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Overview (Wednesday, December 5 to Wednesday, December 12)

Released: December 13

Next release: December 20, 2007


·        Natural gas spot and futures prices increased this report week (Wednesday to Wednesday, December 5-12), as cooler temperatures in much of the country increased demand for space heating. On the week the Henry Hub spot price increased $0.18 per million Btu (MMBtu) to $7.22.

·        At the New York Mercantile Exchange (NYMEX), prices for futures contracts also registered significant increases. The futures contract for January delivery rose about 22 cents per MMBtu on the week to $7.408.

·        Working gas in storage is well above the 5-year average for this time year, indicating a healthy supply picture as the winter heating season progress. As of Friday, December 7, working gas in storage was 3,294 Bcf, which is 8.5 percent above the 5-year (2002-2006) average.

·        The spot price for West Texas Intermediate (WTI) crude oil increased $6.96 per barrel, ending trading yesterday at $94.41 per barrel or $16.28 per MMBtu.





Spot natural gas prices generally increased in week-over-week comparisons, with the largest increases in the Northeast and Rockies. As is often the case during the start of the peak heating season, the direction of spot price movements has been influenced by weather patterns, particularly in market areas with a substantial potential heating load such as the Midwest and Northeast. On the week, the spot price at the Henry Hub in Louisiana increased $0.18 per MMBtu to $7.22, although the average price dipped below the $7-mark to $6.98 on Monday. Other spot prices along the Gulf Coast in Louisiana registered similar relatively small increases between $0.02 and $0.23 per MMBtu. Increases were more substantial in Texas, particularly in the western portion of the State. The average spot price in West Texas yesterday (December 12) was $6.85 per MMBtu, which was $0.50 per MMBtu higher than the previous Wednesday. As of this writing, the National Hurricane Center is monitoring a tropical system in the Atlantic. However, to date in this year, there has been little disruption of supplies from tropical storm activity and the tropical depression, named Olga, appears unlikely to have an impact on production.


Prices for Rockies supplies this week continued to be higher than this summer and parts of the fall, when lack of demand in the region, coupled with a lack of transportation outlets to the east, resulted in very low prices. For the week, the average Rockies price increased 41 cents per MMBtu to $6.62. The price for supplies on the Questar system in Utah increased 58 cents per MMBtu, or 10 percent, to $6.25. Although the current price at this market location (as an example of Rockies pricing generally) is substantially improved from prices of roughly $1 per MMBtu or less in early October of this year, it is still almost $1 less than the Henry Hub price. The opening of the Rockies Express Pipeline before the end of the year (at least for some of the receipt and delivery points) is expected to integrate this supply region with markets in other parts of the country and lessen the difference between the Gulf and Rockies prices.


In the Northeast, the average price yesterday was $11.58 per MMBtu, which was $1.48 higher than the previous Wednesday. Significant variability in pricing existed for much of the week, including yesterday (December 12) as many markets in the region experienced sharp increases during trading. The average spot price of natural gas off Algonquin Gas Transmission in the Northeast increased $7.58 per MMBtu for the day to $17.83, representing the largest increase in the region. Heating demand likely provided the impetus for the increase, as a Nor’easter appears to be moving into the region. As extreme weather conditions increase heating load in the region, various natural gas transportation providers such as Transcontinental Gas Pipe Line Corporation have been announcing constraints to pipeline capacity. However, the reduction in transportation flexibility primarily affects shippers who have purchased less expensive, non-firm capacity that often is interrupted during peak demand periods.






Futures prices increased at the NYMEX, likely owing to wintry weather expected in much of the country. The price of the near-month contract (for January delivery) rose $0.223 per MMBtu this week to $7.408, with the largest price movement occurring yesterday as the January contract jumped up about 32 cents, which offset the cumulative decline of the previous 4 trading days. While expectations of colder weather, including a Nor’easter this weekend, had an impact on trading, the increase also likely was affected by a large-scale price increase in crude oil futures during the day. On the week, price increases from pending cold weather were likely contained by a perception of adequate storage supplies for this winter season, now about 8.5 percent higher than the average for this time of year. The current January contract price of $7.408 per MMBtu is significantly higher than the January 2007 expiration price of $5.838 per MMBtu, but also a great deal lower than the expiration price of $11.431 for the January 2006 contract.


At the end of trading yesterday, the 12-month strip, which is the average price for futures contracts over the next 12 months, was priced at $7.743 per MMBtu, an increase of about 22 cents since last Wednesday. Currently, the highest-priced contract for the remaining months of this heating season (January 2008 to March 2008) is the February 2008 contract, which closed yesterday at $7.506 per MMBtu, a premium of $0.386 to yesterday’s Henry Hub price. This premium provides an economic incentive to put natural gas into storage for delivery later. However, the relationship between physical and futures prices varied during the week. On Tuesday, the Henry Hub spot price exceeded the near-month contract price and was only about $0.06 less than the February price. Generally, the incentive to hold gas in storage is decreasing as the heating season progresses, which is a typical pattern in the natural gas market (although the precise timing can change from year to year).


Recent Natural Gas Market Data



Working gas in storage decreased to 3,294 Bcf as of Friday, December 7, 2007, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure). The implied net withdrawal was 146 Bcf, which leaves storage levels at 8.5 percent above the 5-year average. This report week’s implied net withdrawal is 11 percent above the 5-year average withdrawal of 132 Bcf, but equals the net withdrawal last year at the same time.


This week’s above-average withdrawal reflects the impact of the return of cold temperatures to major consuming regions in the Lower 48 States. Temperatures across the country were 10 percent colder than normal and about 2.1 percent colder than last year, as measured by National Weather Service heating degree-days (HDDs) for the week ended December 6 (see Temperature Maps). HDDs in six Census Divisions were colder than normal, with the highest deviations recorded in the New England and Middle Atlantic divisions (which contain major consuming centers) of 29 and 26 percent, respectively. The East North Central Division, which includes Chicago and other Midwestern cities, recorded 18 percent more HDDs than normal (see Temperature Maps).


The small premium of the futures contract prices to the Henry Hub spot price that prevailed for much of the week also contributed to the higher-than-average withdrawal. As might be expected this time of year, the premium of the futures over the Henry Hub spot price has decreased. In fact, the Henry Hub spot price on December 4 exceeded the January futures contract price by more than 11 cents per MMBtu. With the high natural gas volume in storage and the small price premium, suppliers have an economic incentive to rely more on natural gas from storage for current supplies.





Other Market Trends:

EIA Updates Its Residential Price Brochure: The Energy Information Administration (EIA) has released the 2007 update of the brochure entitled Residential Natural Gas Prices: What Consumers Should Know.  This brochure provides basic information to the residential consumers concerning natural gas supplies and prices.  It explains the factors that influence natural gas prices, summarizes EIA's projections for the coming heating season, and suggests ways for consumers to save on their natural gas bills.  Most of the natural gas used in the United States comes from domestic production and the rest from imports, mostly from Canada.  Domestically produced and  imported natural gas is usually more than enough to supply gas during the summer allowing some gas to be placed in storage facilities for withdrawal in the winter. The price paid by residential customers has two main parts: transportation and distribution, and the commodity cost.  The transportation and distribution cost is the charge that customers pay for the gas to be moved by pipeline from where it is produced to the customer’s local gas company, and to bring the natural gas from the local gas company to their homes.  The commodity cost refers to the cost of the natural gas itself. In the past five winters (2002-2003 through last winter) the cost of natural gas at the wellhead has made up more than 50 percent of the residential price and this trend is expected to continue through the 2007-2008 winter.  


EIA Releases the Annual Energy Outlook 2008 Reference Case: EIA released the Annual Energy Outlook 2008 (AEO2008) reference case on December 12, 2007, which presents long-term projections of energy supply, demand, and prices through 2030 based on the results from EIA’s National Energy Modeling System (NEMS). The full publication, including complete documentation and more than 30 additional cases examining energy markets will be released in early 2008. According to the AEO2008 reference case: 

·        The price of natural gas at the wellhead (in 2006 dollars) is expected to decline from current levels through 2017, as new supplies enter the market. After 2017, however, real natural gas prices are projected to rise to $6.60 per thousand cubic feet (Mcf) (equivalent to $10.40 per Mcf in nominal dollars) by 2030.

·        The higher prices in the AEO2008 reference case compared with the AOE2007 reference case reflect an expected increase in production costs associated with recent trends that were discussed in AEO2007 but were not fully reflected. The higher natural gas prices also are supported by higher oil prices. 

·        Total domestic natural gas production is projected to increase from 18.6 to 20.2 trillion cubic feet (Tcf) between 2006 and 2021, before declining to 19.9 Tcf in 2030. The Alaska natural gas pipeline is projected to be completed in 2020. After the pipeline becomes operational, total Alaska natural gas production is expected to increase from 0.4 Tcf in 2006 to 2.0 Tcf in 2021, and then to 2.4 Tcf in 2030 as the result of a subsequent expansion.

·        Total net imports of liquefied natural gas to the United States are expected to increase from 0.5 Tcf in 2006 to 2.9 Tcf in 2030, down from 4.5 Tcf in AEO2007.

·        The share of natural gas use for electric power generation (including generation in the end-use sectors) is expected to remain between 20 and 21 percent through 2018, before falling to 14 percent in 2030.


EIA Releases December 2007 Short-Term Energy Outlook: According to its latest Short-Term Energy Outlook (STEO) released December 11, the Energy Information Administration estimates that the Henry Hub spot price is expected to average about $7.21 per Mcf  in 2007 and $7.78 per Mcf in 2008.  Natural gas expenditures are expected to increase 6.5 percent this winter compared with last year.  Despite high levels of natural gas in storage and relatively moderate temperatures, the onset of seasonal natural gas demand for space heating has caused a steady increase in the monthly average spot price since September.  Total natural gas consumption is expected to increase by 5.0 percent in 2007 mostly as a result of the increases in the residential, commercial, and electric power sectors, which occurred earlier in the year.  Total consumption is expected to continue to grow by 1.1 percent in 2008, assuming near-normal weather conditions.  U.S. marketed natural gas production in 2007 is expected to increase by 2.1 percent and by 1.6 percent in 2008.  Total Federal Gulf of Mexico production is expected to decline by 1.7 percent in 2007, but increase by 5.1 percent in 2008 resulting from developing deepwater supply infrastructure.  Liquefied natural gas (LNG) imports have slowed in recent months because of complications with key production and liquefaction facilities and an increase in global demand. Nevertheless, LNG imports are expected to increase by 35 percent in 2007, reaching 790 Bcf, and by 19 percent to 940 Bcf in 2008.  As of November 30, natural gas in storage was 3,440 Bcf, which was 273 Bcf above the 5-year average and the second-highest level ever recorded for the end of November.  


Natural Gas Transportation Update:

·        Columbia Gulf Transmission Company announced on Wednesday, December 5, that it has begun accepting receipt and delivery nominations at the Pine Prairie Energy Project LLC meter. The bi-directional meter is situated in Evangeline Parish, Louisiana, and has a daily capacity of 600,000 decatherms (Dth).

·        Questar Pipeline Company reported that the Oak Springs compressor station in Carbon County, Utah is back to normal operation as of December 11. As a result, Questar began using the Mainline 104 scheduling point for gas nominations instead of the West Fidlar point. The pipeline also reported that the repairs to Unit number 1 at the Greasewood compressor station in Colorado will be completed at the earliest on December 14, which will limit deliveries to TransColorado Pipeline to 25,000 Dth until further notice.

·        After determining that one of the four compressor units at Compressor Station 249 in Carlisle, New York, was in need of emergency repairs, Tennessee Gas Pipeline Company declared a force majeure on December 7. Subject to conditions elsewhere on Tennessee’s system and weather in the region, the estimated impact of the outage is 150 MMcf per day of reduced throughput, which represents approximately 15 percent of the station's maximum throughput. Tennessee asked its shippers not to deviate in excess of 2 percent of their scheduled quantity during the repair period.

·        Florida Gas Transmission Company (FGT) is performing maintenance on the Jacksonville Lateral near the FGT and Cypress interconnect in Florida until Friday, December 14. Operating conditions during this period may require the pipeline to schedule reduced volumes at the interconnect, which under normal operating conditions has a capacity of 230,000 MMBtu per day.


 Short-Term Energy Outlook