Energy Report from EIA

By @ibtimes on
  • Natural gas spot prices fell over the week at most market locations, declining on average 16 cents per million Btu (MMBtu). Decreases ranged between 2 cents and 77 cents per MMBtu. In the few trading locations where prices rose, increases were modest, ranging between 1 and 4 cents per MMBtu. The Henry Hub natural gas spot price fell 10 cents on the week, closing at $4.49 per MMBtu.
  • At the New York Mercantile Exchange (NYMEX), the December 2009 natural gas contract fell 34 cents per MMBtu, or 7 percent. The November contract expired on Wednesday, October 28, at $4.289 per MMBtu.
  • Working natural gas in storage increased to 3,788 billion cubic feet (Bcf) as of October 30, according to EIA's Weekly Natural Gas Storage Report. This figure represents an implied net injection of 29 Bcf. Storage levels reached new record highs in all three storage regions, as well as on a national level.
  • The West Texas Intermediate (WTI) crude oil contract rose $2.91 per barrel, or 4 percent, ending the report week at $80.30 per barrel, or $13.84 per MMBtu.
  • The number of natural gas rotary rigs rose by 3 to 728, according to data Baker Hughes Incorporated released on October 30.

NYMEX

Prices fell almost across the board, possibly because of record-level storage stocks and somewhat warmer-than-normal temperatures in most areas of the United States west of the Rocky Mountains. On average, prices fell 16 cents per MMBtu. However, prices fell more steeply mid-week, recovering somewhat by Wednesday, November 4. The natural gas spot price at the Henry Hub settled at $4.11 per MMBtu on both Thursday and Friday of last week, recovering on Wednesday at $4.49 per MMBtu. The biggest decline of the week occurred at the Florida Gas Transmission trading point, where prices fell 77 cents to close at $4.80 per MMBtu. Three of the four trading locations where prices rose slightly were in the Northeast, where average temperatures for the week were in the 40s.

Prices in the Rocky Mountains have nearly matched or exceeded prices at the Henry Hub, likely as a result of colder weather. The natural gas spot price settled at $4.66 per MMBtu at the Northwest Sumas trading point on Wednesday, 17 cents higher than the Henry Hub price. This price differential is in sharp contrast to early in the summer, when the Northwest Sumas Hub often traded more than a dollar below Henry Hub prices. Natural gas demand in the western part of the country spiked this week, according to Bentek data, likely as a result of a snowstorm in Colorado. With other trading points following the Northwest Sumas trend, the differential between the Henry Hub and trading locations in the Rocky Mountains has largely closed.

Spot

At the NYMEX, the December 2009 contract became the near-month contract, and fell 34 cents since the previous Wednesday. The December 2009 contract settled at $4.725 per MMBtu on Wednesday, a decline of about 7 percent. The November contract expired on October 28 at $4.289 per MMBtu. During its tenure as the near-month contract, the November contract lost 55 cents, or 11 percent. The 12-month strip fell from $5.642 per MMBtu last Wednesday to $5.32 per MMBtu yesterday. During the report week, all of the contracts included in the 12-month strip (December 2009-November 2010) dropped, with declines ranging between 27 and 35 cents per MMBtu. Traders cite perceptions of robust levels of natural gas supplies for the winter, with record levels of natural gas in storage and strong production, as likely reasons for the moderated NYMEX prices.

More Price Data     Storage

Working natural gas in storage increased to 3,788 Bcf as of October 30, setting a new record level, following an implied net injection of 29 Bcf, according to EIA's Weekly Natural Gas Storage Report (see Storage Figure). This week marks the sixth consecutive record set since September 30, when inventories exceeded the previous all-time high of 3,565 Bcf recorded in the October 2007 Natural Gas Monthly. Inventories are now 379 Bcf higher than last year's level of 3,409 Bcf, and 414 Bcf above the 5-year average of 3,374 Bcf. Working gas in storage exceeds the 5-year average by 12 percent and last year's levels by 11 percent. While the storage injection season officially ends at the end of October, injections may continue into November. In fact, the last time there was not a net injection for a week ending in November was in 2002. This week's injection matched the 5-year average injection of 29 Bcf, and exceeded last year's injection of 23 Bcf.

In addition to the new national record, all three storage regions reached new record highs. The East region accounted for the majority of the net storage injection, increasing 27 Bcf. The West and Producing regions both increased by 1 Bcf. In all storage regions, working natural gas inventories are at record levels. For the second week in a row, inventories in the West Region exceed EIA's estimated peak working gas capacity, as reported in Estimates of Peak Underground Working Gas Storage Capacity in the United States, 2009 Update. Demonstrated peak capacity is a conservative measure of capacity based on the aggregation of each individual storage field's 5-year (May 2005-April 2009) historical maximum. In the East and Producing regions, inventories are at 96 and 99 percent of estimated peak working gas capacity, respectively, and 97 percent on a national level.

Temperatures during the storage report week exceed both last year's temperature and normal temperatures. In the United States as a whole, the average temperature for the week was 55.9 degrees, which is close to 2.9 degrees above normal and 4.3 degrees above last year's temperature (see Temperature Maps and Data). Only in the Mountain Census Division were temperatures cooler than both normal and last year.

Storage

More Storage Data  Other Market Trends

EIA Releases October 2009 Natural Gas Monthly. Marketed production for August reached 60.3 billion cubic feet per day (Bcf/d), according to the most recent Natural Gas Monthly  (NGM). The August 2009 level is greater than both the August 2008 level of 59.6 Bcf/d and the 5-year (2004-2008) level for August of 54.7 Bcf/d. The largest year-over-year increase occurred in Louisiana, where production increased from 3.8 Bcf/d in August 2008 to 4.6 Bcf/d in August 2009. Marketed production for the United States as a whole is slightly lower than levels reached earlier this year. However, U.S. production remains above levels in the last several years, likely as a result of production technologies, including horizontal drilling and hydraulic fracturing, allowing economically feasible recovery from shale formations. Additionally, consumption has increased year over year. At 50.6 Bcf/d, volumes of natural gas delivered to consumers in August 2009 were more than 2 percent higher than the August 2008 level of 49.3 Bcf/d. Increases in the use of natural gas for electric power, which increased by close to 10 percent since August 2008, largely drove higher consumption levels. Industrial sector consumption, on the other hand, decreased almost 8 percent year over year, falling from 17 Bcf/d in August 2008 to 15.7 Bcf/d in August 2009.

EIA Releases State-Level Energy Production Data. On October 30, 2009 EIA released a report titled, State Energy Production Estimates and State Energy Data Systems (SEDS). This report includes comprehensive production estimates of various types of energy for each of the 50 States, the District of Columbia, and the United States as a whole. This database allows review of State-level energy information, as well as quick facts and overview of each State. Tables and data included in this report offer new supply data for each production cycle. The latest production cycle (2007) includes information on fuel ethanol. Fuel ethanol production is now disaggregated from renewable energy production. Estimates for 1981 forward are calculated using State-level data on production and production capacity and national-level data on production. Estimates of State-level biomass inputs to the production of fuel ethanol, in billion Btu, are also calculated. Changes made to production, consumption, and price source data for historical years are also regularly incorporated into SEDS. SEDS also provides state energy consumption, price and expenditure estimates for the residential, commercial, industrial, transportation, and electric power sectors.  Natural Gas Transportation Update

  • Gulf South Pipeline on Wednesday, November 4, began unplanned maintenance at its Marksville Compressor Station in Avoyelles Parish, Louisiana. The company is undertaking work on two units that may affect capacity through the station by as much as 150,000 decatherms (Dth) per day for up to 10 days.
  • Southern Star Central Gas Pipeline, Inc. on Wednesday reported that it will reduce capacity on its Rawlins-Hesston Line in Kansas for maintenance following inspections conducted as part of its pipeline integrity program. Southern Star will reduce capacity through its St. Francis Station in Cheyenne County, Kansas, to 80,000 Dth per day, or about 100,000 Dth less than its normal capacity of 180,000 Dth. The pipeline company expects the capacity reduction to remain in effect until Friday, November 6.
  • Northern Natural Gas Company on Thursday, October 29, announced it will begin maintenance at a bridge in Otoe County, Nebraska, on November 9. As a result, the company will reduce its pipeline pressure in Otoe County to 100 pounds per square inch. The reduction in line pressure is scheduled through November 25, resulting in no available delivery capacity at the KN Milligan delivery point in Nebraska. The maintenance will also affect delivery capacities east of the pipeline's compressor station in Oakland, Iowa, and north of its compressor station in Palmyra, Nebraska. Capacity at through Palmyra Compressor Station will be limited to 340 million cubic feet (MMcf) per day, while capacity at the Oakland Compressor Station will be limited to 1,380 MMcf per day.
  • El Paso Natural Gas Company on Tuesday said it has scheduled pipeline testing in the San Juan Basin for November 10. The pipeline's San Juan Mainline in New Mexico will experience a capacity reduction of about 250 MMcf per day from a normal capacity of about 2,600 MMcf per day through November 12, according to the company.
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