• Natural gas spot prices at most market locations in the lower 48 States decreased between 5 and 10 percent this report week (Wednesday to Wednesday, September 22–29). The week coincided with the first week of fall, a season in which demand is typically lower given the lack of extreme weather conditions across the country. During the report week, the Henry Hub spot price decreased by $0.21 per million Btu (MMBtu), or 5 percent, to $3.81 per MMBtu.



• The price of the October futures contract at the New York Mercantile Exchange (NYMEX) at final expiration on September 28 was $3.84 per MMBtu, or about 3 cents more than the price of the contract at the end of its first day of trading as the near-month contract on August 30. The November contract finished the report week at a price of $3.96 per MMBtu, or 13 cents lower than the previous Wednesday.



• During the week ending Friday, September 24, estimated net injections of natural gas into underground storage totaled 74 billion cubic feet (Bcf). Working natural gas in underground storage was 3,414 Bcf, which is 6.3 percent above the 5-year (2005-2009) average.



• The West Texas Intermediate (WTI) crude oil spot price increased $4.87 per barrel during the report week. The WTI crude oil spot price averaged $77.85 per barrel yesterday (September 29), or $13.42 per MMBtu.

Moderate weather, high storage levels, and a lack of hurricane activity were all likely factors in most spot prices falling this report week. Decreases ranged between 6 and 34 cents per MMBtu, or about 5 to 10 percent of price levels. At the Henry Hub, the spot price decreased 21 cents per MMBtu over the report week to $3.81 per MMBtu yesterday. Other trading locations in the producing region along the Gulf Coast in Louisiana and East Texas recorded decreases that averaged 25 cents per MMBtu, or about 6 percent, for an average price in the region of $3.76 per MMBtu. The decreases in prices likely resulted in part from lower demand. With the hottest temperatures of the year clearly past, consumption fell 2.8 percent on the week, according to estimates by BENTEK Energy, LLC, which tracks flows on the interstate pipeline grid for indications of changes in supply and demand. In the electric power sector specifically, consumption fell 8 percent compared with the previous week. At the same time, U.S. production increased from the prior week by an estimated 0.8 percent, averaging 62 Bcf per day.

Although prices generally decreased for the report week for markets in the lower 48 States, there were variations in price movements between regions. The only trading locations to record week-on-week increases were in the Rocky Mountain region, which experienced higher demand for supplies to be delivered into the Southwest and California. Price increases occurred at eight Rocky Mountain trading locations, with some gains exceeding $0.20 per MMBtu, or up to 10 percent. For example, the price on Questar Pipeline in Utah increased by $0.29 on the week to $3.34 per MMBtu, while the price at the Opal Hub in Wyoming increased 22 cents to $3.50 per MMBtu. Increased demand in the Southwest and California for electric power likely supported the price increases in part, as temperatures in much of the Southwest and parts of California exceeded 100 degrees for a couple of days during the report week.

In contrast, some of the largest price decreases during the report week occurred in Northeast markets, where cooler weather prevailed. Market prices posted decreases of as much as 7 percent on the week. For delivery in Zone 6 into New York off Transcontinental Gas Pipeline (Transco), the price on Wednesday, September 29, reached $4.09 per MMBtu, a decrease of 29 cents, or almost 7 percent, from the start of the report week. Trading at the Intercontinental Exchange, Inc. (ICE), continues to suggest that a much lower price spread between the Northeast and the Henry Hub is developing. The price for deliveries to Transco Zone 6 in January 2011, for example, is currently priced about $2.02 per MMBtu over the Henry Hub price in ICE trading, while last year at this time the premium was about $3.42. This lower differential is likely because of more supply options for the region, including growing supplies in the Marcellus Shale, access to Rockies supplies, and regasified liquefied natural gas (LNG) from the Canaport LNG terminal in Canada.

At $3.81 per MMBtu, the price at the Henry Hub on Wednesday, September 29, was 15 percent higher than at this time last year, when cash prices reached extreme lows amid a perception of a possible oversupply situation with storage levels at record highs. Natural gas held in storage is once again relatively high compared to recent history at 3,414 Bcf (as of September 24), which is 202 Bcf above the 5-year average (see Storage section below). However, the level is still 166 Bcf, or 4.6 percent less than last year’s level at this time, potentially contributing to prices being somewhat higher than last year. In addition, this year’s high levels of consumption likely provide further explanation for higher prices. According to BENTEK, total U.S. demand is up 4.2 percent to date this year in comparison with 2009, with the electric power and industrial sectors accounting for the entire increase (residential and commercial consumption is down year-to-year). Additionally, demonstrated peak working gas capacity for U.S. underground working natural gas storage for the lower 48 States continues to expand, making a scenario of no available storage capacity less likely.

At the NYMEX, the price of the October 2010 contract decreased a net $0.18 per MMBtu during its last three days of trading to expire at $3.84. This expiration price was just 3 cents per MMBtu higher than the price of the contract in its opening day of trading as the near-month contract and near its low point in trading over the past month ($3.76 on September 1). Nonetheless, the October 2010 contract settled about 5 percent higher than the September 2010 contract expiration price of $3.65 per MMBtu and 3 percent higher than the October 2009 contract expiration price of $3.73.

The price of the November 2010 futures contract during the report week decreased 13 cents per MMBtu to $3.96, likely in part because of the lack of hurricane activity amid continuing strong domestic production. The new near-month contract is now priced about 3 percent higher than the expiration price of $3.84 per MMBtu for the October 2010 contract. Similarly, contract prices increase through March 2011, so that the average price for delivery this heating season (November 2010-March 2011) is $4.23 per MMBtu, a premium of 42 cents to the current spot Henry Hub price. The 12-month strip, which is the average price of natural gas futures contracts over the next year, ended trading yesterday at $4.33 per MMBtu, which was $0.11 lower than the price of the strip last week. The current price of the November 2010 contract is about $0.32 per MMBtu lower than the final price of the November 2009 contract.

As of Friday, September 24, working natural gas in storage totaled 3,414 Bcf, according to the Weekly Natural Gas Storage Report (see Storage Figure). Working gas stocks increased 74 Bcf during the report week, compared with last year’s injection of 65 Bcf and the 5-year average (2005-2009) injection of 67 Bcf. Working gas in storage is now 202 Bcf, or 6.3 percent, greater than the 5-year average level, and 166 Bcf, or 4.6 percent, below last year’s level. The Energy Information Administration (EIA) expects that working gas in storage will end the injection season with levels of 3,687 Bcf at the end of October, as reported in the Short-Term Energy Outlook. At these levels, working gas stocks will end the refill season 120 Bcf below last year’s record end-of-October levels of 3,807 Bcf, and about 203 Bcf above the 5-year average of 3,484 Bcf. Working natural gas in storage currently exceeds the 5-year average level in all three of the storage regions.

Temperatures in the lower 48 States were generally mild during the storage report week, with an average U.S. temperature of 69 degrees. Milder weather often results in reduced heating and cooling-related consumption and more gas in storage. Temperatures were about 3 degrees warmer than the 30-year normal, and about 1 degree warmer than last year’s level (see Temperature Maps and Data). Temperatures were warmer than both the normal level and last year’s levels in all Census Divisions except the Pacific. The coolest weather was in New England, where temperatures averaged 61 degrees. They were warmest in the West South Central, where temperatures averaged 79 degrees for the week.

Royalty-in-Kind (RIK) Program Ends Today. The RIK Program has allowed producers to pay royalties to the Federal Government by delivering oil and gas to the Government instead of sending in checks. The RIK Program will end September 30 when the Federal Government closes the books on the 2010 fiscal year. Existing contracts allowing payment by producers in physical oil and gas rather than cash expire today. A transition phase-out has been underway for the past year. In a September 24 press release, the Director of the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEM) said: “The work we have done to successfully end the RIK program only enhances our continued efforts to eliminate the real and perceived conflicts of interest as we fulfill our regulatory oversight and revenue collection responsibilities.”

Marketed Production Rises to 61.2 Bcf per Day in July. On September 29, EIA released the September 2010 Natural Gas Monthly with data through July 2010. Natural gas marketed production rose to 61.2 Bcf per day in July, its highest recorded level for the month in the 38 years for which there are data. Marketed production remained essentially flat from its June 2010 level of 61.1 Bcf per day, but rose 3 percent year-over-year from July 2009. The wellhead price rose slightly from June, from $4.37 per MMBtu to $4.38 per MMBtu. The July wellhead price this year was almost a dollar higher than its level 1 year ago. Total natural gas consumption rose from the previous month, from 54.9 Bcf per day in June to 58.6 Bcf per day in July. The increase was driven largely by an increase in electric power consumption; cooling degree-days totaled 385 in the United States as a whole, almost 20 percent greater than the 30-year average level of 321. Year-over-year, July consumption of natural gas for electric power generation increased 15 percent, from 25.2 Bcf per day in 2009 to 28.9 Bcf per day in 2010. Exceptionally warm weather likely drove demand for electric power generation. Industrial, commercial, and residential consumption all fell somewhat from June to July.

Net Imports of Natural Gas to U.S. Reach Lowest Level since 1994. According to U.S. Natural Gas Imports & Exports: 2009, which EIA released September 28, imports totaled 2.7 trillion cubic feet (Tcf) in 2009, accounting for only about 12 percent of U.S. natural gas consumption. The decrease in net imports was the result of a decline in gross imports and an increase in gross exports, according to EIA. The primary reason underlying the decline in imports was strength in domestic natural gas production in the lower 48 States. Dry natural gas production rose 3.3 percent in 2009 from the previous year. Additionally, consumption in 2009 declined, also resulting in reduced demand for imports. While LNG gross imports increased close to 30 percent from 2008, LNG is a small source of natural gas supplies for the U.S., as most natural gas is imported via pipeline.

• CenterPoint Energy Gas Transmission started 2 weeks of unscheduled maintenance on September 29 at the Searcy Compressor Station on Line J in the North Pooling Area in Arkansas. During this maintenance, up to 120,000 dekatherms per day (Dth/d) of deliveries and corresponding receipts may be affected; this includes the Texas Gas Transmission and Searcy interconnect. CenterPoint announced that it is possible that firm shippers with primary delivery points on the Line J system will not be scheduled during this maintenance period.



• Columbia Gas Transmission, LLC, announced that the Buff Lick Compressor Station in West Virginia will be out of service for about 8 days effective October 1. With the exception of isolated meters needed to serve local markets upstream of the compressor station, the outage will shut in all receipt meters behind Buff Lick Compressor for the duration of the outage, according to Columbia. Production meters on the discharge of Buff Lick that are physically on Line N that are tied to CNR05 MLI will not be affected and should remain flowing.



• ANR Pipeline Company announced on September 24 that it was continuing repairs at Marshfield Compressor Station in Wisconsin, limiting the total Viking-Marshfield receipt capacity to 285,000 Dth/d through October 15. ANR anticipates that the reductions will result in the curtailment of Interruptible and Firm Secondary nominations, based on current nominations at the Viking-Marshfield location.



• Northwest Pipeline GP is performing on-going anomaly investigations near the Kemmerer Compressor Station in Wyoming and the Soda Springs Compressor Station in Idaho. Northwest has identified additional pressure restrictions that are reducing available capacity at Kemmerer from 579,000 Dth/d to 540,000 Dth/d on September 25 through September 30. Kemmerer will be returned to its full design capacity of 655,000 Dth/d on October 1, 2010. Northwest is also revising the capacity impacts at the Soda Springs compressor. During the work, the available capacity at Soda Springs will be 566,000 Dth/d on October 1 through October 4, and 595,000 Dth/d on October 5 through October 6. If primary nominations exceed available capacity, Northwest will declare a deficiency period and allocate nominations accordingly.



• The U.S. Coast Guard issued a report to the Federal Energy Regulatory Commission concerning the waterways associated with the Calais LNG terminal near Calais, Maine. Calais LNG proposes to build a 1 Bcf/d receiving terminal and associated pipeline on 2,800 feet of shoreline along the banks of the St. Croix River and Passamoquoddy Bay. The Coast Guard was tasked with assessing safety and security issues associated with LNG tankers traveling through these waterways. The Coast Guard reported that provided certain safety and security actions are taken as part of the permit, the waterways are suitable for LNG tankers. Official notification from Calais LNG of their proposal to build an LNG terminal near Calais was given to the Coast Guard in May 2008. The Canadian Federal Government has said that it will not allow LNG tankers to pass through Canadian territorial waters in the Head Harbour Passage; until such permission is granted, tankers will be unable to reach the facility.

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.