Natural Gas Weekly Update

• Significant price increases occurred through Friday, January 8, apparently as a result of extreme temperatures and continued wellhead freeze-offs in some parts of the country during the first half of the report week. However, with temperatures across much of the lower 48 States returning to normal, spot prices receded significantly between Monday, January 11, and Wednesday, January 13. On the week, natural gas spot prices registered significant net decreases at all locations in the lower 48 States since January 6.
• The largest weekly price drops occurred in Florida and the Northeastern markets. The Henry Hub spot price fell 86 cents, or about 13 percent, to $5.61 per million Btu (MMBtu).
• At the New York Mercantile Exchange (NYMEX), the futures contract for February delivery at the Henry Hub ended trading yesterday, January 13, at $5.733 per MMBtu, falling by 28 cents or about 5 percent during the report week.
• Natural gas in storage decreased to 2,852 billion cubic feet (Bcf) as of January 8, leaving inventories 4.4 percent above the 5-year average (2005-2009). The implied net withdrawal for the week was 266 Bcf, the second-highest net weekly withdrawal since the weekly data series began.
• The spot price for West Texas Intermediate (WTI) crude oil decreased by $3.46 since Wednesday, January 6, to $79.66 per barrel or $13.73 per MMBtu.
• According to Bentek Energy, liquefied natural gas (LNG) sendout volumes reached record highs this report week, reaching 4.4 Bcf per day on Friday, January 8. Friday's sendout surpassed the previous record of 4.2 Bcf per day established on August 9, 2007. Bentek Energy also reported a significant increase in Canadian imports this week, which peaked at 10.1 Bcf per day on January 8.

A major arctic air mass enveloped most of the country through Monday, January 11, bringing the lowest temperatures of the season to date as far as the southern tip of Florida. The cold weather resulted in spot price increases across the lower 48 States in the first few days of the report week, most of which peaked on Thursday, January 7. The associated increase in space-heating demand resulted in double-digit prices in Florida and the Northeast, while the rest of the spot price locations traded between $6 and $9 per MMBtu.

In Florida, spot natural gas traded between $14.12 and $14.99 per MMBtu for most of the report week, falling below $10 on Tuesday, January 12. Apparently driven by much-below-normal temperatures and high demand, the Florida spot price rose to levels not recorded since June 2008. Low temperatures in the State dipped below freezing, with temperatures ranging from 5 to 10 degrees below normal during the report week. Gulfstream Pipeline, which transports natural gas from Louisiana to Florida across the Gulf of Mexico, reported significant linepack problems as a result of high demand in the State.

Several spot price locations that serve markets in the Northeast also registered price spikes that exceeded $10 per MMBtu. In fact, prices at all but four of the trading locations in the Northeast jumped to between $10.00 and $14.09 per MMBtu during the week. However, like the rest of the country, prices receded following the slight increase in temperatures. Overall, price locations in the Northeast recorded net weekly decreases between $0.72 and $4.63 per MMBtu or 11 and 42 percent. Transcontinental Pipeline's Zone 6 trading location, which serves New York City, ended the report week at $6.39 per MMBtu, falling precipitously after its $14.09 peak on January 8. Prices in other parts of the country generally followed the same pricing pattern, but at much lower levels. Spot locations in the Rocky Mountains, for example, ended the report week between $0.32 and $1.53 per MMBtu lower than the previous Wednesday, with the intraweek spikes reaching relatively low levels of between $6.00 and $6.93 per MMBtu.

In addition to weather patterns, increased natural gas supplies also likely affected the spot price movements this week. Substantial increases in LNG sendout volume and natural gas imports from Canada this report week appear to have contributed to price declines in the second half of the report week. LNG sendout volumes reached 4.4 Bcf per day on January 8, surpassing the previous record of 4.2 Bcf per day established on August 9, 2007, according to Bentek Energy. LNG sendout volumes for the week were estimated at 3.2 Bcf per day. Imported volumes of natural gas from Canada also spiked this week, reaching 10.1 Bcf per day on January 8, with most of the increase in Canadian imports destined for the Midwest. Canadian imports totaled 74.5 Bcf for the report week.

At the NYMEX, the price of the near-month contract (for February delivery) decreased by 28 cents during the report week to $5.733 per MMBtu. The decrease may be attributable to expectations of lower consumption as a result of the current (though perhaps temporary) reprieve from extreme cold and increase in natural gas supplies. The February 2010 contract began the report week at $6.009 per MMBtu, the first time a near-month contract exceeded $6 per MMBtu since the February 2009 contract ended trading at $6.072 per MMBtu on January 5, 2009. 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 $6.02 per MMBtu, a decrease of about 17 cents, or 2.7 percent, since last Wednesday.

Working gas in storage decreased to 2,852 Bcf as of Friday, January 8, according to EIA's Weekly Natural Gas Storage Report (see Storage Figure). The implied net withdrawal of 266 Bcf significantly exceeded both the 5-year average (2005-2009) of 76 Bcf and last year's net withdrawal of 88 Bcf for the same report week. Working gas stocks are now 103 Bcf above last year's level at this time and 121 Bcf above the 5-year average.

The implied net withdrawal of 266 Bcf is the second-highest net withdrawal on record, second only to the 274-Bcf net withdrawal recorded for the week ended January 25, 2008. Net withdrawals for the week in the Producing Region totaled 100 Bcf, the highest weekly net withdrawal on record for this region. The East and West Regions recorded net withdrawals significantly above the 5-year average, but fell short of the all-time highs. Working gas stocks fell below 3,000 Bcf for the first time since July 2009. Working gas stocks remained above this level for 24 consecutive weeks, the longest since the weekly data series began.

Significantly colder-than-normal temperatures in the lower 48 States likely contributed to the above-average level of net withdrawals from working gas storage. The National Weather Service's degree-day data (see Temperature Maps and Data) indicate that temperatures in the lower 48 States during the week were below both normal and year-ago levels. On average, heating degree-days (HDD) were 17 percent above normal in the lower 48 States. The pattern of colder-than-normal temperatures prevailed in all Census Divisions except the Mountain and Pacific Census Divisions. HDDs in Census Divisions outside the Mountain and Pacific Census Divisions ranged between 2 and 48 percent above normal. The largest deviations from normal temperatures occurred in the Census Divisions situated between the Rocky and Appalachian Mountains. Overall, the average temperature for the week in the United States was 27.6 degrees, 6 degrees below normal and about 8 percent below last year's temperature for the same week.

EIA Expects Higher Natural Gas Prices in 2010. EIA on January 12 released its latest Short-Term Energy Outlook (STEO), which includes monthly forecasts through December 2011 for the first time. EIA projects that the spot price of natural gas at the Henry Hub will increase to an average of $5.36 per thousand cubic feet (Mcf) in 2010, which is $1.30 per Mcf more than the 2009 average of $4.06 per Mcf. The price is projected to continue increasing in 2011, averaging $6.12 per Mcf. As a result of continued high storage levels, enhanced domestic production capabilities, and slow consumption growth, prices are not expected to rise dramatically through the forecast period. STEO estimates that total natural gas consumption declined by 1.5 percent in 2009 to 62.4 Bcf per day, mostly as a result of the economic downturn. Although low natural gas prices throughout most of 2009 led to a large increase in natural gas-fired electric power generation, declines in industrial, residential, and commercial sector consumption drove the year-over-year decrease in total consumption. Natural gas consumption is expected to remain at about the same level as in 2010 (62.4 Bcf per day) and reach 62.7 Bcf per day in 2011. Total marketed natural gas production is estimated to have increased by 3.7 percent in 2009, despite a 59-percent decline in the working natural gas rig count from September 2008 to July 2009. EIA expects marketed natural gas production to decrease by 3 percent in 2010 as a result of steep declines from initial production at newly-drilled wells and the lagged effect of reduced drilling activity. However, in 2011, production is expected to increase by 1.3 percent compared with 2010, reaching 59.2 Bcf per day.

Cold Temperatures Lead to High LNG Sendout Volumes. Since December 29, 2009, deliveries from LNG terminals have exceeded the 5-year (2005-2009) maximum for this time of year. According to Bentek Energy, in the past week, LNG sendout approached the record levels seen in the spring and summer of 2007, and on January 8, 2010, exceeded the high reached on August 9, 2007. Despite recent declines over the past few days, record LNG deliveries have supplemented falling production attributable to freezing wells, thus meeting high weather-related demand. Likely in response to high natural gas prices in the Northeast, large supplies flowed into East Coast terminals, including Everett and Northeast Gateway in New England, as well as Cove Point in the Mid-Atlantic. Pipelines from the Canaport facility in New Brunswick, Canada, have also delivered LNG to the Northeast. Looking forward, seven North American inbound LNG tankers are scheduled to arrive in the United States in the next month, according to Bentek Energy, and will be particularly important if cold weather continues.

• With warmer temperatures moving into the lower 48 States, pipeline companies relaxed flow restrictions this week. The return to nonpeak flow conditions on the interstate pipeline grid was perhaps most noticeable in the Midwest and Midcontinent, where Northern Natural Gas Company ended its System Overrun Limitation (SOL) in all market-area zones on Friday, January 8. Implementation of a SOL ensures that shippers do not take more from the system than they nominate. Other pipeline companies, such as CenterPoint Energy Gas Transmission Company and Southern Star Central Gas Pipeline Corporation, both with service territories in the Midcontinent, and Texas Gas Transmission LLC in the Midwest, also rescinded critical notices from the prior week on Monday, January 11.
• In the Southeast, Southern Natural Gas Company on Wednesday, January 13 canceled its Type 6 operational flow order, the most stringent type of restriction on flows. Limits on short imbalances had been in effect since Sunday, January 10. Similarly, Florida Gas Transmission Company on Wednesday ended its Overage Alert Day, which also restricted short imbalances and had been effective since January 3.
• ANR Pipeline Company on Wednesday, January 13, restricted flows in Louisiana because of unplanned repairs at Eunice Compressor Station in the southeastern part of the State. The company limited delivery capacity between Patterson and Eunice, both located in the southern part of Louisiana, to 760 million cubic feet (MMcf) per day through January 19. Based on current nominations for this segment, ANR said Tuesday it anticipates that the reduction may result in the curtailment of some flows.
• Texas Eastern Transmission Corporation on Monday, January 11, lost commercial power to Lambertville Compressor Station in New Jersey. As a result, the pipeline company estimated a loss of capacity of 150 MMcf per day through the compressor station. The pipeline company restricted interruptible nominations for Tuesday's gas day and prohibited increases in receipts sourced upstream of Lambertville for delivery downstream of Lambertville for most transportation services. On Wednesday, January 13, the company said commercial power had been restored and lifted the restrictions.
• Southern California Gas Company announced it will be conducting maintenance at three storage fields over the next 3 months. As a result, there will be a reduction of 300 MMcf per day of injection capacity from January 19 through March 1 at the Aliso Canyon storage field in Los Angeles County. The La Goleta storage field in Santa Barbara County will lose 140 MMcf per day of injection capacity and 340 MMcf per day of withdrawal capacity for the gas days of March 15 through March 19. The Honor Rancho storage field in Los Angeles County will lose 250 MMcf per day of injection capacity and 1 Bcf per day of withdrawal capacity from March 21 through April 2.

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.