Natural Gas

• Wholesale natural gas prices at most market locations east of the Mississippi River moved higher this week as a bitter cold moved into the eastern half of the country. West of the Mississippi River, a gradual warming trend resulted in lower prices. During the report week (January 5-12), the Henry Hub spot price increased $0.03 to $4.55 per million Btu (MMBtu).
  
• At the New York Mercantile Exchange (NYMEX), futures prices increased during the report week, likely in part due to forecasts of continuing cold weather and improving economic conditions. The futures contract for February 2011 delivery increased by $0.06 per MMBtu on the week to $4.53 per MMBtu.
  
• As of Friday, January 7, working gas in underground storage was 2,959 billion cubic feet (Bcf), which is 5.8 percent above the 5-year (2006-2010) average, according to the Energy Information Administration’s (EIA) Weekly Natural Gas Storage Report (WNGSR).
  
• The natural gas rotary rig count fell last week by 5 to 914, according to data reported January 7 by Baker Hughes Incorporated.

As a strong cold-air mass pushed deep into the middle and eastern parts of the country this report week (January 5-12), natural gas demand for space heating and as a fuel for electric power plants increased significantly. Compared with the prior week, U.S. natural gas consumption increased about 19 percent, and exceeded 100 Bcf per day (Bcf/d) in each of the last three days, according to BENTEK Energy Services, LLC. Combined consumption in the residential and commercial sectors increased 19 percent to over 50 Bcf during these days. This higher demand led to widespread increases in prices east of the Mississippi River that were generally less than a dime with the exception of constrained markets in the Northeast, where increases were much higher. The Henry Hub price increased on the week by $0.03 per MMBtu, or 1 percent, while prices at other markets in the Gulf of Mexico producing region showed similar increases. With wintry weather reaching as far south as Florida, the interstate natural gas pipeline serving the State this week alerted shippers of the need to balance supplies in order to meet higher demand. The spot price there finished trading yesterday at $17.04 per MMBtu, increasing $8.16 from the previous day. Continuing cold weather has resulted in a strengthening in prices from earlier in the fall. The Henry Hub price has increased 33 percent from its price of $3.42 on November 1 (the start of the heating season). Nonetheless, prices are still below their levels this time last year. On January 12, 2010, the Henry Hub price was $5.57 per MMBtu, or about 22 percent above yesterday’s average of $4.55. The primary difference in the pricing environment from last year is likely continuing strong U.S. production levels, which averaged close to 62 Bcf during the week and were 9.4 percent higher than last year at the same time.

Price increases in the Northeast were the second highest in the country following Florida, with prices at a number of markets in New York and New England ending the report week above $10 per MMBtu. Nonetheless, several market centers in the Northeast region posted declines of close to $0.10 per MMBtu, or more than 1 percent on the week. The uneven pattern in pricing has occurred intermittently this winter as pipeline enhancements to the region have resulted in changing pricing dynamics between market centers. For delivery in Zone 6 (New York) off Transcontinental Gas Pipe Line, the price yesterday (January 12) averaged $13.58 per MMBtu, which was $7.66 more than the previous Wednesday’s price. In trading yesterday, the Transco Zone 6 price was $9.03 per MMBtu higher than the Henry Hub’s, a significant increase from the prior week’s average differential of $1.35 per MMBtu. The closely-watched difference in the Northeast price over Gulf of Mexico regional prices tends to fluctuate severely during the winter. Interstate pipelines have limited flexibility to transport non-firm supplies between the two markets because of colder weather and the associated increase in space-heating demand in the Northeast, causing differences in local supply and demand conditions to develop. However, this basis differential has been minimized this winter for certain locations in the Northeast following pipeline enhancements and new supply growth in the region. For example, the price for supplies off of Dominion Pipeline in the Northeast yesterday was $4.73 per MMBtu, a premium of only 17 cents over the Henry Hub price.

West of the Mississippi, scattered price increases were significantly lower, and prices at most market locations decreased. As the coldest weather from the current cold front moved out of the region as the week progressed, prices at Rockies trading locations generally trended lower by between 10 and 20 cents per MMBtu, or generally less than 4 percent. The price for supplies on Kern River Pipeline in Utah (for delivery into California) decreased $0.15 to $3.40 per MMBtu. Yesterday’s price for natural gas off of Colorado Interstate Pipeline was $4.26 per MMBtu, which represented a decrease of $0.11 cents per MMBtu on the week. Small price increases occurred at markets in the Midcontinent and Texas.

U.S. pipeline imports from Canada were significantly higher during the report week in comparison with the prior week, likely resulting from increased withdrawals from storage in Canada to meet heating demand in the United States. According to BENTEK, which monitors flows on the continental pipeline network, U.S imports from Canada during the report week increased 16 percent relative to the prior week to approximately 8.5 Bcf/d. An additional cause for the increased pipeline imports was flow from the Canaport LNG terminal in New Brunswick, Canada, supplies from which were transported into the Northeast by Maritimes and Northeast Pipeline (M&NE). M&NE reported transporting nearly at its maximum capacity this week as regasified liquefied natural gas (LNG) flows from Canaport increased. U.S. LNG imports (as measured by sendout from regasification terminals) averaged 1.1 Bcf/d during this report week, which was 62 percent higher than the prior week. Both Canadian and LNG imports are significantly lower than the prior year at this time, likely as a result of continuing supply strength from domestic drilling, particularly in the shale formations. Pipeline and LNG imports during the report week were, respectively, 10.8 percent and 67.5 percent lower than last year at this time.

At the NYMEX, the price of the near-month contract (for February 2011 delivery) increased $0.06 during the report week to $4.53 per MMBtu. With the weather outlook for much of the country indicating continuing cold temperatures, the price of the February contract is now 32 cents per MMBtu, or 7.5 percent higher, than the final price of $4.22 for the January 2011 contract. However, the current February 2011 price is about 74 cents per MMBtu lower than the final expiration price of $5.27 for the February 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 $4.75 per MMBtu, an increase of about $0.11 per MMBtu, or less than 3 percent, since last Wednesday.

Working natural gas in storage fell to 2,959 Bcf as of Friday, January 7, according to EIA’s WNGSR (see Storage Figure). The net draw of 138 Bcf is significantly smaller than last year’s draw of 255 Bcf for the report week, which was one of the largest withdrawals reported in the history of the WNGSR. The Producing region storage levels are now 185 Bcf above the 5-year average, while the East region is 35 Bcf below. Working gas stocks in the West region are 10 Bcf above average.

Temperatures were slightly warmer than normal in the lower 48 States during the week ending January 6. The National Weather Service’s degree-day data show that the temperature in the lower 48 States last week averaged 34.7 degrees, just 1.3 degrees above normal, and 6.4 degrees above last year (See Temperature Maps and Data). Weather varied considerably by region. In the West, the Mountain and Pacific regions were 8.6 and 5.0 degrees colder than normal, respectively. Most of the rest of the country experienced higher than normal temperatures, led by New England, which was 5.9 degrees above normal.

EIA Releases Short-Term Projections out to 2012. EIA released the Short-Term Energy Outlook on January 11, 2011, which includes for the first time projections to 2012. Forecasted natural gas consumption is expected to average 65.4 Bcf per day in 2011, and rise 2 percent to 66.5 Bcf per day in 2012. The projected year-over-year increase is driven by increases in the electric power and industrial sectors, while commercial and residential consumption largely remain flat. For 2011 and 2012, EIA forecasts a decline in net gas imports; more specifically, EIA expects gross pipeline imports of 8.6 Bcf/d in 2011 and 8.2 Bcf/d in 2012, year-over-year decreases of 4.3 and 4.4 percent, respectively. Total marketed production is expected to fall slightly this year, from 61.6 Bcf per day in 2010 to 61.4 Bcf per day in 2011, as a result in part of a significant decrease in production in the Gulf of Mexico, made up for in part by increases elsewhere. Production rebounds in 2012 to 62.7 Bcf per day with expected increased demand and prices. The EIA forecast shows the Henry Hub spot price averaging $4.02 per MMBtu in 2011, a decline of about 8 percent from 2010. In 2012, the projected Henry Hub spot price rebounds, averaging $4.50 over the year.

Natural Gas Rotary Rigs Fall to 914. The natural gas rotary rig count fell by 5 to 914, according to data reported January 7 by Baker Hughes, Incorporated. This is the fifth consecutive week the rig count has declined. Compared to its level a year ago, however, the natural gas rig count is about 17 percent higher, likely the result of continued development of natural gas in shale formations. During the week, horizontal rigs (including both oil and natural gas) increased by 19 to 966, while vertical rigs (also including both oil and natural gas) fell by 12 to 523. Horizontal rigs are currently at their highest level for the 20 years for which data are available; rigs also reached 966 during two weeks in December.

• Colder-than-normal temperatures prompted several pipelines to issue system notices. With colder than normal weather forecasted for the week, Southern Star Central Pipeline, Inc. posted a list of criteria for shippers on January 10, effective until January 14. The notice stated, “if customers do not adhere to the request, Southern Star could issue a system-wide, point, or shipper specific OFO [Operational Flow Order] on short notice.” Tennessee Gas Pipeline Company added an OFO warning for January 13 for Zone 5 and Zone 6 to an imbalance warning it issued on January 10. On January 11, Iroquois Gas Transmission requested that shippers adhere to their scheduled volumes through the January 14th, with flow control to be implemented and activated as necessary. Similarly, Texas Eastern Transmission Company has placed restrictions on shippers effective January 12 through January 14.
  
• TransCanada Corporation’s Bison Pipeline has been filling with linepack since approximately the start of the month. The 302-mile interstate pipeline has a design capacity of approximately 477 million cubic feet per day, with a potential to expand to 1 billion cubic feet per day. The pipeline is designed to transport gas from the Powder River Basin to the Midwest market, extending northeastward from the Dead Horse Region near Gillette, Wyoming, through southeastern Montana and southwestern North Dakota. It will interconnect with Northern Border Pipeline Company’s system near Northern Border’s Compressor Station 6 in Morton County, North Dakota. The pipeline was originally expected to open in November 2010 but weather and other complications caused a delay.

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.