Natural Gas

• The natural gas market is transitioning to spring, a “shoulder” season of lower demand between the relatively high-demand periods of winter and summer. As space-heating demand ebbed during the report week, prices declined across the lower 48 States. The Henry Hub spot price ended trading yesterday, March 24, at $4.02 per million Btu (MMBtu), a decrease of $0.25 compared with the previous Wednesday, March 17.
  
• At the New York Mercantile Exchange (NYMEX), futures prices continued to decline as storage inventories appeared more than adequate and domestic production remained strong. The futures contract for April delivery decreased by $0.20 on the week, or about 4.6 percent, to $4.11 per MMBtu.
  
• The natural gas industry began replenishing storage supplies for use during future periods of higher demand. As of Friday, March 19, working gas in underground storage was 1,626 billion cubic feet (Bcf), which is 8 percent above the 5-year (2005-2009) average. The implied net injection into storage was 11 Bcf.
  
• The price of West Texas Intermediate (WTI) crude oil decreased on the week by $2.64 to $80.29 per barrel, or $13.84 per MMBtu.

Moderate demand contributed to price declines at market locations across the lower 48 States. Total U.S. demand ended the report week at about 65.7 Bcf per day, but dropped below 60 Bcf per day earlier in the week, according to BENTEK Energy, LLC. At less than 60 Bcf per day, demand was well below the average available supply of approximately 64 Bcf per day, which suggests opportunities for injections into storage (see Storage below). According to BENTEK, overall demand on the week was 0.6 percent higher than the previous report week, but 1 percent lower than the similar week last year. Price declines occurred throughout the country, ranging between $0.18 and $0.38 per MMBtu. On Friday, March 19, the Henry Hub natural gas spot price decreased to $4.01 per MMBtu, the lowest price at the Henry Hub since November 25, 2009. Year-to-date, the Henry Hub price has fallen 34 percent.

Strong domestic production is also putting downward pressure on prices, contributing to lower imports of natural gas. Contrary to expectations of production declines because of a reduction in drilling activity last year, domestic production remains strong. Production from unconventional gas fields, such as the Marcellus Shale in the Northeast/Appalachia region and the Haynesville Shale in Louisiana, is growing steadily. According to the March edition of EIA’s Short-Term Energy Outlook (STEO), dry production this month is expected to reach 56.2 Bcf per day, a forecast that is about 3.5 percent higher than the projection in the November 2009 STEO. As a result of strong domestic production and lower prices, imports of natural gas have declined. During the report week, U.S. imports from Canada were 3.6 percent lower than last week and 10 percent lower than the same week in 2009. The pace of deliveries of U.S. liquefied natural gas (LNG) imports in recent weeks has slowed considerably compared with January and February. Sendout from U.S. LNG import terminals has averaged 1.2 Bcf per day in March, compared with 2.0 Bcf per day during the first 2 months of the year.

Prices decreased as much as 9 percent at trading locations across the lower 48 States. The largest price declines occurred in the Rocky Mountains and California, with decreases ranging between 6 and 9 percent. The Pacific Gas and Electric Citygate in Northern California, as well as Southern California Gas in the southern portion of the State reported high linepack (inventory on pipelines). The price at the Opal, Wyoming, trading point decreased $0.32 on the week to $3.82 per MMBtu. Prices at most trading locations in the Rockies are now below $4 per MMBtu and are among the lowest in the country. In addition, trading locations in the Northeast posted declines of as much as 6 percent on the week. For delivery in Zone 6 into New York off Transcontinental Gas Pipeline, the price hit a year-to-date low of $4.28 per MMBtu on Friday, March 19. Friday’s price was just $0.27 higher than the Henry Hub price, indicative of the lower price spread that may be developing between the Northeast and other markets. This lower differential is likely because of more supply options for the region, including growing supplies in the Marcellus Shale, access to Rockies supplies, and regasified LNG from the Canaport LNG terminal in Canada.

At the NYMEX, the price of the near-month contract (for April delivery) decreased $0.20 during the report week to $4.11 per MMBtu. The decrease was attributable chiefly to warmer temperatures moving into consuming regions of the country. Downward price pressure also appears related to a strong domestic production outlook. The April 2010 contract is currently priced about 13.1 percent higher than the expiration price of $3.63 per MMBtu for the April 2009 contract. However, the April 2008 contract expired at $9.58 per MMBtu, or more than double the current price of 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 $4.71 per MMBtu, a decrease of about $0.21, or 4.2 percent, since last Wednesday.

Working natural gas in storage rose to 1,626 Bcf as of Friday, March 19, posting the first net injection of the year, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure). The implied net injection was 11 Bcf, compared with last year’s net withdrawal of 1 Bcf and the 5-year (2005-2009) average withdrawal of 37 Bcf for the report week. Net injections of 2 Bcf and 19 Bcf occurred, respectively, in the West and Producing regions. Warming temperatures in most regions of the lower 48 States and sustained natural gas production likely contributed to the implied net injection during the report week. Working gas inventories were 121 Bcf above the 5-year average level and 28 Bcf below last year’s level at this time.

Regionally, working gas stocks exceed historical levels in the East and West regions, while stocks in the Producing region match historical norms. On a regional basis, working gas in storage exceeded the 5-year average in the East and West regions by 64 and 57 Bcf, respectively, and equaled the 5-year average in the Producing region. Levels of working gas in storage were 126 Bcf below last year’s level at this time in the Producing region, while the East and West regions surpassed last year’s level by 94 and 5 Bcf, respectively. As of March 5, stocks in the Producing region had fallen as much as 145 Bcf below last year’s level and 39 Bcf below the 5-year average for the region, but have since recovered.

Temperatures were generally warmer than normal in most Census Divisions in the lower 48 States during the week ended March 18. Based on the National Weather Service’s degree-day data, temperatures in the lower 48 States during the week ending March 18 were, on average, about 4 degrees warmer than normal and 3 degrees warmer than last year (see Temperature Maps and Data). Although the West South Central had the warmest temperatures in the lower 48 States at an average of 54 degrees last week, the average temperature in the region this report week was 3 degrees colder than normal. The average temperature in the East South Central Census Division was 1 degree colder than normal. Elsewhere in the lower 48 States, average temperatures ranged between 43 and 52 degrees, about 1 and 9 degrees warmer than normal.

Ratio of Oil to Gas Prices Rising. In the last several weeks, natural gas prices at the Henry Hub have fallen as the West Texas Intermediate (WTI) crude oil spot prices have increased. Both prices are measured in terms of thermal equivalency, or dollars per MMBtu. These price changes have led to an increase in the ratio of oil to gas prices. Over the last 10 years, this ratio has typically been no more than 2, with the WTI spot price being roughly twice the Henry Hub price. However, in 2009, the ratio rose to more than 5 for the week ending September 4. During this week, oil prices dropped, but natural gas prices dropped dramatically, hitting their lowest weekly level since 2002. The ratio oscillated somewhat in the fall, then began dropping in late November, and fell to below 2.5 for the remainder of 2009 and into 2010 (see figure below). However, the ratio began rising again mid-February 2010. Since the beginning of February, natural gas prices have fallen about 20 percent, while crude oil prices have risen 8 percent. The ratio of oil to gas prices was 3.3 for the week ending March 19, 2010, the highest since the week ending November 27, 2009. Possible factors that could drive the prices of oil and natural gas apart include a lack of perfect substitutability, the relative abundance of the domestic natural gas resource base, and reductions in the cost of extracting natural gas.

EPA Proposes Adding Sources to GHG Reporting System. The Environmental Protection Agency (EPA) on March 23 proposed several rules requiring additional industry sectors to report emissions data to the agency’s Greenhouse Gas (GHG) reporting system, which was finalized in October 2009. The current system requires 31 industry sectors to track and report emissions, covering about 85 percent of GHG emissions in the United States. According to the EPA, the proposed rule would require collection of emissions data from the oil and natural gas sector, industries that emit fluorinated gases, and from facilities that inject and store carbon dioxide underground for the purposes of geologic sequestration or enhanced oil and gas recovery. Under the proposed rules, which will be amendments to the Mandatory Reporting of Greenhouse Gases Rule, the newly-covered sectors would begin collecting emissions data in January 2011. The first annual reports would be submitted to EPA on March 31, 2012. Proposals will be open for comment for 60 days after publication in the Federal Register. More information about the proposal can be found here: http://yosemite.epa.gov/opa/admpress.nsf/d0cf6618525a9efb85257359003fb69d/8d717a8525394687852576ef00595ffc!OpenDocument

• Southern California Gas Company declared an operational flow order (OFO) on Friday, March 19, because of low demand in its service area and the resulting high linepack. The pipeline lifted the OFO on Sunday, but reinstated the OFO on Monday, March 22. As of the latest announcement, the OFO is expected to remain in place through Thursday, March 25.
  
• Southern California Gas Company also lost 150 million cubic feet (MMcf) per day of injection capacity at its Aliso Canyon storage facility on Friday, March 19. The company reported on Sunday, March 21, that the reduction in injection capacity occurred as a result of unscheduled repairs on one of its gas generators. An update on the storage facility status revealed that Southern California Gas declared a force majeure because one of the generator’s oil pumps needed repairs. As of the latest announcement, 60 MMcf per day of injection capacity continues to be unavailable and this reduction is expected to last through Monday, March 29.
  
• Questar Pipeline issued a reminder to customers that a reservoir test at its Clay Basin storage facility in Utah began on Wednesday, March 24 and is expected to last through Monday, March 29. During this time, the field will be limited to physical withdrawals only and injection nominations will not be accepted. According to the pipeline, on Tuesday, March 30, the reservoir will be conditioned at a constant withdrawal rate of 275 MMcf for 24 hours, followed by a Wednesday reservoir test at a constant withdrawal rate of 325 MMcf for 24 hours. From April 1-14, the field will be shut in and only transfer nominations will be processed. Normal Clay Basin operations are scheduled to resume on April 15.

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.