Overview:  Thursday, July 12, 2007 (next release 2:00 p.m. on July 19, 2007)

 

Natural gas spot prices increased during this holiday-shortened report week (Thursday-Wednesday, July 5-11) as weather-related demand emerged in response to the hottest temperatures to date this year in the Northeast and Midwest. On the week, the Henry Hub spot price increased 36 cents per MMBtu, or 5.7 percent, to $6.65. At the New York Mercantile Exchange (NYMEX), the story was slightly different with the contract price for August delivery decreasing to $6.600 per MMBtu, which was 1.8 cents lower than last Thursday’s (July 5) closing price. EIA’s Weekly Natural Gas Storage Report today reported natural gas storage supplies of 2,627 Bcf as of Friday, July 7. This level of working gas in underground storage is 16.6 percent above the 5-year average inventory for this time of year. The spot price for West Texas Intermediate (WTI) crude oil increased $0.77 per barrel on the week to $72.58 per barrel. On a Btu basis, the crude oil price is now nearly double the price of natural gas at $12.51 per MMBtu. The relative difference in pricing can have a large effect on demand (mostly in the industrial sector and power plants).

 

 

 

Prices:

Although the Henry Hub price of $6.15 per MMBtu on Friday (July 6) was at its lowest level since January, price increases in the 3 consecutive trading days since the weekend resulted in a net increase for the report week. The price at the Henry Hub yesterday (July 11) was $6.65 per MMBtu, or 36 cents more than last Thursday’s price. The increase reversed the past month’s downward trend in prices, as moderate temperatures dominated the weather picture for much of the country and underground storage inventories rose to comfortable levels for this time of year. At least briefly this week, mild temperatures gave way to above-normal temperatures in the Midwest and Northeast, boosting demand for natural gas as a fuel for power generation to meet air-conditioning needs. Prices at production-area trading locations along the Gulf Coast generally increased between $0.27 and $0.96 per MMBtu to a regional average of $6.64 in Louisiana and $6.44 in East Texas. Highly-variable pricing continues to characterize Rockies production-region trading locations, where relatively abundant supplies lack access to markets, resulting in large price differentials with other markets in the Lower 48 States. The average price in the region yesterday was $4.74 per MMBtu, or almost $2 less than the Henry Hub price. For the report week, prices at Rockies markets also represented the only declines in the country. At $3.60 per MMBtu as of Wednesday (July 11), the price at the Questar pool in Utah was 85 cents lower than the previous Thursday, representing the largest weekly decrease in the Rockies and also the lowest price in the country. Following an average increase of 39 cents per MMBtu for the week in the Northeast, prices at some trading locations exceed $7. Off Transcontinental Gas Pipe Line in New York City, the average price yesterday was $7.23 per MMBtu, or 39 cents higher on the week. Although price decreases characterized much of the springtime, there are still factors that could lead to rising prices this summer. Being only 3 weeks into the official summer season, plenty of time remains for episodes of hot temperatures in the next few months.  Competing petroleum products (as evidenced by an increase in the underlying crude oil price) continue to trade at near-record prices. Additionally, the hurricane season may yet become active and result in hurricanes that could disrupt production in the Gulf of Mexico region.

 

 

 

At the NYMEX, the price of the futures contract for August delivery decreased in three of four trading sessions this week, but posted a net decrease on the week of just 1.8 cents per MMBtu. The contract’s price at the end of trading yesterday was $6.600 per MMBtu, which is 21 percent lower than the August contract high this year (reached in May) of $8.362. All futures contracts through the end of the next heating season also decreased on the week, while the contract prices from April 2008 through July 2008 were slightly higher. As a result, the price of the 12-month strip, or the average price for contracts over the next year, dropped 4.2 cents per MMBtu, or less than 1 percent, to $7.786. The price of the near-month contract is $0.967 per MMBtu higher than last year’s price at this time (on July 11, 2006, the August 2006 contract settled at $5.633 per MMBtu). At this time last year, the difference between the Henry Hub price and the price for the NYMEX contract for delivery the following January (the month that is normally the highest price in the 12-month strip) had widened to $4.51 per MMBtu, a spread that was highly unusual. The corresponding spread this year is still atypically high, but is narrower at $2.07 per MMBtu. Currently, the January 2008 contract is priced at $8.722 per MMBtu.

 

Recent Natural Gas Market Data

 

Estimated Average Wellhead Prices
	Dec-06	Jan-07	Feb-07	Mar-07	Apr-07	May-07
Price ($ per Mcf)	6.65	5.92	6.66	6.56	6.84	6.98
Price ($ per MMBtu)	6.48	5.76	6.48	6.39	6.66	6.80
Note: Prices were converted from $ per Mcf to $ per MMBtu using an average heat content of 1,027 Btu per cubic foot as published in Table A4 of the Annual Energy Review 2002.
Source:  Energy Information Administration, Office of Oil and Gas.

 

 

Storage:

Working gas in underground storage was 2,627 Bcf as of July 6, which is 16.6 percent above the 5-year average inventory level for the report week, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure).  The implied net change for the week was 106 Bcf. However, it should be noted the implied net change was affected in this week’s report by a reclassification of 10 Bcf from base to working gas. Without this reclassification, the implied net change would have been equal to the 5-year average (2002-2006). The report’s implied net change also was higher than the implied injection of 86 Bcf last year at the same time (calculated through an interpolation of EIA data). As a result, current inventory levels are now just 64 Bcf less than at this time last year but 374 Bcf higher than the 5-year average. (The percentage difference between current storage levels and the 5-year average declined slightly because of the increase in the total amount of natural gas in underground storage). Cooling degree-day (CDD) statistics published by the National Weather Service for the period roughly coinciding with the week covered by the storage report show that weather-related gas demand likely was low relative to normal in most Census Divisions (see Temperature Maps). For the United States as a whole, temperatures totaled about 9 percent less than normal. Temperatures in Census Divisions in populous regions that would affect weather-related demand for natural gas were significantly cooler than normal. For example, the East North Central, which includes Chicago and other major metropolitan centers, experienced weather that was 39 percent cooler than normal during the report week.

 

 

 

Other Market Trends:

EIA Releases July 2007 Short-Term Energy Outlook: In its latest Short-Term Energy Outlook (STEO), released July 10, the Energy Information Administration (EIA) projects that the Henry Hub spot price will average $7.66 per thousand cubic feet (Mcf) in the third quarter of 2007 and $8.79 per Mcf in the fourth quarter. On an annual basis, the Henry Hub spot price is projected to average $7.91 per Mcf in 2007, increasing 98 cents per Mcf over the 2006 average. These prices are based on the assumption that near-normal temperatures will prevail during the third quarter of 2007.  Population-weighted cooling degree-days (CDD) are projected to number 788 between July and September, a significant decline compared with the same quarter of 2006. With natural gas serving as a primary fuel source for meeting peak demand for summer cooling, temperatures will continue to play a key role in determining natural gas consumption throughout the third quarter. While the 2007 second quarter consumption increased 2.9 percent over the corresponding period of 2006 because of colder-than-normal weather and increased gas-fired electric power generation, the third-quarter 2007 consumption is projected to decline year-over-year. On an annual basis, however, total natural gas consumption is expected to increase by 4.3 percent in 2007 and 1.1 percent in 2008. The projection incorporates possible hurricane-induced production disruptions in the Gulf of Mexico with a reduction in production of 85 Bcf this summer.  The 2007 total dry natural gas production is expected to increase by 0.3 percent. Total Federal Gulf of Mexico production is expected to decline by 4.9 percent in 2007, but increase by 8.1 percent in 2008. Liquefied natural gas (LNG) imports are expected to remain strong through the end of 2007, increasing 44 percent above the volume imported in 2006. Total LNG imports in 2007 and 2008 are projected to reach 840 and 1,020 Bcf, respectively.

 

Natural Gas Transportation Update:

●        Southern California Gas Company declared a high linepack operational flow order (OFO) for Saturday, July 7, assessing buy-back charges to shippers who deliver more than 110 percent of their actual usage into the pipeline system.

●        Pacific Gas and Electric Company declared a systemwide stage 2 high-inventory OFO for Tuesday, July 10. The penalties were set at $1 per decatherm (Dth) for volumes exceeding an 11-percent tolerance level for positive daily imbalances.

●        Florida Gas Transmission Company declared Saturday and Sunday (July 7-8) overage alert days (OAD) with a 25 percent tolerance for negative daily imbalances. The pipeline extended the OAD for Monday, tightening the tolerance to 15 percent.

●        Northwest Pipeline Corporation is conducting pig runs on July 11 and 12 between the Lava and Pocatello compressor stations in Idaho. The pipeline noted that if the net primary nominations north through the Lava compressor station exceed the available capacity of 628,000 Dth per day, Northwest will have to declare a deficiency period and decrease nominations accordingly; if the net primary north nominations exceed the design capacity of 640,000 Dth per day, the company will issue an OFO.

●        Transcontinental Pipeline Company is removing a section of line downstream of the Sabine River from service, limiting the amount of available transportation capacity through this area of the system. Effective gas day Thursday, July 12, and until early August, Transco will limit nominations to shippers using primary capacity under the firm transportation rate schedule for gas received upstream and delivered downstream of compressor station 40. Total scheduled quantity at the Sabine River will be limited to 625,000 Dth per day for natural gas received upstream and delivered downstream of Sabine River. The pipeline replacement will affect about 100,000 Dth per day.

 

 

 Short-Term Energy Outlook