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Overview: Thursday, August 10 (next release 2:00 p.m. on August 17, 2006)
Natural gas spot prices decreased at all locations except for one this week (Wednesday – Wednesday, August 2 - 9) as moderating temperatures contributed to lower demand. The Henry Hub spot price decreased $1.06 per MMBtu this week, or more than 12 percent, to $7.59. The price of the NYMEX futures contract for September delivery also decreased, albeit only by 15 cents since last Wednesday (August 2) to settle yesterday at $7.651 per MMBtu. Natural gas in storage as of Friday, August 4, was 2,763 Bcf, which is 15.7 percent above the 5-year average. The spot price for West Texas Intermediate (WTI) crude oil ended yesterday’s trading session at $76.28 per barrel ($13.15 per MMBtu) after increasing $0.12 per barrel (2 cents per MMBtu), or less than 1 percent, on the week.
With the easing of the temperatures across much of the Lower 48 States over the past week and the end of the threat to the Gulf of Mexico production area posed by Tropical Storm Chris, spot prices have decreased on the week at all but one trading location. Meanwhile, the Edison Electric Institute (EEI) reported yesterday that U.S. electricity demand reached a weekly record for the second time in three weeks. According to the EEI, domestic utilities delivered 98,583 gigawatt hours (GWh) of electricity for the week ended August 5, surpassing the previous single-week record of 96,314 GWh set during the week ended July 22, for a 2.4 percent increase. Since Wednesday (August 2), spot price decreases were widespread and varied widely, ranging between 2 cents and $2.23 per MMBtu. The Henry Hub spot price decreased $1.06 or 12.3 percent on the week, averaging $7.59 per MMBtu yesterday, after it began the report week at the second highest price since February 1, 2006. Spot prices at the other trading locations in Louisiana decreased by an average of $1.23 per MMBtu on the week, trading yesterday at an average of $7.70 per MMBtu. Prices at other production areas exhibited smaller decreases that averaged about 50 cents per MMBtu. On a regional basis, the Northeast saw the largest decreases ranging up to $2.08 per MMBtu. There was, however, one increase on the week, which occurred in the Arizona/Nevada trading region, where prices increased by 17 cents or about 2 percent to $7.88 per MMBtu. Despite the price declines this past week, spot prices at all reporting markets are at least $1.22 per MMBtu higher compared with prices early in July, with some locations recording increases of up to $2.34 per MMBtu.
The price of the NYMEX futures contract for September delivery decreased 15 cents since last Wednesday and settled at $7.651 per MMBtu yesterday. The October 2006 contract also decreased on the week, ending trading yesterday 18 cents or 2.2 percent lower than last Wednesday (August 2). Contracts for delivery during the upcoming heating season (November 2006 – March 2007) declined by an average of 7 cents per MMBtu this week to settle at an average of $10.885 per MMBtu. Currently, the highest priced contract is the February 2007 contract, which settled yesterday at $11.467 per MMBtu. Despite declines in the prices for the near-term delivery contracts, current market expectations resulted in price increases on the week for the remaining contracts for delivery during 2007. The April through December 2007 futures strip gained an average of 3 cents to settle yesterday at $9.256 per MMBtu. Futures contract prices for delivery during the 2006-2007 heating season continue to exceed last year’s prices for the past heating season contracts by an average of $1.573 per MMBtu. The November 2006-through-March 2007 contracts traded yesterday at an average of $10.885 per MMBtu, compared with the November 2005-through-March 2006 strip’s price of $9.654 per MMBtu on August 9, 2005. Additionally, contracts for delivery during the next heating season were trading at an average premium of $3.30 per MMBtu relative to the Henry Hub spot price yesterday, which is significantly higher than the 94-cent premium that the 2005-2006 heating season futures contracts exhibited 1 year ago.
Recent Natural Gas Market Data
Working gas in storage totaled 2,763 Bcf as of Friday, August 4, according to EIA’s Weekly Natural Gas Storage Report. Working gas inventories are roughly 16 percent above the 5-year average for the report week and about 12 percent above the level last year for the same week (See Storage Figure). For the second time in the past 3 weeks the weekly report showed a net withdrawal. Although there have been a few weekly withdrawals in the Producing and West regions during the summer months of July and August since 1994, when the weekly storage data began, this is the first time that a withdrawal has occurred in the East. The 12 Bcf net withdrawal for the week contrasts sharply with the 5-year average net injection of 61 Bcf and last year’s net injection of 42 Bcf. The unusual withdrawal reflects the impact of above-normal temperatures and the prevailing economic incentives. During the week ended August 3, the National Weather Service reported temperatures that were 42 percent warmer than normal, as measured by the cooling degree days (CDDs) (See Temperature Maps). For the report week, temperatures in each Census Division were from 13 to 104 percent higher than normal. The extremely hot temperatures that enveloped most of the Lower 48 States resulted in a record level of electric power generation, thus contributing greatly to this week’s net withdrawal. Another factor behind the storage withdrawal is the backwardation of prices for the near-month delivery contract. Although the current, relatively high, premiums between prices for winter delivery contracts on the NYMEX and spot prices at the Henry Hub would be expected to encourage the injection of gas into underground storage, the backwardation of the near-term contract price in 4 of the 5 trading days in the storage report week provided a strong incentive to draw gas from storage rather than purchasing higher price gas on the spot market.
Other Market Trends:
EIA Releases Report on Natural Gas Pipeline Expansion in 2005: The Energy Information Administration released a special report on August 8, 2006, entitled Additions to Capacity on the U.S. Natural Gas Pipeline Network: 2005. This report examines the amount of new natural gas pipeline capacity added to the U.S. natural gas pipeline system during 2005 and the areas of the country where those additions were concentrated. In addition, it discusses and analyzes proposed natural gas pipeline projects that may be developed between 2006 and 2008 and the market factors supporting these initiatives. Even though 10 fewer natural gas pipeline projects were completed in 2005 than in 2004, the average capacity addition per project increased from 187 million cubic feet per day (MMcf/d) to 264 MMcf/d, and average added natural gas pipeline increased from 36 to 37 miles per project. Additionally, in the Gulf of Mexico, the first new U.S. liquefied natural gas (LNG) import terminal in over 20 years was completed, as well as an 8-mile natural gas pipeline lateral linking it to existing offshore-to-onshore systems. Although the amount of natural gas pipeline capacity added during 2005 was only 7 percent above the 2004 level, which was the smallest annual level since 2000, the current inventory of project proposals indicates that a reversal can be anticipated over the next several years. There are 157 natural gas pipeline projects, accounting for more than 9,500 miles of potential new pipeline that have been proposed for development between 2006 and 2008 in the United States (as of June 2006). To date, 71 projects have been approved by regulating authorities and have begun, or are permitted to begin, construction, with 8 of the projects scheduled for early 2006 already completed. While 28 projects are still only in the planning, or post-open season stage, 58 have been submitted to various regulatory authorities for review. Nineteen of the latter have been submitted to FERC under the NEPA pre-filing process. As much as 77 Bcf/d of natural gas pipeline capacity would be added to the national network between 2006 and 2008, if all current proposals were completed as designed and as scheduled, although this is unlikely.
GAO Releases Findings on the Pipeline Safety Improvement Act of 2002: On August 4, 2006, the Government Accountability Office (GAO) released its findings on the Pipeline Safety Improvement Act of 2002, which established a risk-based program for gas transmission pipelines, requiring pipeline operators to identify areas where the consequences of a pipeline incident might be greatest, such as highly populated areas. Operators are required to evaluate pipelines in these areas for safety threats such as corrosion, repair or replace defective segments, and reassess their pipeline at least every 7 years. In the report, GAO provided updated information on the ongoing process. Though the process is still in its early stages, there have been improvements in pipeline safety nationwide. Up to December 2005, 182 out of 241 operators, or 76 percent, have reported baseline assessment activity and that their pipelines were in good condition, requiring only minor repairs. According to the report, as of December 31, 2005, 33 percent of the pipelines located in highly populated or frequently used areas had been assessed and over 2,300 repairs had been completed. The majority of the problems were concentrated in 7 pipelines. As a result of the improved pipeline safety, GAO estimated that up to 68 percent of the population residing close to natural gas transmission pipelines reside in highly populated areas and they can expect to receive additional protection. According to the report, the results were notable since the Act requires operators to assess their riskiest segments first and repair defects, making them safer prior to starting reassessments toward the end of the decade.
EIA Releases Its August Short-Term Energy Outlook: According to the Energy Information Administration’s (EIA) latest Short Term Energy Outlook (STEO), released on August 8, 2006, natural gas spot prices at the Henry Hub in 2006 are expected to average about $7.69 per Mcf, or $1.17 per Mcf less than the 2005 average price of $8.86 per Mcf. However, the average spot prices are expected to increase to about $8.17 per Mcf in 2007, assuming sustained high oil prices, normal weather, and continued economic expansion in the United States. During the third week in July, natural gas inventories fell by 7 Bcf, which was the first decline ever recorded during summer months (May through September) since 1994 when the weekly storage data began. Total U.S. natural gas consumption in 2006 is expected to fall about 270 billion cubic feet or 1.2 percent below the 2005 level and then increase by about 810 Bcf or 3.7 percent in 2007. Residential consumption is expected to decline in 2006 by 7.6 percent from 4.84 trillion cubic feet (Tcf) in 2005, largely because of mild weather during the early months of 2006. By 2007, residential consumption is expected to rebound to 4.88 Tcf, increasing by 9.2 percent on the year. Domestic dry natural gas production in 2006 is estimated to increase by 1.3 percent to 18.48 Tcf and by another 0.4 percent to 18.56 Tcf in 2007. Included in this months STEO is a feature article regarding the Alaska Prudhoe Bay shutdown. On August 6, 2006, BP announced the shutdown of about 400,000 barrels per day of crude oil production originating from the Prudhoe Bay field in Alaska due to corrosion in the pipeline.
Natural Gas Transportation Update:
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