Natural Gas Weekly Update

Natural Gas Weekly Update Text
Released: March 17, 2011 at 2:00 P.M.
Next Release: Thursday, March 24, 2011
Overview (For the Week Ending Wednesday, March 16, 2011)

  • With imports (particularly from outside North America) becoming less significant to U.S. natural gas markets, spot natural gas prices this report week appeared largely unaffected by international events that have had large impacts on other energy commodities. As weather turned spring-like in many parts of the country and storage withdrawals continued to slow dramatically, the Henry Hub spot price increased just $0.04 to $3.85 per million Btu (MMBtu).

  • At the New York Mercantile Exchange (NYMEX), futures prices increased slightly for delivery in the near-term. The futures contract for April delivery increased by less than 1 cent per MMBtu on the week to $3.94 per MMBtu. Changes in contract prices with delivery in later months and years moved progressively higher through the forward curve, however, likely in part as a result of concerns over the longer-term implications of the current crisis at Japan’s nuclear plants (See Other Market Trends below).

  • As of Friday, March 11, working gas in underground storage was 1,618 billion cubic feet (Bcf), which is 1.4 percent above the 5-year (2006-2010) average.

  • The natural gas rotary rig count fell 17 to 882 as of March 11, according to data released by Baker Hughes Incorporated (See Other Market Trends below). This is the lowest count in over a year, possibly signaling less natural gas drilling in response to falling natural gas prices.

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

As temperatures continued to warm in the lower 48 States this report week (March 9-16), changes in wholesale market prices were mixed, but in general quite minimal. With natural gas imports becoming less important to U.S. gas supply, events in Japan and continuing unrest in North Africa appear to have had little impact on the spot natural gas market to date. The Henry Hub price increased on the week by $0.04 per MMBtu, or about 1 percent, while prices at other markets in the Gulf of Mexico Producing region also moved higher in very small increments of less than a dime. Prices at several markets in the Northeast decreased by up to $0.25 per MMBtu, while in the Rockies and California prices were mostly flat relative to the prior week.

According to BENTEK Energy Services, LLC, U.S. production during the report week, which averaged close to 63 Bcf per day, was nearly 5.2 percent higher than the comparable period last year. At least in part because of the strength in current domestic supplies, prices are below their levels this time last year. On March 16, 2010, the Henry Hub price was $4.38 per MMBtu, or about 13.8 percent above yesterday’s average of $3.85. Compared with the prior week, U.S. natural gas consumption decreased about 3.6 percent to an average of about 69.4 Bcf per day, according to BENTEK. The spring-like weather in many regions of the country was reflected in lower demand in the residential and commercial sectors, which together decreased their consumption by 7.3 percent during the week.

While prices in the Northeast continued to be the highest in the country at above $4 per MMBtu at most locations, this region saw the largest declines in the lower 48 States during the report week. Several market centers in the Northeast region posted declines of close to $0.25 per MMBtu, or close to 4 percent on the week. For delivery in Zone 6 (New York) off Transcontinental Gas Pipe Line, the price yesterday (March 16) averaged $4.26 per MMBtu, which was $0.18 less than the price the previous Wednesday. During the report week, the Transco Zone 6 price was, on average, about $0.54 per MMBtu higher than the Henry Hub’s, significantly lower than the average differential of $3.51 to date in 2011. The closely-watched difference in the Northeast price over Gulf of Mexico regional prices tends to fluctuate severely depending on local weather conditions. Interstate pipelines have limited flexibility to transport non-firm supplies between the two markets during times of colder weather, causing differences in local supply and demand conditions to develop. The lower premium during this report week was the result of temperatures in the Northeast rising to above-normal levels, limiting heating demand and allowing greater flexibility on the region’s transportation system.

Further to the west, week-to-week changes in prices were minimal in the Rockies and California markets. At Rockies trading locations, price changes were generally less than 1 percent. The price for supplies on Kern River Pipeline in Utah (for delivery into California) was flat in comparison with the previous week at $3.64 per MMBtu. Yesterday’s price of $3.63 per MMBtu for natural gas off of the Colorado Interstate Pipeline represented a decrease of a penny per MMBtu on the week.

U.S. imports of natural gas, including liquefied natural gas (LNG), were significantly lower during the report week in comparison with this time last year. According to BENTEK, which monitors flows on the continental pipeline network, U.S imports from Canada during the report week were 6.0 percent lower than the prior year at about 5.8 Bcf per day. LNG imports (as measured by sendout from regasification terminals), which averaged less than 1 Bcf per day the prior week, were 19.3 percent lower in comparison with the previous year.

Spot Prices

At the NYMEX, the price of the near-month contract (for April delivery) increased less than 1 cent per MMBtu during the report week to $3.938 per MMBtu. With weather forecasts for much of the country indicating continuing moderate temperatures amid a strong domestic supply outlook, prices for contracts with deliveries in the near-term fluctuated very little during the week. 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 $4.401 per MMBtu, an increase of about $0.06 per MMBtu, or 1.4 percent, since last Wednesday. However, prices for delivery in later years rose during the trading week, possibly as a result of a perception of future impacts to the U.S. supply and demand balance from the situation with Japan’s nuclear power plants. For example, the NYMEX contract for April 2015 delivery rose $0.22 per MMBtu on the week to $6.08.

Wellhead Prices
Annual Energy Review
More Price Data

Working natural gas in storage fell to 1,618 Bcf as of Friday, March 11, according to EIA’s WNGSR (see Storage Figure). The 56 Bcf draw was nearly equal to the 5-year average draw for the week of 58 Bcf but larger than last year’s draw of 25 Bcf. Stocks were still 1 Bcf above last year’s level and 23 Bcf above the 5-year average of 1,760 Bcf.

Virtually the entire drawdown last week occurred in the East Region where 51 Bcf was withdrawn. The Producing and West Regions drew 3 Bcf and 2 Bcf respectively. Typically, the Producing Region will begin seeing consistent stock builds starting next week while the East and West Regions will continue to draw later into March. 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 10 were just 1 degree warmer than normal and almost equal to last year. The National Weather Service’s degree-day data show that the temperature in the lower 48 States last week averaged 43.0 degrees (See Temperature Maps and Data). Despite less than a degree of difference overall between last week’s average and the previous year, regional differences were significant. The Midwest and the Northeast were considerably colder than last year while the regions in the South and West were mostly warmer.

Storage Table

More Storage Data
Other Market Trends

Earthquake and Tsunami Could Increase Japan’s Need for LNG. The March 11 earthquake and resulting tsunami in Japan damaged generation capacity at four nuclear power plants. Total capacity at the affected plants was 12 megawatts (MW) and about half of that capacity was down for maintenance at the time of the earthquakes. According to some industry estimates, Japan’s use of fuel oil and natural gas could increase by up to 238,000 barrels per day and 1.2 Bcf per day, respectively. In 2010, Japan, which is the world’s largest importer of LNG, imported 3.3 trillion cubic feet (Tcf), according to information reported by EIA in a Country Analysis Brief. A number of LNG-exporting countries have pledged to increase supplies of LNG to Japan, including Russia, Qatar, and Indonesia according to BENTEK and trade press reports. Two of Japan’s 40 LNG terminals were affected by the earthquake and tsunami, including the Shinminato LNG Terminal and the Hachinohe LNG Terminal, located on the east coast of Japan. The U.S. Department of Energy (DOE) has maintained contact with Japan in response to the aftermath of the earthquake and tsunami and has provided assistance. More information about the DOE’s efforts is available here: and the Country Analysis Brief on Japan is available here:

U.S. Reliance on Foreign Sources of Natural Gas Lessens as Imports Continue to Fall in 2010. Increased domestic natural gas production is resulting in lower natural gas imports, both in imports by pipeline from Canada and from overseas sources of LNG. According to the February edition of the EIA’s Natural Gas Monthly, net imports to the United States decreased 117.8 Bcf to 2,561.2 Bcf in 2010, which marks the lowest level of net imports since 1994. Decreases in both pipeline imports from Canada and deliveries of LNG from a variety of countries resulted in a decrease of gross imports by 67.9 Bcf. Additionally, U.S. gross exports expanded 49.9 Bcf. Net imports represented 10.6 percent of total U.S. consumption, the lowest proportion since 1991. This is a remarkable change from just 2007, when net imports were the highest on record, equaling roughly 16.4 percent of consumption.

Canadian supplies generally have not increased as a share of the U.S. market in recent years. Net imports from Canada in 2010 totaled 2,489.8 Bcf, which was a decrease of 3.1 percent, or 80.7 Bcf, from the previous year. Gross imports in 2010 decreased 48.7 Bcf, or 1.5 percent. This decrease coincided with a strong increase in exports from the United States to Canada. During the year, U.S. exports to Canada in 2010 increased 31.9 Bcf or 4.6 percent in comparison with 2009.

U.S. LNG imports in 2010 declined 4.6 percent from the 2009 level to 431.0 Bcf. This was the second lowest annual volume for LNG since 2002. The number of LNG source countries expanded from five to seven with Peru and Yemen shipping the fuel to the United States for the first time from new liquefaction plants in their countries. Nonetheless, the volume of LNG imports from existing exporters was well below the previous year. Decreased supplies from Trinidad and Tobago (the source country with the largest contribution to U.S. LNG imports), as well as from Egypt primarily accounted for the decline in deliveries in 2010. Volumes totaled 189.7 and 73.0 Bcf from, respectively, Trinidad and Tobago and Egypt. In 2009, Trinidad and Tobago and Egypt delivered, respectively 236.2 Bcf and 160.4 Bcf.

Rig Count Falls to 882. The natural gas rotary rig count fell to 882 as of March 11, according to data released by Baker Hughes Incorporated. Natural gas rigs fell by 17 from the previous week and are at their lowest level since February 2010. The weekly decline was the largest since November 2010. While natural gas rigs fell, oil rigs rose by 26, likely the result of recent increases in crude oil prices. Vertical rigs (including both oil and natural gas) rose by 6; horizontal rigs rose by 11; and directional rigs fell by 9. Horizontal rigs remain at historically high levels.

Natural Gas Transportation Update

  • On March 14, the Golden Pass LNG Terminal LLC and Golden Pass Pipeline LLC announced that it had been granted in service authority by the Federal Energy Regulatory Commission and has commenced commercial operations. The terminal and pipeline facilities, located near Sabine Pass, Texas, completed Phase 1 commissioning activities and performance tests for its terminal in early March. The nominal send out capacity for Phase 1 operations is 1 Bcf per day. According to the company, Phase 2 of the terminal is “expected to commence commercial operations in the May/June timeframe.” When fully operational, the terminal will have the capacity to import 15.6 million metric tons of LNG annually and have a nominal send out capacity of 2.5 Bcf per day.

  • Due to an equipment failure at a compressor unit at the Fort Morgan, Colorado, storage facility on March 13, Colorado Interstate Gas Company declared a force majeure. Effective March 16, the injection capacity at the facility was reduced by 25 million cubic feet (MMcf) per day until further notice—this reduces the injection capacity from 325 MMcf per day to 300 MMcf per day. Due to this reduction, Colorado Interstate Gas Company has adjusted the storage injection capacity for each customer to 92 percent of their normal injection capacity.

  • Tennessee Gas Pipeline Company declared a force majeure event on March 14 for its line 2 section located near Heidelberg, Mississippi (approximately 11.8 miles downstream of MLV 538) after a leak was detected. According to the event notice, Tennessee Gas Pipeline immediately “activated its emergency response plan and dispatched personnel to the scene to close valves and isolate the pipeline segment.” Tennessee Gas Pipeline is not requiring adjustments to nominations at this time, but is requiring operators and producers to keep physical flow to zero until further notices at the New Leaf River meter. In a notice on March 16, Tennessee Gas Pipeline reported that they are making progress in the repairs to the pipeline.

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.