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Natural Gas Weekly Update
Natural Gas Weekly Update Text
Released: January 29, 2009
Next Release: February 5, 2009
Overview (For the Week Ending Wednesday, January 28, 2009)

  • Since Wednesday, January 21, natural gas spot price movements were mixed, with decreases at most markets in the Lower 48 States. Prices at the Henry Hub fell 3 cents per million Btu (MMBtu), or about 1 percent, to $4.84 per MMBtu.

  • At the New York Mercantile Exchange (NYMEX), the futures contract for February delivery at the Henry Hub expired yesterday (January 28) at $4. 476 per MMBtu, declining 30 cents per MMBtu or about 6 percent since last Wednesday, January 21.

  • Natural gas in storage was 2,374 billion cubic feet (Bcf) as of January 23, which is about 1.2 percent above the 5-year average (2004-2008), following an implied net withdrawal of 186 Bcf during the report week.

  • The spot price for West Texas Intermediate (WTI) crude oil decreased 52 cents per barrel since last Wednesday, January 21, to $42.04 per barrel or $7.25 per MMBtu.

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

Despite an arctic blast of frigid temperatures enveloping most of the Lower 48 States, natural gas spot prices generally continued to show considerable weakness, decreasing at most market locations in the Lower 48 States, and posting relatively modest increases at other locations since Wednesday, January 21. Pricing patterns in the Lower 48 States during the past week suggest that natural gas markets are well-supplied to meet consumer demand this winter. Prices fell at most market locations with declines of up to $1.14 per MMBtu, although a number of markets in the Lower 48 States posted modest increases of less than 29 cents per MMBtu. Aside from increased onshore natural gas production this year and plentiful levels of working gas in storage, key factors contributing to the softness of natural gas prices likely included a lower level of industrial demand for natural gas, as a result of the ongoing economic downturn, and relatively low crude oil prices.

On a regional basis, price movements did not exhibit a clear regional pattern. Regions posting declines since last Wednesday included the East Texas, Louisiana, Alabama/Mississippi, Florida, California, Midwest, and Northeast regions. Declines in these regions were generally less than 11 cents per MMBtu since last Wednesday, except for the Florida and Northeast regions, where prices declined $1.14 and $0.41, respectively. Regions with price increases since last Wednesday included the South Texas, West Texas, Midcontinent, Rocky Mountains, and Arizona/Nevada regions. Regional average price increases since last Wednesday were generally less than 12 cents per MMBtu with the exception of the West Texas region, where prices climbed 23 cents per MMBtu over the period.

Prices in the Northeast region exhibited significant variability in trading since last Wednesday, January 21. On average, prices in the Northeast region ranged between a low of $5.55 and a high of $8.17 per MMBtu—an average spread of $2.62 between the high and low prices reported during the week. Price variability during the week was most pronounced at the New York citygate, where prices ranged between an intra-week high of $11.43 per MMBtu reported on Friday, January 23, and an intra-week low of $5.93 per MMBtu on January 22. Elsewhere in the Lower 48 States, excluding the Florida region, price variability was generally much less pronounced with prices trading in a relatively narrow band of less than 12 cents per MMBtu on average.

Natural gas prices are significantly below the levels reported last year at this time. As of January 28, natural gas prices are $1.85 to $4.30 per MMBtu, or 21 to 54 percent, below levels at this time last year at most market locations. At the Henry Hub, prices were $3.03, or 39 percent, below the 2008 level. The year-over-year price declines were even more pronounced in the Rocky Mountains region, where prices were $3.81 per MMBtu below last year’s levels, on average.

Spot Prices

At the NYMEX, the prices for natural gas delivery contracts through January 2010 fell between 15 and 33 cents per MMBtu, or 2 to 7 percent, since Wednesday, January 21. Prices for the 12-month futures strip (February 2009 through January 2010) averaged $5.07 per MMBtu as of Wednesday, January 28, declining by roughly 28 cents per MMBtu, or about 5 percent, on the week.

The February contract for natural gas delivery at the Henry Hub expired in trading on January 28 at $4.476 per MMBtu, declining $1.383 per MMBtu, or nearly 24 percent, during its tenure as the near-month contract. At $6.136 per MMBtu, theFebruary 2009 contract expired $1.04 or 14 percent below the expiry of the January 2008 contract. This marks the lowest level for the price of a near-month contract since the October 2006 contract expired at $4.201 per MMBtu on September 27, 2006, and it was the lowest level for the February 2009 contract since April 29, 2003.

Wellhead Prices Annual Energy Review
More Price Data

Working gas in storage decreased to 2,374 Bcf as of Friday, January 23, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure). The implied net withdrawal of 186 Bcf from working gas was 54 Bcf below last year’s net withdrawal of 240 Bcf for the same report week and 2 Bcf above the 5-year average (2004-2008) net withdrawal of 184 Bcf. Working gas stocks are now 34 Bcf above last year’s level at this time and 29 Bcf above the 5-year average.

Colder-than-normal temperatures in the Lower 48 States likely contributed to the above-average level of net withdrawals from working gas storage. The National Weather Service’s degree-day data (see Temperature Maps and Data) indicate that temperatures in the Lower 48 States during the week were above normal levels and the levels that prevailed last year. On average, heating degree-days (HDD) were 11 percent above normal in the Lower 48 States. The pattern of colder-than-normal temperatures prevailed in the New England, Middle Atlantic, East North Central, South Atlantic, and East South Central Census Divisions, where HDD ranged between 23 and 40 percent above normal. In the Census Divisions west of the Mississippi, temperatures were warmer than normal. HDD in the Mountain and Pacific Census Divisions were 26 and 43 percent below normal, respectively, and in the West South Central and West North Central Census Divisions, reported HDD were between 4 and 12 percent below normal.

Storage Table

More Storage Data
Other Market Trends

EIA Releases Report on Impact of the 2008 Hurricanes on the Natural Gas Industry. According to a report released by the Energy Information Administration (EIA) on January 26, Impact of the 2008 Hurricanes on the Natural Gas Industry, natural gas market conditions after the 2008 hurricanes did not match those observed in the aftermath of the 2005 hurricanes. This outcome was the result of less powerful hurricanes in 2008 in terms of wind and storm surge compared with those in 2005. Lack of the supply-and-demand tightness observed in 2005 and the increase in onshore production in 2008 limited the shock to the market as production in the Federal offshore was reduced. Overall, the 2008 Atlantic hurricane season was the fourth most active one since 1944 and the most active since 2005. The damage caused by the storms was significant, with most of the production facilities in the Gulf of Mexico going offline for at least a few days following Hurricanes Gustav and Ike. As a result of the production disruptions, average daily natural gas production in the Federal Gulf of Mexico fell by 68 percent in September 2008 compared with levels in the previous month and 70 percent compared with those in September 2007. As of December 2008, companies continued to repair damage that the hurricanes caused to their facilities, particularly the subsea lines that transport wellhead natural gas from production platforms to processing plants. While most of these facilities are operational, a few pipeline segments and platforms are still offline. Some reports indicate that several of the platforms likely will stay offline through mid-2009. Most of the processing plants affected by the hurricanes did not sustain major internal damage. However at its peak, more than 16 Bcf per day or 24 percent of total processing capacity was taken offline. The plants that cited external factors as reasons for not operating have recovered, and all of them currently operate although some at reduced levels. Three plants are still shutdown as a result of extensive internal damage and are not expected to be back online until early 2009.

EIA Releases Electric Power Annual: The Energy Information Administration released its 2007 Electric Power Annual on January 21, 2009. The report found that power generation and power sales reached record levels in 2007. Net generation of electric power increased by 2.3 percent, rising to 4,157 million megawatthours (MWh) from 4,065 million MWh in 2006, and retail sales rose by 2.6 percent to 3,765 million MWh in 2007. Additionally, EIA found that the increase in power generation was achieved primarily through increased performance of existing coal-fired, natural gas-fired, and nuclear capacity. The share of natural gas-fired generation increased from 20.1 percent in 2006 to 21.6 percent in 2007, as the share of coal continued to decline, falling to 48.5 percent of net generation in 2007. Natural gas generation increased 9.8 percent from 816 MWh in 2006 to 897 MWh in 2007. Natural gas, for 2007 and 2006, represented the second-largest share of total net generation after coal, the report found. For these 2 consecutive years, natural gas surpassed nuclear power, which historically has had the second largest share of total net generation. Coal’s share of generation continued to fall in 2007, and the decline is attributable to increases in the total share of net power generation fueled by natural gas, nuclear, and renewables. According to the report, natural gas-fired generation made up 392,876 MW or 39.5 percent of total net summer generating capacity. The report also found that new gas-fired, combined-cycle power plants can generate power more efficiently than older power plants, but high natural gas prices can put downward pressure on full utilization of these plants.

Natural Gas Transportation Update

  • The winter continues to bring its challenges to the pipeline companies in a variety of ways. This week brought ice storms to several States in the South, and the resulting electrical power outages are affecting at least one pipeline company’s operations. On Wednesday, January 28, Texas Eastern Transmission Corporation reported the loss of commercial power to some compressor stations in Arkansas and Missouri. According to the company, the Fagus and Egypt stations in Arkansas are not fully operational. The pipeline company said that it was currently evaluating the capacity impact and its ability to meet scheduled quantities in both States.

  • In the U.S. Southeast, Southern Natural Gas Company (SNG) on Wednesday implemented restrictions on imbalances between scheduled flows and actual pulls from clients, saying significantly colder weather is expected through Saturday in its service area. No penalty will apply to short imbalances up to 2 percent or 200 decatherms, according to SNG. Nonetheless, tiered penalties will be in place for larger imbalances. SNG expects its storage withdrawal capability will be utilized fully during today’s gas day. It also said that based on supply patterns from recent days, it may be required to allocate receipt points west of Enterprise Compressor Station in southern Mississippi.

  • Transcontinental Gas Pipeline Corporation on Tuesday, January 27, said it had experienced a mechanical failure of a compressor unit at Station 167 in South Hill, Virginia. The pipeline said repairs could take several weeks, but that no impact to firm capacity is anticipated. The station is on Transco’s South Virginia Lateral. Delivery locations downstream of the station may experience lower-than-normal pipeline pressure.

  • Sabine Pipe Line Corporation on Monday, January 26, ended a force majeure at the Henry Hub North Booster Station. Sabine Pipe Line first declared the force majeure on January 21 because of reduced throughput capabilities resulting from necessary repairs to a compression unit. Transportation capacity at the station was reduced by 20 percent, but firm transportation services were not affected.

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.