|Home > Natural Gas > Natural Gas Weekly Update|
|Weekly Natural Gas Storage|
|Impact of Higher Natural Gas Prices on Local Distribution Companies and Residential Customers|
|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|
|Natural Gas Residential Choice|
|Previous Issues of Natural Gas Weekly Update|
|Natural Gas Homepage|
Overview: Thursday, October 18, 2007 (next release 2:00 p.m. on October 25, 2007)
Natural gas spot prices increased since Wednesday, October 10, at nearly all market locations. For the week (Wednesday to Wednesday), the price at the Henry Hub increased $0.32 per MMBtu, or about 5 percent, to $7.11 per MMBtu. The NYMEX futures contract for November delivery at the Henry Hub rose 45 cents since last Wednesday to close yesterday at $7.458 per MMBtu. Natural gas in storage as of Friday, October 12, was 3,375 Bcf, which is 6.7 percent above the 5-year average. Despite the seemingly favorable supply conditions and little weather-related natural gas demand, natural gas prices continued their upward movement of the past 6 weeks. The Henry Hub spot price exceeded the $7-per MMBtu mark in this week’s trading for the first time in 2 months. One factor in the recent run-up in prices may be the relatively low imports of liquefied natural gas (LNG) to the Lower 48 States. LNG imports have averaged less than 1 Bcf per day during the first half of October, based on the sendout data published on companies’ websites. LNG cargoes instead are heading to Europe and Asia, where buyers continue to purchase LNG at much higher prices than have prevailed in U.S. markets. A likely influence on natural gas prices is the spot price for West Texas Intermediate (WTI) crude oil, which reached yet another record high on Tuesday, but decreased slightly during yesterday’s trading to $87.19 per barrel or $15.03 per MMBtu. On the week, however, the WTI increased $5.89 per barrel or about 7 percent.
Despite moderate weather and high storage levels, spot prices increased this week between 4 cents and $2.17 per MMBtu. Only a few points in the Lower 48 States noted decreases on the week, such as trading locations on the Natural Gas Pipeline Company of America and Southern Star in the Midcontinent, where price declines were between 5 and 11 cents. At the Henry Hub, the spot price increased 32 cents or nearly 5 percent on the report week to $7.11 per MMBtu. Prices at other trading locations in Louisiana, where similar increases were recorded, averaged $7.09 per MMBtu yesterday. As of yesterday, trading in the Rockies continues to record the lowest average price in the Lower 48 at $4.93 per MMBtu, despite some significant increases on the week. Four trading locations in the Rockies had prices that more than doubled on the week. In addition to a decrease in temperatures in the Rockies, price increases across the Lower 48 may reflect a decrease in LNG supply. Recent LNG imports are substantially lower than earlier this year, when at times they averaged more than 3 Bcf per day. With the average import level at less than 1 Bcf per day in the current month, monthly supplies in the Lower 48 States will be at least 60 Bcf less than the 2007 peak, as long as the current trend continues. Trunkline LNG terminal in Lake Charles, Louisiana, has reported low sendout volumes of regasified LNG (an average of 75 MMcf per day). Additionally, activity is limited at Dominion’s terminal in Cove Point, Maryland (with sendout averaging just 110 MMcf per day). BG Group is the sole supplier for the Lake Charles terminal, while Shell, Statoil, and BP share capacity rights at the Cove Point terminal. BG Group also is the primary supplier at the Elba Island terminal in Georgia, where activity has declined to just over 350 MMcf per day. Meanwhile, activity has not been affected as significantly at the Suez LNG terminal in Everett, Massachusetts, where sendout activity of more than 400 MMcf per day is reported. The reduction in U.S. LNG imports reflects changes in LNG supply and demand across the world. Global LNG supplies appear adversely affected by several producers experiencing difficulties maintaining full production levels. For example, Marathon Oil has reported a temporary suspension of activity (for minor equipment repairs) at its LNG production complex on Bioko Island, New Guinea. In addition, strong demand for LNG in other parts of the world has resulted in higher prices, which diverts cargos away from the United States. For example, Japan, which is the largest importer of LNG in the world, recently experienced a massive earthquake that resulted in the temporary shutdown of nuclear power plants. As a result, Japan is now relying more on LNG as a fuel for electric power generation.
At the NYMEX, the futures contract for November delivery at the Henry Hub closed yesterday, October 17, at $7.458 per MMBtu, after increasing 45 cents or about 6 percent on the week. The November 2007 contract settlement price was the highest price for a near-month contract since the July 2007 futures contract settled at $7.519 per MMBtu on June 19. Similarly, the December 2007 contract price also increased, settling yesterday at $8.103 per MMBtu, 38 cents or about 5 percent higher than last Wednesday’s price. As of yesterday, all futures contracts for delivery during the heating season with the exception of the November 2007 contract traded above $8 per MMBtu after recording average increases of more than 4 percent on the week. The 12-month strip, which is the average of the futures prices for the coming year, increased about 31 cents per MMBtu, or 4 percent, this week to $8.079. A likely factor contributing to the upward pressure on natural gas futures prices is the increase in crude oil prices during the report week.
Recent Natural Gas Market Data
Working gas in storage increased to 3,375 Bcf as of Friday, October 12, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure). Storage inventories are currently 6.7 percent above the 5-year average but about 2 percent, or 59 Bcf, below last year’s storage level at this time. The implied net injection of 39 Bcf was 38 percent less than the 5-year average injection of 63 Bcf and about 28 percent lower than last year’s injection of 54 Bcf. This week’s injection partly reflects moderate temperatures across the United States, which kept demand for heating and cooling needs low. For the week ending October 11, 2007, temperatures were slightly warmer-than-normal (see Temperature Maps). However, the relatively low levels of 52 heating degree-days and 12 cooling degree-days for the week ending October 11, according to the National Weather Service, indicate a lack significant heating and cooling load for the country as a whole. The lower-than-average injection levels were in part due to the relative natural gas price levels that have prevailed since mid-September. During this time, the premium of near-month futures prices over the Henry Hub has decreased somewhat, which lowers economic incentives to store gas. In addition, a number of storage fields are reported to be at, or near, their capacity limit. The decrease in the relative price premium along with less available storage capacity contributed to this week’s below-average net injection.
Other Market Trends:
IOGCC Releases Its 2007 Report on Marginal Wells: According to a newly released study by the Interstate Oil and Gas Compact Commission (IOGCC), natural gas production from marginal wells accounted for 1.71 trillion cubic feet (Tcf) in 2006, which was about 9 percent of total domestic production during the year. Marginal gas refers to natural gas produced from a well that produces 60 Mcf or less per day. The number of marginal wells has increased steadily during the past decade, reaching 296,721 wells in 2006. Total marginal production, however, decreased in 2006 from the 2005 peak of 1.76 Tcf. Related to these trends, the average daily production per well dipped slightly to 15,800 cubic feet per day in 2006 from 16,700 in 2005. On a State basis, production from marginal wells in Texas in 2006 was the highest of all 28 States with marginal-gas producing wells, totaling 321.5 Bcf or 19 percent of the total. Texas was followed by Kansas (178.7 Bcf) and Oklahoma (176.9 Bcf). Marginal well productivity was the highest in Arizona and Oklahoma, where wells produced 39,700 and 36,600 cubic feet per well per day, respectively. Pennsylvania had the largest number of operational marginal wells (49,750) along with West Virginia (43,336) and Texas (40,099). The IOGCC expects a continued increase in the number of marginal gas wells in the foreseeable future.
Update on Natural Gas Rig Counts: The number of rigs drilling for natural gas was 1,442 for the week ending October 12, according to Baker-Hughes Incorporated. Although 5 percent below the record peak of 1,523 on August 31, the number of natural gas rigs is about 20 percent greater than last year at this time, and more than 35 percent higher than the 5-year average for the report week. Rigs drilling for natural gas have been on an upward trend since early 2002, reflecting the general increase in natural gas spot prices since late 2001 (see Rigs and Price graph). The continued increase in natural gas rigs indicates that spot prices in recent months, while lower than the post-hurricane highs of $10 per MMBtu or more in late 2005, have provided producers with enough incentive to continue drilling at historically high rates. The share of natural gas rigs drilling was about 82 percent of the total gas and oil rig count for the report week.
Natural Gas Transportation Update:
<![if !supportLists]>· <![endif]>Transcontinental Pipeline Corporation has encountered anomaly repair work downstream of the Sabine River, which limited the amount of available transportation capacity through this area of the system effective October 12. Total scheduled quantity is limited to primary firm transportation only for gas received upstream and delivered downstream of the Sabine River. This restriction is expected to continue until line replacement is completed on October 23, 2007.
<![if !supportLists]>· <![endif]>Questar Pipeline Company announced on Friday, October 12, that it will be performing modifications to its Oak Springs compressor station in Carbon County, Utah, between October 26 and 29, 2007. The latest modifications at Oak Springs were necessitated by the Southern Natural Gas Company’s ongoing expansion work. To facilitate the work, Mainline 104 capacity will be reduced to 320,000 decatherms (Dth) per day from its normal 380,000 Dth per day during this time period.
<![if !supportLists]>· <![endif]>Northwest Pipeline Corporation announced on Monday, October 15, that it will be performing several pig runs between the Rangely and Cisco compressor stations in Colorado and Utah, respectively, between November 2 and 16, 2007. The available south flow capacity at the Cisco compressor station will be reduced to between 70,000 and 244,000 Dth per day during this time. Should primary nominations exceed the available capacity, Northwest will declare a deficiency period and reduce nominations accordingly.
<![if !supportLists]>· <![endif]>Tennessee Gas Pipeline announced that it anticipates restrictions on the Carthage Line lateral for gas day October 18. The company stated that about 36 percent of total supply that was supposed to flow through meters on the Carthage lateral will be restricted, specifically volumes covered by various interruptible transportation agreements.
<![if !supportLists]>· <![endif]>Columbia Gas Company issued an operational flow order effective Tuesday, October 16, to all shippers and receipt meter operators in market areas 16, 17, 18, and 19 in West Virginia in order to preserve system integrity and operating performance.
<![if !supportLists]>· <![endif]>Natural Gas Pipeline Company of America reported on October 17 that a force majeure event had occurred on its Illinois Lateral #2 line in Whiteside County, Illinois. While the affected section of the pipeline has been replaced, it has been determined that additional work and testing will be required. The work, which is expected to extend through the winter season, will result in a reduced operating pressure on the lateral. The pressure reduction affects the capacity for gas flowing through Compressor Station 110 both northbound through the Illinois Lateral and eastbound through Segment 14.