xxxxx Welcome to EIA's Natural Gas Weekly Update. If you need assistance viewing this page, please call (202) 586-8800.
Home  >  Natural Gas  >  Natural Gas Weekly Update

Printer-Friendly Version 

Weekly Natural Gas Storage
U.S. Natural Gas Imports and Exports: 2004
Residential Natural Gas Prices: What Consumers Should Know
An Assessment of Prices of Natural Gas Futures Contracts As A Predictor of Realized Spot Prices at the Henry Hub
Overview of U.S. Legislation and Regulations Affecting Offshore Natural Gas and Oil Activity
Changes in U.S. Natural Gas Transportation Infrastructure in 2004
Major Legislative and Regulatory Actions (1935 - 2004)
U.S. LNG Markets and Uses: June 2004
Natural Gas Restructuring
Previous Issues of Natural Gas Weekly Update
Natural Gas Homepage
EIA’s Natural Gas Division Survey Form Comments

Overview:  Thursday, August 2, 2007 (next release 2:00 p.m. on August 9, 2007)

Natural gas spot prices increased this week (Wednesday-Wednesday, July 25-August 1) as tropical storm activity increased and weather-related demand returned along with normal summertime heat in large market areas in the East. On the week, the Henry Hub spot price increased 62 cents per MMBtu, or 11.1 percent, to $6.19. At the New York Mercantile Exchange (NYMEX), the futures contract for August delivery expired last Friday (July 27) at $6.11 per MMBtu. Although the price of the expiring contract in the last couple days of trading rose slightly, the expiration price was still the second lowest of the year (the January 2007 contract expired at $5.838). Taking over as the near-month contract, the September 2007 contract increased in price by $0.29 per MMBtu on the week to $6.352. EIA’s Weekly Natural Gas Storage Report today reported natural gas storage supplies of 2,840 Bcf as of Friday, July 27. This level of working gas in underground storage exceeds the maximum level of the previous 5 years. The spot price for West Texas Intermediate (WTI) crude oil increased $0.75 per barrel on the week to $76.49 per barrel. On a Btu basis, the crude oil price is now more than double the price of natural gas at $13.19 per MMBtu.




After dropping below $6.00 per MMBtu for all of the prior calendar week, the Henry Hub spot price increased 51 cents on Monday following reports of tropical storm activity and the return of seasonal weather in market areas. The Henry Hub price ended this report week (the week ending Wednesday, August 1) at $6.19 per MMBtu, which reflects an increase of 62 cents or 11.1 percent. As a result, the Henry Hub spot price at the beginning of August was nearly the same as it was at the beginning of July ($6.24 per MMBtu on July 1). Although Tropical Storm Chantal may have caused some jitters in the market on Monday, it will not affect production. Nevertheless, storm activity appears to be increasing, and the National Hurricane center is watching low-pressures systems in the Caribbean and Gulf of Mexico as of this writing. Meanwhile, temperatures returned closer to normal in the East, boosting demand for natural gas as a fuel for power generation to meet air-conditioning needs. For the report week, prices at production-area trading locations along the Gulf Coast generally increased between $0.48 and $0.79 per MMBtu (excluding an isolated gain of more than $1 at Florida Gas Transmission Zone 3) to a regional average of $6.24 in Louisiana and $6.02 in East Texas. Trading at Rockies production-region locations, where relatively abundant supplies lack access to markets, yielded the smallest gains of the week (as well as a net decline in price at the Kern River trading point) and continued large price differentials with other markets in the Lower 48 States. The average price in the region yesterday was $4.42 per MMBtu, or $1.77 less than yesterday’s Henry Hub price. At $3.51 per MMBtu as of Wednesday (August 1), the price at the Questar pool in Utah was the lowest in the Lower 48 and a mere 8 cents higher than the previous Wednesday. Following an average increase of 93 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 $7.20 per MMBtu, or $1.15 cents higher on the week.




At the NYMEX, the price of the futures contract for August delivery increased in the last 2 days of trading to reach $6.11 per MMBtu by its expiration as the near-month contract last Friday (July 27). Nonetheless, the August contract expired near a low-point in its trading history. For example the expiration price was $2.25 per MMBtu, 27 percent, below its high for 2007 of $8.362 (on May 17). The August 2007 contract also expired at a price substantially lower than the August 2006 price. Last year, the August contract expired at $7.042 per MMBtu, about 93 cents more than the expiration price of the August 2007 contract. During this report week, the September 2007 contract rose 29 cents per MMBtu, or about 4.8 percent, to $6.352, owing at least in part to increased storm activity and hotter weather. The prices of all futures contracts for the next 12 months all increased this week, albeit in lesser amounts than the near-month contract. As a result, the price of the 12-month strip, or the average price for contracts over the next year, increased 20.7 cents per MMBtu, or less than 2.8 percent, to $7.97. The price of the new near-month contract is $1.46 per MMBtu lower than last year’s price at this time (on August 1, 2006, the September 2006 contract settled at $7.574 per MMBtu). The difference between the current Henry Hub price and the price for the NYMEX contract for delivery this January (the month that is normally the highest price in the 12-month strip) is now $2.57 per MMBtu, providing a substantial economic incentive to place natural gas in storage for delivery next winter.


Recent Natural Gas Market Data



Working gas in underground storage was 2,840 Bcf as of July 27, which is 16.9 percent above the 5-year average inventory level for the report week, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure). Current inventory levels are now 68 Bcf more than at this time last year and 410 Bcf higher than the 5-year average. The implied net change for the week was 77 Bcf, which is significantly higher than both the estimated net injection of 15 Bcf last year at the same time and the 5-year average of 51 Bcf. 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 temperatures were significantly lower relative to normal in most Census Divisions (see Temperature Maps).  For the United States as a whole, CDDs totaled about 16 percent less than normal, which would have lowered weather-related gas demand. In the West South Central Division, which includes Texas’ numerous gas-fired power plants, CDDs were 22 percent less than normal.  Temperatures in Census Divisions in populous regions including the Northeast were also lower than normal. In the Middle Atlantic Census Division, for example, CDDs numbered 25 percent lower than normal during the report week.




Other Market Trends:

NEB Releases Study on Hydrocarbon Pipeline Capacity: According to the July 27, 2007, National Energy Board (NEB) study, Canadian crude oil pipelines could be facing a transportation bottleneck this fall, as there likely will not be enough pipeline capacity to transport the crude oil produced in Alberta’s oils sands. Natural gas pipelines, on the other hand, have spare capacity even during winter, when demand for natural gas hits seasonal peaks. The report notes that between January 2003 and January 2007, there has consistently been capacity in excess of throughput volumes, which persisted through the warmer-than-normal summers of both 2005 and 2006, as well as following hurricane induced production losses in the Gulf of Mexico. Both circumstances resulted in an increase in demand for Canadian natural gas in the United States. The eastern part of the TransCanada system, which connects to U.S. pipelines in New England (at Iroquois and Niagara Falls), underwent a number of expansions in 2006 that are directed towards connecting to additional supply from Dawn, Ontario, and to access markets in the U.S. Northeast. This resulted in average excess capacity of 1.4 Bcf per day over the past 4 years. Similarly, the average annual capacity utilization on TransCanada’s Foothills Pipeline, which connects to markets in the Midwest (through the Northern Border Pipeline), was 88 percent in 2006, a significant decrease from an average of 94 percent in 2003. TransCanada’s B.C. (British Columbia) system, which primarily serves California, showed an annual average capacity utilization of 64 percent in 2006, slightly higher than in previous years despite competing with supplies from the Rocky Mountains, and San Juan and Permian basins.


Natural Gas Transportation Update:

        Northern Natural Gas Company declared a force majeure on July 30 reporting that it is investigating a possible leak on the 26-inch C East Leg pipeline east of the Earlville, Iowa, compressor station. As a result of the force majeure, the company lowered the line pressure in order to inspect the pipeline and determine if there is any damage. As a result, primary firm service is being allocated as of the July 31 gas day. The force majeure is expected to remain in place until the repairs have been completed, which should occur by August 4 according to the pipeline.

        Questar Pipeline Company reported experiencing mechanical failure at its Greasewood compressor station, as a result of which nominations to Trans Colorado Interstate Pipeline were reduced to 30,000 decatherms (Dth) per day on July 26. Because the repairs were completed the same day, the pipeline was able to increase the capacity at the  interconnect to 45,000 Dth the same day.

        Questar also announced that owing to seasonal operating conditions, it reduced the injection capacity at its Clay Basin Storage Facility to 325,000 Dth per day. Additionally, 25,000 Dth per day of capacity will be available for park and loan. The new capacity was effective with the cycle 1 gas day August 2 and is expected to last until November 1, 2007. 

        Pacific Gas and Electric issued a systemwide Stage 2 high inventory operational flow order (OFO) for Saturday, July 28. Penalties were set at $1 per Dth for exceeding a 5 percent tolerance level for positive daily imbalance.

        Sea Robin Pipeline issued an OFO for all offshore receipt points for Saturday, July 28, through Monday, July 30. The OFO resulted from imbalances that existed at the time, along with those that continued to build, leading to an unacceptable increase in pressure.

        ANR Pipeline Company announced on Monday that it began unplanned engine repairs at the St. John Compressor Station in Indiana, located in the northern fuel segment. The total St. John west-east capacity was reduced by 115 MMcf per day on August 1, leaving 1,190 MMcf per day available.



 Short-Term Energy Outlook