Natural Gas

• As the story of abundant natural gas supply continued to provide headlines for the market this report week (Wednesday to Wednesday, April 6-13), spot prices at most market locations in the lower 48 States decreased. Moderate temperatures also likely contributed to the price declines by limiting end-use demand and allowing for replenishment of storage supplies. During the report week, the Henry Hub spot price decreased by 3 cents per million Btu (MMBtu), or less than 1 percent, to $4.14 per MMBtu. Other market prices also decreased by up to 10 cents per MMBtu, with a few exceptions in the U.S. Northeast.
  
• The price of the May futures contract at the New York Mercantile Exchange (NYMEX) at the close of trading on Wednesday, April 13, was $4.141 per MMBtu. During the report week, the near-month contract price varied little, with daily changes never exceeding 10 cents per MMBtu.
  
• During the week ending Friday, April 8, estimated net injections of natural gas into underground storage totaled 28 billion cubic feet (Bcf). Working natural gas in underground storage was 1,607 Bcf, which is 0.6 percent above the 5-year (2006-2010) average.
  
• The natural gas rotary rig count, according to data reported by Baker Hughes Incorporated on April 8, fell by 2 to 889, which was slightly less than 50 percent of the overall rig count of 1,782. This is the first time since 1995 that rigs drilling for natural gas targets have fallen to below 50 percent of the overall rig count.

Moderate weather and continued high domestic production levels weighed on prices this week, leading to declines at most market locations. Price decreases during the report week were generally less than 10 cents per MMBtu, or less than 2 percent, as price increases late in the report week offset a portion of declines that occurred before last weekend. At the Henry Hub, the daily average spot price reached a low point of $4.04 per MMBtu on Monday, April 11, before gaining in the next two trading sessions to close the report week at $4.14, down 3 cents for the week. Other trading locations in the producing region along the Gulf Coast in Louisiana and East Texas generally recorded decreases of less than 10 cents per MMBtu, or between 1 and 2 percent for the week. In the Rockies and Midcontinent, price declines were slightly less and scattered price increases even occurred.

With the continuing transition to spring-like weather, consumption was limited to an average of about 58.2 Bcf per day, according to estimates by BENTEK Energy Services, LLC, which tracks flows on the interstate pipeline grid for indications of changes in supply and demand. Residential and commercial consumption, which is largely related to demand for space heating, decreased approximately 21 percent from the prior report week to an average of 20.4 Bcf per day, as warmer temperatures entered the northern parts of the country, providing a glimpse of what is to come. During the week, U.S. production was only slightly lower than the previous week (a week in which a record high level of output occurred), averaging close to 64 Bcf per day, according to BENTEK.

The largest price decreases during the report week occurred in Northeast markets, where prices responded to lower demand owing to warmer weather in the region. Market prices posted decreases of as much as 10 percent on the week. For delivery in Dracut, Massachusetts, the price at the end of the report week averaged $4.58 per MMBtu, a decrease of 51 cents, or about 10 percent. Daily trading patterns suggest that a much lower price spread between the Northeast and the Henry Hub is developing. For example, the price for deliveries to Transcontinental Gas Pipe Line Zone 6 during the report week averaged 40 cents higher than the price at the Henry Hub, which is substantially less than the $2.81 average during the first three months of the year. The Northeast’s price premium over Gulf of Mexico regional prices typically decreases with the advent of warmer weather because of increased access to pipeline capacity into the region. But the premium may also be changing due to non-weather related conditions such as more supply options for the Northeast, including growing supplies in the Marcellus Shale, access to Rockies supplies, and regasified liquefied natural gas (LNG) from the Canaport LNG terminal in Canada.

At the NYMEX, the price of the May 2011 contract varied very little during the report week, with daily changes in closing prices never exceeding 10 cents per MMBtu. Its price at the close of trading on Wednesday, April 13, was $4.141 per MMBtu, which was less than 1 cent lower than the price at the close of the prior report week. The near-month contract price is now about 3 percent lower than the final expiration price of $4.27 per MMBtu. The 12-month strip, which is the average price of natural gas futures contracts over the next year, ended trading yesterday at $4.55 per MMBtu, which was 1 cent per MMBtu lower than the price of the strip last week.

Working natural gas in storage rose to 1,607 Bcf as of Friday, April 8, according to EIA’s WNGSR (see Storage Figure). After a 28-Bcf net injection, stocks are now just 10 Bcf above the 5-year (2006-2010) average, and 137 Bcf below last year’s level of 1,744 Bcf. This week’s injection is the first of the official injection season, which began April 1 (although a net injection occurred at the end of March). This week’s build is equal to the 5-year average build, but below the 79-Bcf net injection seen for the same week in 2010.

Injections in the Producing Region made up the bulk of this week’s storage build. The Producing Region saw a net increase of 21 Bcf, while the East Region injected 7 Bcf. There was no change week-to-week in the West. Both the East and West Regions are below both their 5-year average and year-ago levels. The Producing Region, with 763 Bcf of working gas in storage, remains above the five-year average and last year’s level for the week.

Temperatures in the lower 48 States during the week ending April 7 were 1.6 degrees warmer than normal and 7.3 degrees cooler than last year. The National Weather Service’s degree-day data show that the temperature in the lower 48 States last week averaged 51.3 degrees, 9.1 degrees warmer than last week (see Temperature Maps and Data). Almost all regions were warmer than normal, with the exception of the South Atlantic and the East South Central, where temperatures were only slightly cooler (less than 1 degree) than normal. The Mountain region was the warmest relative to normal, with temperatures averaging 4.7 degrees warmer than normal.

EIA Forecasts Slower Production Growth in 2011. In EIA’s Short-Term Energy Outlook (STEO), released April 12, 2011, EIA forecasts that natural gas marketed production will increase 2.4 percent in 2011, considerably less than the 4.5 percent growth in 2010. The slower production growth stems from projections of relatively low prices, which lead to reduced drilling activity. The annual average Henry Hub spot price is expected to decline $0.29 per MMBtu in 2011 to $4.10. The latest EIA data for monthly natural gas production already show a decline in production in the lower 48 States for January 2011. Some of this decline is because of “freeze-offs” during the very cold weather that forced some producers to temporarily shut down some production. Although further declines in production are expected from freeze-offs in February, production levels are expected to recover this spring before beginning modest declines that will continue through the year because of a falling gas-directed drilling rig count.

Growing domestic production continues to reduce U.S. reliance on natural gas imports. EIA expects little effect on the U.S. natural gas market from increased demand for liquefied natural gas (LNG) in Japan, where nuclear outages are expected to increase consumption of natural gas as a replacement fuel for electric power generation. Japan is already the largest importer of LNG in the world, with daily imports averaging more than 9 Bcf per day in 2010. EIA now projects U.S. imports of LNG will average 1.05 Bcf per day in 2011, down from 1.18 Bcf per day in 2010.

Total natural gas consumption will rise slightly from 2010 to 2011, according to the EIA forecast. Consumption in the industrial sector rises 3.6 percent to 18.7 Bcf per day in 2011, as the natural gas weighted industrial production index increases 4.3 percent year over year. This growth is only partially offset by forecast declines of 0.7 and 1.7 percent in, respectively, the residential and commercial sectors. (Note, however, that consumption changes relative to 2010 are affected by changes in EIA’s methodology for collecting and reporting natural gas consumption data that were implemented in the middle of 2010 to provide more accurate data on seasonal patterns of natural gas use.)

Natural Gas Rig Count Falls to 889. The natural gas rotary rig count, according to data reported by Baker Hughes Incorporated on April 8, fell by 2 to 889, which was slightly less than 50 percent of the overall rig count of 1,782. This is the first time since 1995 that rigs drilling for natural gas targets have fallen to below 50 percent of the overall rig count. During this time (as recently as four years ago, rigs drilling natural gas prospects accounted for over 80 percent of the rig count). The natural gas rig count has fallen about 9 percent from a high of 973 in April 2010 and by about 3 percent since the beginning of 2011. The large price difference between petroleum liquids and natural gas on an energy-equivalent basis has contributed to this shift towards drilling for liquids rather than for gas.

• The Federal Energy Regulatory Commission (FERC) approved Trunkline Gas Co. LLC’s proposal to allow bidirectional transportation on a portion of its existing South Texas System. Trunkline proposed to modify a 165-mile portion of their South Texas pipeline in order to service liquids-rich gas primarily from the Eagle Ford Shale play. DCP Midstream LLC, a major producer of Eagle Ford shale gas entered into a precedent agreement for 336,000 decatherms per day of capacity of the bidirectional pipeline, according to the FERC Order. The Order further states that the modifications to the pipeline to allow bidirectional flows are minor and “Trunkline contends that it can link the Eagle Ford Shale production area to DCP’s LaGloria and Gulf Plains processing plants and the rest of DCP’s Gulf Coast gathering system.”
  
• On April 12, Transwestern Pipeline Company started annual maintenance at the La Plata Compressor station. The maintenance is expected to impact capacity at the compressor station, located on the San Juan Lateral through April 16. La Plata Compressor station capacity will be reduced from 500,000 MMBtu per day to 0 MMBtu per day. The interconnects affected are: Northwest/Ignacio, Williams/Ignacio, and BP/Florida.

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.