Overview (For the Week Ending Wednesday, January 14, 2009)* In the eastern half of the Lower 48 States, temperatures were significantly lower this report week, resulting in sharp price increases in the Northeast as space-heating demand rose. In the West and in the producing regions along the Gulf coast, however, a respite from cold weather provided some softening in natural gas spot prices.* During the report week, the Henry Hub spot price decreased $0.42 per million Btu (MMBtu) to $5.47.* At the New York Mercantile Exchange (NYMEX), futures prices for the near-month contract decreased in four out of the five trading sessions this report week. The futures contract for February delivery fell during the week by more than 90 cents to $4.970 per MMBtu, reaching the lowest price level for any near-month contract since September 27, 2006.* The level of working gas in underground storage continues to exceed both the 5-year average and last year’s level for this time of year. As of Friday, January 9, working gas in storage was 2,736 Bcf, which is 3.1 percent above the 5-year (2004-2008) average. The implied net withdrawal for the week was 94 Bcf.* The spot price for West Texas Intermediate (WTI) crude oil decreased $5.32 per barrel on the week, trading yesterday at $37.43 per barrel or $6.45 per MMBtu.

PricesSpot prices at trading locations in the Northeast increased sharply this week, gaining on average more than $5 per MMBtu. However, spot market locations in other areas of the country exhibited significant decreases, including the West. Weather conditions largely dictated the difference in price movement. However, trading locations in the Midwest largely failed to react to the cold temperatures. Prices in this area either decreased or remained about the same compared with last Wednesday. The price in the Detroit area off Michigan Consolidated fell 67 cents on the week to $5.54. However, the Chicago Citygate ended trading yesterday at $6.28 per MMBtu, the same price as last Wednesday, despite the continued below-zero temperatures and wind chills as low as minus 25 degrees Fahrenheit. In the Northeast, where prices decreased the previous week, prices surged this report week in response to the increased space-heating demand. The largest price hikes were recorded at Transcontinental Zone 6 New York ($9.71 per MMBtu) and Iroquois Gas Transmission Zone 2, which delivers natural gas to New England ($8.82 per MMBtu), trading yesterday at $17.34 and $16.20 per MMBtu, respectively. The average price in the region yesterday (January 14) was $12.14 per MMBtu, nearly twice the level of the previous Wednesday ($6.95).Counter to the price movements in the East, prices for upstream Rockies supplies and downstream consuming markets in the West decreased this report week. Areas west of the Rockies experienced warmer temperatures compared with the previous week’s, which reversed price increases from the prior week. As of yesterday, the average Rockies price decreased 59 cents to $4.24 per MMBtu. Prices in California decreased by an average of 72 cents to $4.81 per MMBtu, while Arizona/Nevada trading point prices fell by about 66 cents to $4.61 per MMBtu. Other producing areas along the Gulf Coast also exhibited price declines, with Louisiana prices falling about 31 cents on the week to an average of $5.54 per MMBtu. Also in Louisiana, the Henry Hub spot price ended trading yesterday at $5.47 per MMBtu, about 42 cents lower than last Wednesday. Overall, yesterday’s spot price at the Henry Hub was about 35 percent lower than last year at this time and about 10 percent lower than during the same time in 2007. However, prices in the Northeast as of yesterday were about 25 percent higher than those recorded at the same time in 2008 and more than double the price level on January 16, 2007.

Futures prices at the NYMEX decreased to their lowest levels in more than 2 years. The price of the near-month contract (February delivery) decreased by more than 90 cents per MMBtu since last Wednesday to $4.970. The decrease this week and the continuing downward trend in futures prices may have occurred as a result of the ample supplies available in storage for the second half of the heating season (the mid point of the winter heating season is today, January 15). During the report week, crude oil prices continued to trade at less than $40 per barrel, providing downward pressure on all energy commodities, including natural gas. This, coupled with the economic slowdown and the associated drop in industrial consumption, offset the effects of the cold snap. The current February contract price of $4.970 per MMBtu is significantly lower ($3.226) than the February 2008 price last year at this time.Contracts for futures prices beyond the near-month contract all generally decreased during the week as well. 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 $5.604 per MMBtu, a decrease of about 81 cents since last Wednesday. Currently, the average price for contract months remaining in this winter heating season (February and March) is $4.971, which is $1.165 lower than the expiration price of $6.136 for the January 2009 contract.

StorageWorking gas in storage was 2,736 Bcf as of Friday, January 9, leaving natural gas inventories 3.1 percent above the 5-year average inventory level for the report week, according to EIA’s Weekly Natural Gas Storage Report see Storage Figure). At 2,736 Bcf, working gas stocks were 28 Bcf above the 2,807 Bcf in storage at this time last year and exceeded the 5-year average by 81 Bcf. Today (January 15) marks the midpoint of the heating season, leaving ample gas supplies in storage for the second half. So far this season, cumulative withdrawals have exceeded those of the 5-year average by about 24 Bcf. Should the net changes for the remainder of the season correspond to those of the 5-year average, there will be about 1,440 Bcf left in storage on March 31, 2009.Net withdrawals from working gas in storage for the week were somewhat higher than historical levels. The net withdrawal from working gas in storage of 94 Bcf is about 7 percent higher than the 5-year average of 88 Bcf and 3 percent more than last year’s net withdrawal of 91 Bcf for the same report week. A contributing factor behind the above-average withdrawals is relative prices. Prices for the two near-month futures contracts (February and March delivery) were in backwardation for the last 3 trading days of the storage week (ending Thursday). The lower prices for future delivery provide an economic incentive to withdraw natural gas to avoid paying the higher spot price and to reduce the cost of gas remaining in storage. The larger withdrawal compared with the 5-year average occurred despite the below-normal number of heating degree-days in the Lower 48 States during the report week (see Temperature Maps and Data), which were 8 percent below the normal level for the country as a whole. The only Census Division in the Lower 48 States with warmer-than-normal temperatures was the Pacific Census Division where temperatures as measured by heating degree-days (HDD) were 8 percent above normal. While temperatures in New England matched normal levels, the Middle Atlantic, East North Central, and West North Central Census Divisions, which include major gas-consuming areas, had heating degree-days up to 5 percent below normal for the report week. Aggregate heating degree-days this week were 10 percent higher than the same level reported last year at this time, partly accounting for the deviation in net withdrawals for the week ended January 9 compared with the same week last year.

Other Market TrendsEIA Releases the January Short-Term Energy Outlook. The Energy Information Administration (EIA) on January 13 released its latest Short-Term Energy Outlook (STEO), which includes the monthly forecasts through December 2010 for the first time. Residential natural gas prices this winter are projected to average $12.17 per thousand cubic feet (Mcf), which is 4 percent less than last winter’s level. The U.S. economic downturn is a contributing factor to the lower natural gas prices. EIA projects that the spot price of natural gas at the Henry Hub will decline from an average of $9.13 Mcf in 2008 to $5.78 per Mcf in 2009, but then increase in 2010 to an average of $6.63 as the economy revives. Owing mostly to a 5.8-percent increase in heating degree-days year over year, total natural gas consumption is estimated to have increased by 0.7 percent in 2008. However, gas consumption is expected to decline by 1.0 percent in 2009 because of expectations of continued economic weakness. By 2010, natural gas consumption is projected to increase by 0.7 percent because of increased demand in the electric power sector. Total marketed natural gas production is estimated to have increased by 5.9 percent in 2008 driven by the development of unconventional reserves in the Lower 48 States. Natural gas market production in 2009 is expected to continue to increase by 0.7 percent, but is expected to decrease in 2010 by 0.9 percent, because of the recent decline in drilling activity. Drilling for natural gas in the Lower 48 States has fallen about 22 percent by early January from a peak level of 1,606 rigs for the week ending September 12, 2008 (see related story on natural gas drilling rigs). U.S. imports of liquefied natural gas (LNG) are estimated to have totaled about 350 Bcf in 2008 and are expected to total about 420 Bcf in 2009 and more than 500 Bcf in 2010. As of January 2, 2009, working natural gas in storage was 2,830 Bcf, which was 87 Bcf higher than the 5-year (2004-2008) average and 31 Bcf higher than the level during the corresponding week last year.EIA Releases Updated Report on Imports and Exports. The Energy Information Administration (EIA) released the report, U.S. Natural Gas Imports and Exports: 2007, on January 14. This report examines recent trends in U.S. international trade of natural gas. International natural gas deliveries in 2007 were a critical source of supply to meet U.S. energy demand. Total natural gas net LNG and pipeline imports to the United States reached an all-time high record of 3,785 Bcf in 2007. The growth of LNG deliveries from a variety of countries and pipeline imports from Canada increased gross imports by 421 Bcf. However, about 23 percent of the expanded import level was offset by an increase in U.S. gross exports. U.S. pipeline natural gas exports increased in volumes overall in spite of a decline in pipeline exports to Mexico. Furthermore, there were two new destination countries for LNG exports during the year, Russia and Canada. A single LNG cargo was delivered to Russia in October carrying the equivalent of about 2 Bcf of natural gas in gaseous form, and a single truckload of LNG was delivered to Canada in July. U.S. net imports accounted for about 16 percent of domestic consumption in 2007. Despite being a small portion of overall U.S. supplies, the volumes received from foreign sources still qualify the United States as the largest importer of natural gas in the world. In 2007, the United States was the fourth leading importer of LNG in the world taking delivery of 771 Bcf. The report includes extensive historical tables with natural gas import and export data through 2007 for both pipeline and LNG trade.Rotary rigs drilling for natural gas fell to 1,239 for the week ending January 9, 2009. The rig count fell by 28 from the previous week, about a 2-percent decline. The week ended January 9 is the seventh week in a row the natural gas rig count has fallen. The rig count is off about 23 percent from record levels in late summer 2008. The average rig count for the first 2 weeks in 2009 is 1,253, compared with an average rig count of 1,430 for the corresponding period in 2008. This represents about a 12-percent decline year over year. However, the latest level represents a significant decline from peak levels during 2008. The natural gas rig count reached 1,606 on August 29, 2008 (and again on September 12), the highest number of gas rigs in the more than 21 years since July 1987, when publication began of drilling rig data by fuel type. Decline patterns varied by type of rigs. Horizontal rotary rig counts, which account for both oil and gas drilling, have dropped almost 20 percent to 522 from a high of 650 for the week ended October 31, 2008. However, vertical oil and gas rigs began dropping earlier in the year and have dropped further with an almost 30 percent decline to 722 from a 2008 high of 1,017, reached the week ended August 29. Factors likely leading to the drop in rig count are the drop in natural gas and oil prices, which weakens the incentive to drill for oil and gas, and the difficulty obtaining financing in a weakened economy, which may lead producers to cancel plans for drilling projects.Natural Gas Transportation Update* The extreme cold from the Arctic air mass currently moving through the Midwest and East has resulted in numerous postings of interstate pipeline restrictions that are intended to preserve system integrity during peak demand periods. In the Midwest, Northern Natural Gas Company, which posted an expected system-weighted temperature of minus 10 degrees for January 15, has forced shippers to balance nominations and flows for much of the last week. Also citing extreme conditions, Panhandle Eastern Pipe Line Company on Tuesday implemented an operational alert. The alert limits certain flows under interruptible rate schedules in preference for higher-priced firm service. Panhandle added that limits will be evaluated on a daily basis.* With the cold front moving into the Northeast today (Thursday, January 15), regional pipelines also were preparing for peak loads to meet increased space-heating needs. With below-normal temperatures forecast for much of its market area, Transcontinental Gas Pipeline Corporation issued an operational flow order limiting imbalances (between flows and nominations) to 5 percent or 1,000 decatherms (Dth). Referring to colder market-area temperatures and its need to maintain linepack, Tennessee Gas Pipeline Company on Wednesday issued a similar alert requiring shippers to limit daily negative imbalances to 2 percent of scheduled quantities or 500 Dth, whichever is greater. Tennessee said penalties will be 21.98 cents per Dth for that portion of physical quantities related to underdeliveries by receipt point operators.* Even pipeline companies in the U.S. Southeast joined the chorus of alerts with their own flow orders. Southern Natural Gas Company implemented penalties of up to $15 per Dth for imbalances exceeding 8 percent. Noting the cold front would likely reach its territory, Florida Gas Transmission Company issued an alert to customers setting its imbalance limitation at a relatively high level of 25 percent.* Northwest Pipeline Company on January 8 said it would cut volumes scheduled over the capacity of 680,000 Dth per day at its Kemmerer compression station in Wyoming. The pipeline said it would send out daily notices of realignment volumes whenever Kemmerer was scheduled at more than this level.* Centerpoint Energy Gas Transmission Company on Tuesday, January 13, told shippers that unscheduled maintenance will be needed at the Buckley, Malvern, and Ada compressor stations in Oklahoma. Because of this maintenance and extreme cold in its service area, Centerpoint said it will require shippers to balance nominations and flows through the period of extreme cold.