Natural Gas Weekly Update

Natural Gas Weekly Update Text
Released: September 2, 2010 at 2:00 P.M.
Next Release: Thursday, September 9, 2010
Overview (For the Week Ending Wednesday, September 1, 2010)

  • Since Wednesday, August 25, natural gas spot prices fell at most market locations in the lower 48 States, although prices generally rose in the Northeast and Rocky Mountain areas. The Henry Hub spot price fell on the week from $3.99 per million Btu (MMBtu) to $3.73 per MMBtu, its lowest value since April 1, 2010.

  • At the New York Mercantile Exchange, the October 2010 natural gas futures contract fell about 3 percent from $3.896 per MMBtu to $3.762 per MMBtu. During the report week, the September 2010 natural gas futures contract expired at $3.651, having lost about $1.176 per MMBtu during its tenure as the near-month contract.

  • Working natural gas in storage increased to 3,106 billion cubic feet (Bcf) as of Friday, August 27, according to the Energy Information Administration’s (EIA) Weekly Natural Gas Storage Report. This represents an implied net injection of 54 Bcf.

  • The West Texas Intermediate crude oil spot price rose from $72.07 per barrel, or $12.43 per MMBtu, to $73.97 per barrel, or $12.75 per MMBtu.

  • The natural gas rotary rig count, as reported by Baker Hughes Incorporated, fell by 12 from 985 to 973 as of August 27. Total rigs, including oil and natural gas, rose by 5 to 1,656, as an increase in onshore oil rigs offset the decline in natural gas rigs.

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

Natural gas prices fell at most market locations across the lower 48 States, with several exceptions. On Wednesday, September 1, the Henry Hub price, falling almost 7 percent, reached its lowest level since April 1, 2010, at $3.73 per MMBtu. Temperatures across the country were relatively mild, although mean temperatures reached the 80s, notably in areas in Florida, Louisiana, and Texas; near the end of the week, temperatures were in the upper 70s in many parts of the Northeast. The weather was milder than the previous week, possibly contributing to a drop in prices in much of the country. Demand for natural gas for electric power generation in the United States as a whole, according to BENTEK Energy estimates, fell about 9 percent from the previous week, although it remained about 8 percent higher than the same time last year. The largest price decline occurred at the Agua Dulce trading point in South Texas, where prices fell from $4.02 per MMBtu to $3.72 per MMBtu.

In the Northeast, most prices hit a low point in intraweek trading on Friday, before rebounding later in the week. According to BENTEK Energy estimates, power burn in the Northeast spiked near the end of the report week, rising above the 5-year maximum for the time of year, to about 8 Bcf per day. Warm temperatures near the end of the week likely contributed to the end-of-week price increases and the spike in natural gas used for power generation in the Northeast. Additionally, transmission issues affecting imports of electricity from Canada also likely led to price increases in the Northeast. Overall during the week, net price changes in the Northeast were mixed, but prices increased from Friday, August 27, to Wednesday, September 1, at all trading points. At Transcontinental Pipeline’s Zone 6 trading point for delivery into New York City, prices hit a weekly low of $4.07 per MMBtu on Friday, before ending the week at $4.23 per MMBtu. Despite intraweek movements, the Transco Zone 6 price began and ended the week at $4.23 per MMBtu.

Natural gas prices increased at all but three trading points in the Rocky Mountains. At the Northwest Pipeline’s trading point south of Green River, prices rose 34 cents during the report week, with a large jump in trading on Wednesday, to end the week at $3.19 per MMBtu. The 34-cent increase that occurred at this trading point was the largest in the lower 48 States. Most Rockies prices jumped from Tuesday to Wednesday, possibly because warm weather near the end of the week in California boosted demand for Rockies gas, according to trade press reports.

Overall, natural gas demand fell during the week, largely due to the 9 percent drop in natural gas consumption for power generation. Industrial demand fell less than one-half of 1 percent, according to estimates by BENTEK Energy, and residential rose about 3 percent. Supply was down about 1 percent week over week, as production and Canadian imports fell slightly, and LNG sendout fell almost 20 percent. LNG sendout averaged about 659 MMcf per day during the week, about 37 percent below the level for the same week last year.

Spot Prices

The October 2010 futures contract lost about 3 percent during the week, falling from $3.896 per MMBtu to $3.762 per MMBtu. Also, the September contract expired on Friday, August 27, at $3.651 per MMBtu, having lost about 24 percent of its value during its tenure as the near-month contract. The 12-month strip (the average of the 12 contracts between October 2010 and September 2011) changed very little during the week from $4.433 to $4.436. The winter heating strip (the average of the five contracts from November 2010-March 2011) also posted little net change over the report week, beginning the week at $4.432 and ending at $4.431.

Wellhead Prices Annual Energy Review
More Price Data

Working natural gas in storage increased to 3,106 Bcf as of Friday, August 27, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure). The implied net injection was 54 Bcf, compared with last year’s net injection of 64 Bcf and the 5-year average of 62 Bcf for the report week. Working gas inventories are currently 208 Bcf below year-ago levels and 169 Bcf above the 5-year average level. Working gas in storage has exceeded the 5-year average for this time of year in each of the three storage regions since March 26, 2010, or the last 23 weeks.

While injections into working gas stocks during the report week remained below average, the pace of the fill increased considerably during this week. The 54 Bcf injection this week was greater than injections over the past several weeks. Injections into working gas stocks have fallen short of the 5-year average for 11 consecutive weeks, as significantly warmer-than-normal temperatures throughout the summer have continued to drive declines in the surplus of working gas stocks relative to the 5-year average. Since May 6, cumulative cooling degree-days have exceeded normal levels by about 25 percent, outstripping normal levels during each week. These warmer than normal temperatures resulted in increased electric generation demand for natural gas, contributing declines in the surplus relative to the 5-year average. However, injections into working gas storage increased somewhat this week with temperatures moderating at most market locations in the lower 48 States. Over the last 5 weeks, net injections into working gas storage averaged about 32 Bcf during each week.

Temperatures remained warmer than normal in most of the Census Divisions in the lower 48 States during the week ending August 26, but moderated considerably from recent high levels. Based on the National Weather Service’s degree-day data, temperatures in the lower 48 States during the week ending August 26 were, on average, about 75.1 degrees, about 2 degrees warmer than normal and 1.4 degrees warmer than last year at this time (see Temperature Maps and Data). During the storage report week, the New England and Middle Atlantic were the only Census Divisions reporting cooler-than-normal temperatures in the lower 48 States. Temperatures in New England averaged nearly 3 percent below normal levels, and temperatures in the Middle Atlantic were slightly below normal. On the week, temperatures in the lower 48 States fell nearly 2 degrees, or about 2 percent, on average from the previous week’s level.

Storage Table

More Storage Data
Other Market Trends

Hurricane Earl Moving Toward East Coast. According to the National Oceanic and Atmospheric Association’s National Hurricane Center (NHC), Hurricane Earl was about 410 miles south of Cape Hatteras, North Carolina, as of 5:00 a.m. September 2. The storm, which is currently a Category 4, has strengthened some, but is expected to gradually weaken later today. Some key facts about Earl, according to the NHC and a report released by EIA:

  • Many areas along the East Coast are currently under hurricane watch or warning. At 2 a.m. Friday, Earl is expected to bring hurricane conditions to areas along the coast of North Carolina up to the Virginia border. Earl will be a major hurricane as it passes by North Carolina.

  • Hurricane-force winds extend 90 miles from the center of the storm and tropical-storm-force winds extend outward up to 230 miles.

  • Some 1.1 million barrels per day of operable refinery capacity (about 7 percent of the U.S.’s total refinery capacity) lie within the area likely to be affected. The majority of capacity in the affected area is near Philadelphia, where four refineries represent capacity of 858,000 barrels per day.

  • There are two LNG terminals off the coast of Massachusetts, Northeast Gateway Deepwater Port and Neptune LNG, as well as the onshore Distrigas of Massachusetts LNG terminal. The potential impact of Earl on the LNG terminals is unclear.

  • Strong winds and a potential storm surge could affect electric power infrastructure in areas along the East Coast.

  • Another storm, Tropical Storm Fiona, is currently southeast of Earl in the Atlantic, and a tropical storm watch has been issued for Bermuda.

  • Tropical Storm Gaston is currently moving over the central tropical Atlantic, with no recent change in strength. Gaston is southeast of Fiona, and has no associated tropical storm watches or warnings.

More information and updates about Hurricane Earl and Tropical Storms Fiona and Gaston are available from the NHC at and from EIA at

Interactive Gulf of Mexico Fact Sheet Details Hurricanes, Production, and Infrastructure. EIA on September 1 released a special report detailing energy production and infrastructure in the Gulf of Mexico (GOM). The report includes an interactive map showing refineries, power plants, pipelines, LNG terminals, processing plants, and other forms of infrastructure in the offshore Gulf, and onshore in the States surrounding the Gulf. The GOM area, offshore and onshore, is a key region for energy infrastructure and production; its offshore oil production accounts for 30 percent of U.S. crude oil production and its offshore natural gas production makes up about 13 percent of U.S. natural gas production. Additionally, the report shows that 82 of the country’s 493 natural gas processing plants are located in the Gulf of Mexico. The GOM processing plants have a combined capacity of 23 Bcf per day, about 30 percent of the U.S.’s total capacity of 77.5 Bcf per day. The average GOM processing plant size is 280 MMcf per day, compared with 157 in the rest of the country. The new report also describes the hurricane outlook for the season, and provides information about other developing storms that could affect the Gulf.

Natural Gas Marketed Production Drops almost 1 Bcf per day in June. EIA on August 30 released the August 2010 Natural Gas Monthly, which includes data through June 2010. According to the NGM, natural gas marketed production dropped from about 62 Bcf per day in May to 61.2 Bcf per day in June, the first monthly decline of 2010. June production, however, was still slightly higher than production in the same month of 2009. Wellhead prices rose slightly, from $4.15 per MMBtu in May to $4.37 per MMBtu in June. Working natural gas in underground storage was 2,741 Bcf, representing a net increase of 320 Bcf from the previous month. Compared with last year’s June level, June 2010 storage is slightly lower, possibly due to a warmer-than-normal summer. Consumption of natural gas for electric power generation was at its highest recorded level for June (for the 10 years for which data are available), 23.6 Bcf per day, 9 percent higher than June of last year. The increase in electric power consumption largely drove the month-over-month increase in delivered volumes, as residential, commercial, and industrial volumes all fell or remained flat. Delivered volumes increased about 8 percent year-over-year, from 46.1 Bcf per day in June 2009 to 49.7 Bcf per day in June 2010.

DOE Researchers Develop New Methane Hydrate Technology. Researchers at DOE’s National Energy Technology Laboratory (NETL) announced on August 25 that they have developed a method to quickly produce synthetic methane hydrates, which are ice-like with high concentrations of methane, the principle component of natural gas. Methane hydrates are very dense: about one cubic meter of solid hydrate can produce 164 cubic meters of methane. The NETL researchers developed a method to rapidly and continuously form synthetic hydrates. Previous methods could take hours or days. Currently, natural gas sometimes is cooled and liquefied and converted to compressed or liquefied natural gas to reduce volume; this method can use large amounts of energy and increase the cost of natural gas for the end-user. According to the NETL, the new method to form methane hydrates could represent a more efficient way to reduce the volume of natural gas for transport or storage, and could significantly reduce the production, transportation, and storage costs associated with the current methods for compressing natural gas. Though methane hydrates are less dense than liquefied or compressed natural gas, producing hydrates would require less refrigeration, pressure, and time. More information about the NETL’s new technology is available here:

State Department Hosts First Global Shale Gas Initiative Conference. On August 23 and 24, the U.S. Department of State hosted representatives from 17 countries in an effort to foster worldwide development of shale gas. EIA’s Deputy Administrator Howard Gruenspecht made a presentation at the conference discussing the development of shale gas in the United States. Development and success of production in the Barnett Shale in Texas led U.S. producers to explore other shale formations in the United States. Specifically, in the Haynesville Shale in Louisiana, the Marcellus Shale in Pennsylvania, and the Eagle Ford Shale in Texas, drilling activity has risen over the past several years. Over the long term, according to Gruenspecht’s presentation, increased shale gas production along with Alaska natural gas production are projected to offset other declines in supply. The conference was part of the State Department’s Global Shale Gas Initiative (GSGI), which was launched in April 2010 to help countries seeking to exploit unconventional natural gas resources. The GSGI focuses on helping countries identify these resources and develop them safely. More information about the GSGI is available here:; Gruenspecht’s presentation is available here:

Natural Gas Transportation Update

  • Rockies Express Pipeline, LLC, on Wednesday, September 1, experienced a valve failure at its compressor station in Steele City, Nebraska. The pipeline company said that it expected to operate the segment of its pipeline in Gage County, Nebraska, at a capacity of 1.5 billion cubic feet (Bcf) per day, affecting approximately 330 million cubic feet (MMcf) per day of flow eastbound. The temporary reduction in capacity was expected to continue until today, September 2.

  • Although Tennessee Gas Pipeline Company has lifted last weekend’s system-wide notice requiring shippers to balance supplies with nominations, the pipeline company is continuing to restrict operating conditions in its zones in the Northeast (zones 5 and 6). Citing limited operational flexibility and mild weather, Tennessee is requiring shippers to maintain an actual daily flow rate not exceeding 2 percent of scheduled quantities, or 500 decatherms, whichever is greater, for overdeliveries into the system and undertakes from the system. Separately, Tennessee said that manpower and resources were mobilized yesterday, September 1, to Station 325 (Liberty, New Jersey) for repair work, which will result in the loss of about 50 MMcf per day of capacity at the station.

  • In the West, operators of pipeline and storage fields are responding to unusually high levels of storage inventories for this point in the injection season. The high levels of storage are reducing flexibility to accept supplies for storage, as well as for operations of associated pipeline system. Effective with Friday's (August 27) gas day until further notice, Questar Pipeline Company said it is “requiring shippers and point operators to have production volumes aligned with scheduled nominations." Questar said the notice is due to high inventory in its Clay Basin storage balancing account and current operational conditions resulting in minimal linepack available for balancing. Separately, Colorado Interstate Gas Company (CIG) declared a Strained Operating Condition for the transmission system to be effective September 1. Because of high inventories, CIG said its ability to absorb imbalances is extremely limited.

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.