• Colder weather moved into major population centers this report week, increasing demand related to space heating for much of the country. Prices moved higher at all trading locations in the lower 48 States, with the biggest increases occurring in the Northeast. During the report week, the Henry Hub spot price increased $0.33 to $4.18 per million Btu (MMBtu).



• At the New York Mercantile Exchange (NYMEX), futures prices also increased significantly as the weather outlook suggested higher consumption for the remaining days of March. The futures contract for April delivery climbed $0.40 on the week to $4.34 per MMBtu. Upward pressure on prices at the NYMEX also appears related to concerns over events in Japan that could affect energy markets. Japan, the world’s largest liquefied natural gas (LNG) consumer, is expected to boost consumption of LNG as a fuel for power generation following the nuclear crisis in the country. However, it should be noted that LNG demand in the United States has fallen significantly in recent years as a result of higher U.S. production.



• As of Friday, March 18, working gas in underground storage was 1,612 billion cubic feet (Bcf), which is 2.2 percent above the 5-year (2006-2010) average, according to the Energy Information Administration’s Weekly Natural Gas Storage Report (WNGSR). The implied net withdrawal from storage was 6 Bcf.



• The number of rigs drilling for natural gas continued to decline, although the decrease slowed from the prior week. According to data reported by Baker Hughes Incorporated, the number of active rigs fell by 7 to 875 for the week ending March 18. The natural gas rig count is at its lowest level in more than a year (see Other Market Trends below).

Cold, winter-like temperatures and even a large snowstorm in the Northeast are characterizing the opening days of spring, resulting in higher natural gas consumption related to space-heating. Overall U.S. consumption increased 9.6 Bcf per day, or 6.1 percent, from the beginning of the report week (Thursday, March 17) through yesterday (Wednesday, March 23), according to BENTEK Energy Services, LLC. In the residential and commercial sectors, consumption grew 11.1 Bcf per day, or 15.2 percent, to 33.8 Bcf per day yesterday. As often occurs during the winter, the cold weather this week translated into higher prices for natural gas on the wholesale spot markets. The Henry Hub price averaged $4.18 per MMBtu yesterday, which was 8.6 percent higher than the price of $3.85 at the beginning of the report week. The Henry Hub spot price was either unchanged or increased in each of the 5 trading days this report week. The report week began with price increases following EIA’s release of the March 17 edition of the WNGSR, which showed withdrawals from storage occurring more rapidly than expected by analysts. Toward the end of the report week, the weather outlook appeared to drive prices higher. At markets in the producing region surrounding the Gulf of Mexico, price increases during the week were generally between $0.30 and $0.45 per MMBtu. The price at the Houston Ship Channel in East Texas increased by $0.36 on the week to $4.16 per MMBtu, while the price at Transcontinental Gas Pipe Line (Transco) Station 65 in Louisiana increased by $0.34 to $4.20 per MMBtu.

U.S. domestic production continues to create new records as volumes from shale formations increase. Supplies from unconventional gas fields such as the Marcellus Shale in the Northeast/Appalachia region and the Haynesville Shale in Louisiana helped boost domestic production above 63 Bcf per day on average during the report week, and as high as 63.3 Bcf on Sunday, March 20, which is the highest production level ever reported by BENTEK in its daily production statistics (See Other Market Trends below). U.S. domestic production is 5.9 percent higher compared with this time last year, according to BENTEK statistics. Domestic production has not declined substantially despite reductions in overall rig counts compared with this time last year, likely in part because of greater efficiencies in the drilling process and the high initial production levels at shale fields. However, it should be noted that there is often a delayed effect on production output from changes in drilling trends.

In the Northeast, prices increased by as much as 35 percent on the week, as temperatures in the region turned winter-like. Many points in the Northeast region posted increases of more than $1.00 per MMBtu on the week. For delivery in Zone 6 into New York off Transco, the price increased by $1.22 per MMBtu to an average of $5.48 by the end of the report week. This price was the highest at this market center in about 3 weeks, and $1.30 higher than the Henry Hub price yesterday. The Northeast’s price premium over Gulf of Mexico regional prices typically widens significantly with the advent of colder weather because of a lack of alternatives for transportation of supplies into the region during periods of high demand.

Prices at the majority of markets west of the Mississippi River increased over 10 percent. The price at the Opal, Wyoming, trading point increased by $0.39 on the week to $4.04 per MMBtu. Consistent with other regional trends, this price was the highest average price at this market center for several weeks (February 9). Although prices in the Rocky Mountain region are generally the lowest in the country, discounts of Rockies prices to other markets have grown less in the past two years. To date in 2011, the average difference between the Opal price and the Henry Hub price is $0.14 per MMBtu. During the same time periods in 2010 and 2009, the average differential was, respectively, $0.33 and $1.50 per MMBtu. The change in the price relationship likely is resulting from increased pipeline capacity from pipeline projects such as Rockies Express Pipeline and the new Bison Pipeline, which have integrated Rockies markets with other regions.

Imports of natural gas continue to flow into the United States at much lower levels than in previous years, likely as a result of higher U.S. domestic production. During the report week, net Canadian imports averaged 5.5 Bcf per day, which is 8.0 percent lower than the same week in 2010. The pace of deliveries of U.S. LNG imports in recent weeks has also decreased considerably in comparison with this time last year. Sendout from U.S. LNG import terminals averaged about 0.9 Bcf per day during the report week, or 11.8 percent lower than the same week in 2010. The lower level of U.S. LNG imports this week is the result of much higher prices being available to suppliers of LNG in regional markets in Europe and Asia. Following the nuclear crisis in Japan (which will likely result in higher demand for LNG) and conflict in North Africa, the difference in prices in the United States and other world markets has increased even more. Currently, however, the extent to which this will affect current deliveries of LNG to the United States is unclear.

At the NYMEX, the price of the near-month contract (for April delivery) increased $0.40 during the report week to $4.34 per MMBtu. The increase was attributable chiefly to colder temperatures moving into consuming regions of the country. Upward price pressure also appears related to concerns about the stability of international supplies of LNG, although domestically these supplies make up meet a very small portion of overall U.S. consumption. The April 2011 contract is currently priced about 12 percent higher than the expiration price of $3.84 per MMBtu for 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 $4.72 per MMBtu, an increase of about $0.32, or 7.3 percent, since last Wednesday.

Working natural gas in storage fell to 1,612 Bcf as of Friday, March 18, according to EIA’s WNGSR (see Storage Figure). After a 6-Bcf draw, stocks are now 34 Bcf above the 5-year average but 12 Bcf below last year. The draw was less than the 5-year average draw of 17 Bcf. Last year, however, saw a stock build of 6 Bcf during the same week. This marked the beginning of last year’s injections, which continued until November. Typically, we can expect to see one more week of draws before injections begin.

Once again, the drawdown last week was centered on the East Region where 22 Bcf was withdrawn. The Producing and West Regions injected 15 Bcf and 1 Bcf respectively. It is normal for the Producing Region to see consistent stock builds in March while the East Region will usually continue to draw into the start of April, especially if cold weather continues. Regional weather patterns and changing production and consumption dynamics can easily disrupt these historical averages, however.

Temperatures in the lower 48 States during the week ending March 17 were about 3 degrees warmer than normal but about 1 degree colder than last year. The National Weather Service’s degree-day data show that the temperature in the lower 48 States last week averaged 47.0 degrees (See Temperature Maps and Data). Regional differences were significant with the East North Central Region a full 7 degrees cooler than last year. That amounts to a 38 percent increase in heating degree-days in a major gas-consuming region, and contributes to an 8 percent increase in heating degree-days in the lower 48 States.

Haynesville Shale Production Surpasses Barnett. Citing data from BENTEK Energy, EIA reported on Friday, March 18, that natural gas production in Louisiana’s Haynesville Shale has surpassed that of the Barnett Shale in Texas. For the past decade, the Barnett has been the nation’s largest shale producer. EIA noted that Haynesville producers were able to take advantage of technological advances in drilling. Additionally, pipeline infrastructure has expanded recently to accommodate Haynesville production. More information is available here: http://www.eia.doe.gov/todayinenergy/detail.cfm?id=570#

Natural Gas Rig Count Falls to 875. The natural gas rotary rig count, according to data reported by Baker Hughes Incorporated on March 18, fell for the third week in a row to 875. The rig count has fallen by about 5 percent since the beginning of 2011, and rigs are at their lowest level in more than a year. As the overall natural gas rig count has fallen, strength in production has continued, likely the result of more efficient drilling techniques and drilling in shale formations. The horizontal rig count (which includes both oil and natural gas) rose this week to 986, an increase of 5 from the previous week. Horizontal rigs, which are often found in shale formations, are at their highest level in the 20 years for which Baker Hughes has data. Vertical rigs (also including both oil and natural gas) dropped this week by 6 to 503.

• In anticipation of colder-than-normal weather in the Northeast, several pipelines this week issued imbalance warnings. Texas Eastern Transmission Corporation issued a notice effective March 24 through March 31, requiring all delivery point operators in Market Area Zone (M3) “to keep actual daily takes out of the system less than or equal to scheduled quantities regardless of their cumulative imbalance position” and receipt point operators in Market Area Zone (M3) “to keep actual daily receipts into the system greater than or equal to scheduled quantities regardless of their cumulative imbalance position.” Additionally, Texas Eastern is requiring all power plant operators in Market Area Zone (M3) to provide information on the hourly consumption profile of directly connected power generation facilities.



• Similarly, Algonquin Gas Transmission Company issued a notice effective March 23 through March 31 requiring all shippers and point operators to “carefully review demands for gas and schedule gas consistent with daily needs and to tender and receive gas consistent with confirmed nominations.” Algonquin is requiring that all receipt point operators keep actual daily receipts into the system greater than or equal to scheduled quantities regardless of their cumulative imbalance position. Algonquin has also required all power plant operators to provide information on the hourly consumption profile of directly connected power generation facilities.



• Questar Pipeline Company has a reservoir test scheduled April 7 through April 20 at their Clay Basin, Utah, facility. An operational flow order issued March 22 by Questar stated that during the testing period, they will be unable to inject or withdraw for its Clay Basin balancing account and will not be able to accept any imbalance payback nominations to or from the pipeline for gas during the testing period. Additionally, Questar is requiring shippers and point operators to align nominated and actual volumes.

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.