• Since Wednesday, March 31, natural gas spot prices climbed at most market locations across the lower 48 States, with increases of as much as 8 percent. The Henry Hub natural gas spot price rose $0.15, or about 4 percent, to $4.08 per million Btu (MMBtu), in a week of trading shortened by the Good Friday holiday on April 2.



• At the New York Mercantile Exchange (NYMEX), the futures contract for May delivery at the Henry Hub settled yesterday, April 7, at $4.02 per MMBtu, rising by $0.15 or about 4 percent since the previous Wednesday.



• Natural gas in storage was 1,669 billion cubic feet (Bcf) as of April 2, about 12 percent above the 5-year (2005-2009) average. The implied net injection for the week was 31 Bcf.



• The spot price for West Texas Intermediate (WTI) crude oil increased by $2.19 per barrel since Wednesday, March 31, to $85.64 per barrel or $14.77 per MMBtu.

Since last Wednesday, March 31, natural gas spot prices increased at market locations across the lower 48 States. Despite moderating temperatures and continued robust natural gas production, natural gas prices posted gains on the week. Possible factors contributing to widespread price increases include rising crude oil prices, a rally in natural gas futures prices, and a shift in market expectations regarding future natural gas prices. On the week, price increases at most markets generally ranged between $0.09 and $0.30 per MMBtu, or about 3 to 8 percent. The El Paso Pipeline South Mainline/North Baja market location posted the largest gain of $0.49 per MMBtu, or 13 percent.

Natural gas consumption in the lower 48 States fell by 14 percent since last week, with declines in all market sectors. Natural gas consumption posted declines on the week in each of the major market sectors, with decreases ranging between 1 to 30 percent, according to BENTEK Energy Services, LLC. The largest weekly declines occurred in the residential/commercial and electric power market sectors, which fell 30 percent and 3 percent, respectively. The declines in these sectors likely resulted from the decrease in space-heating demand associated with moderating and unseasonably warm temperatures. Industrial demand fell about 1 percent on the week. Compared with the same week last year, natural gas consumption in the lower 48 States has fallen about 14 percent, driven by significant declines in the residential/commercial sector, which was down 30 percent from its year-prior level. However, natural gas in the electric power and industrial sectors was 3 percent and 5 percent above year-ago levels, respectively.

Natural gas supplies increased since last week, as a result of increases in production and net imports. Natural gas supplies increased by almost 2 percent since last week, according to BENTEK. Natural gas production increased about 1 percent on the week, while Canadian pipeline and liquefied natural gas (LNG) imports rose 5 and 24 percent, respectively. The robustness of domestic natural gas production suggests that the natural gas market remains well-supplied overall. Canadian imports rose on the week as imports into the West and Midwest regions more than offset significant declines in the Northeast region. Canadian imports in the West region increased by 9 percent on the week and were about 19 percent above year-prior levels. Imports into the Midwest region posted a 34-percent gain over the preceding week, exceeding last year’s level at this time by 1 percent. Canadian imports into the Northeast region were down 46 percent on the week. Compared with year-ago levels, current U.S. natural gas production was about 0.8 percent lower, while total pipeline and LNG imports were 9 percent lower and 20 percent higher, respectively.

Natural gas spot prices at the Henry Hub are trading above year-ago levels. Prices at market locations across the lower 48 States are trading at a premium to year-ago levels. At $4.08 per MMBtu in trading on April 7, prices at the Henry Hub were 17 percent, or $0.58, above year-ago levels. Elsewhere in the lower 48 States, natural gas spot prices at most markets were trading at about 7 to 38 percent above year-ago levels.

At the NYMEX, the prices for natural gas delivery contracts through April 2011 decreased between $0.03 and $0.16 per MMBtu, or up to 4 percent, during the report week. On the week, the price of the May contract increased $0.15 per MMBtu, or about 4 percent. Overall, prices for the 12-month futures strip (May 2010 through April 2011) averaged $4.76 per MMBtu as of Wednesday, April 7, climbing about $0.11 per MMBtu, or about 2 percent on the week. Natural gas futures prices in the front months posted gains in trading each successive day between March 31 and April 5. The 12-month strip and the near-month contract peaked on the week at $5.00 per MMBtu and $4.28 per MMBtu, respectively, before posting declines in subsequent trading. Natural gas futures prices for delivery during the injection season months averaged $4.31 per MMBtu, trading at a $0.23-premium to the Henry Hub spot price. This premium suggests natural gas suppliers have an incentive to replenish inventory levels of natural gas held in storage.

Working natural gas in storage increased to 1,669 Bcf as of Friday, April 2, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure). The implied net injection was 31 Bcf, compared with last year’s net injection of 17 Bcf and the 5-year (2005-2009) average of 11 Bcf for the report week. Warming temperatures in most regions of the lower 48 States likely contributed to the larger-than-normal net injections into storage. Working gas inventories were 2 Bcf below year-ago levels and 180 Bcf above the 5-year average level. Working gas in storage exceeded the 5-year average for this time of year in each of the three storage regions. However, working gas stocks in the Producing region are 115 Bcf, or about 16 percent, below last year’s level. Since peaking on March 5 at 145 Bcf, the year-on-year storage deficit in the Producing region has declined during each successive week (see Other Market Trends).

Temperatures were generally warmer than normal in most Census Divisions in the lower 48 States during the week ended April 1. Based on the National Weather Service’s degree-day data, temperatures in the lower 48 States during the week ending April 1 were, on average, about 1.6 degrees warmer than normal and 2.1 degrees warmer than last year (see Temperature Maps and Data). Temperatures were warmest in the West South Central, South Atlantic, East South Central, and the Pacific Census Divisions, where the average temperatures were 60.3, 54.7, 53.3, and 53.3 degrees, respectively. Elsewhere in the lower 48 States, average temperatures ranged between 42 and 50 degrees. In contrast to the rest of the lower 48 States, the West South Central, East South Central, and Pacific Census Divisions reported slightly cooler-than-normal temperatures.

EIA Projects Spot Price Decreases in the April Short-Term Energy Outlook. EIA released its latest Short-Term Energy Outlook (STEO) on April 6, which includes the Short-Term Energy and Summer Fuels Outlook slideshow. According to the STEO, the Henry Hub natural gas spot price is expected to average $4.44 per MMBtu this year. Though considerably less then the average price of $5.17 per MMBtu projected for 2010 in last month’s STEO, this projection is $0.49 per MMBtu more than the 2009 average. Total natural gas consumption is expected to increase by 1.9 percent to average 63.8 Bcf per day in 2010. During the first quarter of 2010, cold weather contributed to year-over-year increases in natural gas consumption in the electric power sector. In addition, industrial consumption increased as economic conditions improved. The STEO predicts total natural gas consumption will decline by 0.6 percent in 2011, as the predicted return of near-normal weather will likely reduce residential and commercial consumption. Conversely, the STEO predicts industrial consumption will increase by 1.7 percent in 2011, likely as a result of continued economic growth. U.S. marketed production is expected to increase by roughly 1 percent to 60.9 Bcf per day in 2010 and decrease by 0.7 Bcf per day or 1.2 percent in 2011. These estimates reflect the latest January 2010 production estimate from the Form EIA-914 survey and the continuing increase in the number of working natural gas rigs over the last month.

Colorado State University Forecasters Predict Above-Average Hurricane Season. In a report released on April 7, Colorado State University researchers predicted that hurricane activity in 2010 would be greater than normal based on the premise that El Niño conditions will dissipate by the summer and above-average sea surface temperatures will prevail. The researchers predicted that 15 named storms would form in the Atlantic basin between June 1 and November 30. Of this total, eight are expected to develop into hurricanes and four of the eight will develop into major hurricanes with sustained winds of 111 miles per hours or greater. This forecast compares with the long-term average of 9.6 named storms per hurricane season, 5.9 hurricanes, and 2.3 major hurricanes. The forecast also includes a 44% chance that a major hurricane will make landfall on the Gulf Coast from the Florida Panhandle west to Brownsville, Texas (the long-term average is only 30%) and a 69% chance that at least one major hurricane will make landfall on the U.S. coastline in 2010. More information is available here: http://www.news.colostate.edu/Release/5129.

2009-2010 Heating Season Storage Recap. The 2009-2010 heating season ended on March 31, with nearly 1.7 trillion cubic feet (Tcf) of natural gas in underground storage, which is about 4 Bcf higher than last year’s level, and about 164 Bcf higher than the 5-year (2005-2009) average for this time of year, according to weekly data. The heating season began with nearly 3.8 Tcf in underground storage, a record-high volume. Somewhat unusually, net injections into underground storage continued through the month of November as a result of warmer than normal conditions, totaling 31 Bcf according to EIA’s March 2010 Natural Gas Monthly. These volumes of working gas in storage were more than sufficient to offset the increase in demand and the slight decrease in total supply compared with last year. Colder-than-normal weather between December and February spurred large withdrawals from storage, with total net withdrawals reaching nearly 2.1 Tcf. According to heating degree-day (HDD) data published by the National Weather Service, weather in the United States as a whole was between 1 and 10 percent colder than normal during months of December 2009 through February 2010. While all of the Census Divisions experienced colder-than-normal weather, areas such as the Southeast and the Northeast were particularly cold, boosting gas demand. Warmer than normal temperatures in most of the lower 48 States during March likely contributed to the early start of the injection season.

• Southern Natural Gas Company announced that it was conducting a shut-in test of its Muldon storage field in Mississippi, necessitating a force majeure between Tuesday, April 6 and Monday, April 12. The shut-in test requires Southern to allocate injection and withdrawal capacity on a pro-rated basis, allowing only 36 percent of the scheduled capacity to be available to its customers during this time, including those under firm transportation service agreements.



• Gulf South Pipeline reported that it began 5 days of maintenance on April 5 on a meter facility at its Erath receipt point in Louisiana. The receipt point, which delivers gas from Sea Robin Pipeline to Gulf South, will be unavailable for service until the maintenance is complete.



• Northern Natural Gas announced on April 1 that a reduction in the operationally available capacity at the Beatrice, Nebraska interconnect will occur as a result of excessive carbon dioxide levels delivered in the Trailblazer Pipeline. The high carbon dioxide levels caused operational issues and concerns. Northern reduced the interconnect capacity to 300,000 decatherm (Dth) per day until the gas delivered by Trailblazer meets the maximum level of carbon dioxide of 2 percent. Immediately prior to the capacity reduction, about 650,000 Dth per day of gas was flowing through the interconnect, according to the pipeline, with an annual peak of more than 1.4 million Dth per day recorded in late January 2010.

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.