• Natural gas spot prices rose at nearly all market locations in the lower 48 States since last Wednesday, July 28. A few exceptions to these increases occurred in trading locations that serve markets in California as well as a few other locations scattered around the lower 48. Prices at most market locations rose between 5 and 15 cents per million Btu (MMBtu) this week; however, some locations registered significantly higher increases.



• At the New York Mercantile Exchange (NYMEX), the futures contract for September delivery at the Henry Hub ended trading yesterday at $4.737 per MMBtu, decreasing by 4 cents or about 1 percent during the report week.



• Natural gas in storage increased to 2,948 billion cubic feet (Bcf) as of July 30, following a 29-Bcf net injection. The latest net injection brings the current inventories to 8.1 percent above the 5-year (2005-2009) average, and 4.3 percent below last year’s total volume.



• The spot price for West Texas Intermediate crude oil also rose on the week, increasing by $5.43 since Wednesday, July 28, to $82.49 per barrel or $14.22 per MMBtu.

Summer temperatures engulfed much of the country this week, with continued power demand likely supporting price movements this week in spot markets. The short-lived tropical storm Colin served as yet another reminder of the 2010 Atlantic hurricane season, marking the second tropical storm formation in 3 weeks. However, the increase in price this week may likely be a response to the hot weather, particularly in areas that consume natural gas for electric power generation, such as areas along the Gulf of Mexico coast and the Southeast. Other factors perhaps only limited the increases in price, including continued robust production. Since last Wednesday, spot prices increased at almost all market locations in the lower 48 States, with a few exceptions, most notably at locations that serve markets in California. Most of the locations that registered price increases rose between 5 and 15 cents per MMBtu. The Henry Hub spot price rose by 2 cents or less than one half of 1 percent, ending the report week at $4.77 per MMBtu.

The Florida Gas Transmission (FGT) trading location registered the highest weekly increase, rising $5.80 per MMBtu since last Wednesday in response to the summer heat in Florida. The price increase during the latest report week nearly doubled the price of natural gas at this location, which ended trading yesterday at $13.66 per MMBtu, the highest price at this location since the beginning of this year. Furthermore, the natural gas spot price at FGT was the highest-priced location in the lower 48 States, far exceeding prices at all other locations, which ended trading yesterday between $3.84 and $5.35 per MMBtu.

Spot prices in the West registered decreases, as did a few other scattered points in the lower 48 States. Price decreases ranged between 1 and 20 cents per MMBtu in the Rockies and west of the mountain range. At the Pacific Gas and Electric spot location, which serves southern California markets, the price fell 10 cents or 2 percent on the week, ending trading yesterday at $4.33 per MMBtu. As of yesterday, the Rockies and California were the lowest priced locations in the lower 48 States, likely as a result of the lower demand in those areas. Furthermore, Canadian imports into the West remained fairly steady during the week, decreasing only by 1 percent while demand remained stable as well.

Summer heat and the increased power burn in some areas of the country supported relatively high demand this week; however, total natural gas demand registered a 2.5-percent decrease this report week compared with the previous week, according to estimates from BENTEK Energy Services, LLC. The decrease in residential and commercial consumption likely led this week’s slide, as it fell by 7 percent since last week. Furthermore, total natural gas power burn fell by 2.2 percent on the week, despite the increase in natural gas use for electric power generation in the Gulf. In fact, demand fell in each of the sectors this week. Despite the slight decrease in demand this week compared with last, total demand remained well above year-ago levels, exceeding last year’s by more than 10 percent, according to BENTEK data. During the latest report week, natural gas demand for electric power generation exceeded last year’s by 19.4 percent.

Natural gas supply reversed last week’s slight declines and rose 1.7 percent, driven by the increase in domestic production. According to BENTEK flow data, natural gas daily production reached 61.9 Bcf on August 2, a very high level of production. The all-time peak may actually have occurred in February of 1973 when, according to EIA monthly production statistics, marketed production set a record-high of 70.1 Bcf per day. This is a daily average over the month, suggesting that there may have been individual days exceeding the monthly average. According to EIA, marketed production reached 62.0 Bcf per day and 61.9 Bcf per day in April and May 2010, respectively. Imports of natural gas by pipeline from Canada and of liquefied natural gas from other countries were significantly lower than both last week and last year.

At the NYMEX, the price of the contract for September delivery decreased by 4 cents per MMBtu, ending trading for this report week at $4.737. The decline in the price of the near-month contract was in contrast to both price increases in the spot market as well as futures contracts for delivery during the remainder of this calendar year. The decrease in price was also somewhat surprising since prices for associated energy products, such as natural gas liquids and crude oil, increased on the week. The October 2010 futures contract, the last contract for delivery during the current injection season, ended the week at $4.756 per MMBtu, 4 cents higher than last Wednesday. The 12-month strip, which is the average of futures contracts for delivery through August 2011, traded at $5.039 per MMBtu or 1 percent higher compared with the previous Wednesday.

Working natural gas in storage increased to 2,948 Bcf as of Friday, July 30, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure). The implied net injection was 29 Bcf, compared with last year’s net injection of 67 Bcf and the 5-year average of 47 Bcf for the report week. Working gas inventories are currently 132 Bcf below year-ago levels and 221 Bcf above the 5-year average level. Working gas in storage has exceeded the 5-year average for this time of year in each of the three storage regions since March 26, 2010, or the last 19 weeks.

Significantly warmer-than-normal temperatures throughout the summer have contributed to declines in the surplus of working gas stocks relative to the 5-year average. Since May 6, cumulative cooling degree-days have exceeded normal levels by nearly 27 percent, outstripping normal levels during each week. Increased electric generation demand for natural gas, as a result of these warmer than normal temperatures, likely contributed declines in the surplus relative to the 5-year average. While natural gas stocks remain significantly above historical levels, the surplus relative to the 5-year average has diminished in recent weeks, with this week marking the seventh week in a row that the surplus relative to the 5-year average has declined. This surplus last peaked on May 7, 2010, at 325 Bcf. Most of the decline since May 7 occurred in the East region, where the surplus has fallen for 13 consecutive weeks, from 145 Bcf on May 7 to 16 Bcf as of July 30.

Temperatures were warmer than normal in most of the Census Divisions in the lower 48 States during the week ending July 29. Based on the National Weather Service’s degree-day data, temperatures in the lower 48 States during the week ending July 29 were, on average, around 75.6 degrees, about 2.9 degrees warmer than normal and 2.7 degrees warmer than last year at this time (see Temperature Maps and Data). Temperatures were warmest relative to historical levels in the Middle Atlantic, South Atlantic, and East South Central Census divisions, ranging between 5 and 6 percent warmer than normal levels. Temperatures in the West South Central, Mountain, and Pacific Census Divisions were less than 1.5 percent above normal levels. Elsewhere in the lower 48 States, temperatures were about 2 to 5 percent above normal.

Natural Gas Production Sets a Record for May. On Thursday, July 29, EIA released the Natural Gas Monthly (NGM), which includes data through May 2010. Natural gas consumption totaled 52.4 Bcf per day, a decrease of about 7 percent from the previous month. The decline was largely due to a decrease in residential consumption, as weather became warmer. Heating degree-days in May averaged 159 for the United States as a whole, compared to 346 in April. Residential consumption fell from 10.8 Bcf per day in April to 6.6 Bcf per day in May. Commercial consumption also fell from about 7.4 Bcf per day to 5.3 Bcf per day. Use of natural gas for electric power generation increased, as customers in warmer climates began to use air-conditioning. Wellhead prices rose slightly, from $4.03 per MMBtu to $4.15 per MMBtu. Natural gas marketed production remained robust but dropped slightly from 62.0 Bcf per day in April to 61.9 Bcf per day in May. In fact, marketed production was the highest level recorded for the month of May for as far back as EIA has data. Working natural gas in storage was 2,421 Bcf as of the end of May, according to the NGM. This reflects 409 Bcf of net injections during May.

Government and Industry Continue to Respond to Oil Spill in the Gulf of Mexico. Response continues to the oil spill following the April 20 explosion aboard the Deepwater Horizon mobile offshore drilling unit. The rig was located about 50 miles southeast of Venice, Louisiana. Some of the latest information (according to status reports from the Administration-wide response, unless where otherwise noted) include:

• Efforts to stop the leaking well via a procedure called “static kill” appear to be working. The procedure involves pumping mud into the blown-out well.


• National Incident Commander Admiral Thad Allen authorized BP to cement its damaged well, pending success of the static kill procedure.


• The team of experts leading the response has emphasized the importance of the completion of the relief well. When BP finishes drilling the relief well, mud will be pumped in and the well will be cemented.


• According to estimates from scientists from the Department of the Interior and the National Oceanic and Atmospheric Administration, about 74 percent of the oil from the Deepwater Horizon incident has evaporated or been burned, skimmed, recovered from the wellhead, or dispersed. The remaining 26 percent includes oil that is on or just below the surface, has washed ashore, or been collected from the shore. The analysis was based on an estimated release of 4.9 million barrels of oil.


• The Administration continues to oversee repayment to Americans who have suffered financial losses as a result of the oil spill. As of August 4, a total of 141,690 claims had been opened and more than $293 million had been disbursed.

More information about the ongoing response is available at http://www.deepwaterhorizonresponse.com.

Colorado State Researchers Maintain Previous Forecast and Predict Active Hurricane Season. In a forecast released August 4, researchers at Colorado State University maintained their forecast from June 2010, calling for a very active hurricane season. According to the researchers, 2010 will have 10 named hurricanes (compared with an average of 5.9) and 18 named storms (compared with an average of 9.6). Additionally, the new forecast predicts the probability of U.S. major hurricane landfall and Caribbean major hurricane activity to be well above normal. The forecast cites a 49 percent chance that a major hurricane will make landfall on the Gulf Coast (the long-term average is 30 percent.) More information about the forecast is available at http://typhoon.atmos.colostate.edu/.

Prices, Investment, and Drilling Technology Drive Barnett Shale Production Growth. Despite a sharp decline in Henry Hub spot prices from the levels reached in the summer of 2008, natural gas production in the Barnett shale in Texas continued to climb through the middle of 2009 and appears to have reached an undulating plateau since then. Production growth in the Barnett shale comes from several large natural gas producers who continued to maintain strong production even in an environment of relatively low natural gas prices (see Figure).

During 2005-2008, growth in the Barnett shale production was driven by high natural gas prices, successful application of horizontal drilling, and hydraulic fracturing, as well as significant investments made by natural gas companies in production assets and state-of-the-art technology. When natural gas prices declined sharply in the second half of 2008, the momentum in production growth continued, in part because of the 3-6 month lag generally observed between changes in prices and a production response. As natural gas prices continued to decline in 2009, so did the number of drilling rigs. However, despite more than a 60 percent reduction in the number of drilling rigs from the peak levels in 2007-08, production in the Barnett shale remained high due to several factors:

• Increased per-unit production output as a result of improved production efficiencies from horizontal drilling (which allows multiple horizontal wells to be drilled from a single rig) and an improved understanding of how natural gas is produced from this formation.


• Large operators hedged a significant portion of their natural gas production on the futures market when natural gas prices were higher.


• Significant capital investments in acquiring technologies, leases, etc., combined with the resultant large debt, required continuous production so operators could service the debt.


• Contractual lease obligations require operators to continue drilling or risk losing leases.


• High initial production rates in the Barnett shale wells decreased the number of drilling rigs required to maintain and even to increase natural gas production output.

• Tennessee Gas Pipeline Company yesterday (August 4) said it is mobilizing equipment and manpower for emergency repairs at its Compressor Station 703 in Mansfield, Louisiana. Current repair estimations indicate that the unit will be returned to service by Saturday, August 7. The outage may still result in volume restrictions on Tennessee’s Carthage Line Lateral in East Texas, based upon scheduled volumes and pipeline conditions, the pipeline company said.



• Gulf South Pipeline Company, LP, on Wednesday reported that it would undertake immediate maintenance at its Airport Compressor Station in Mobile County, Alabama. The Airport Compressor Station will be out of service until further notice, with deliveries to both Gulfstream Pipeline and Florida Gas Transmission reduced as a result. Separately, Gulf South said it would be performing maintenance at the Montpelier Compressor Station in Louisiana. Maintenance will begin Thursday, August 12, 2010, and continue for approximately 21 days. Based on current system operations and nominations, Gulf South does not anticipate any impact on shippers.



• El Paso Natural Gas Company this week reminded shippers that it would be conducting maintenance on its South Mainline in August. The maintenance will result in the reduction of base capacity through the compressor station in Lordsburg, New Mexico, by 555 million cubic feet (MMcf) per day from August 10 to August 13. (El Paso’s base capacity will fall to around 1,200 MMcf per day from 1,700 MMcf per day through the station). Flows in the last week have averaged just under 900 MMcf per day, according to BENTEK Energy.

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.