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Overview: Thursday, February 16 (next release 2:00 p.m. on February 23, 2006)
Winter-like conditions in much of the East this past weekend transitioned to above-normal temperatures, contributing to a further decline in natural gas spot prices this week (Wednesday, February 8 – Wednesday, February 15). On the week the Henry Hub spot price declined 57 cents per MMBtu to $7.31. At the New York Mercantile Exchange (NYMEX), prices for futures contracts also registered significant declines. The futures contract for March delivery, which is the last contract for the current heating season, declined 66.9 cents per MMBtu on the week to $7.066. Relatively high levels of natural gas in working storage and falling prices for competing fuels likely contributed to falling natural gas prices this week. Working gas in storage as of Friday, February 10, was 2,266 Bcf, which is 43.9 percent above the 5-year (2001-2005) average. The spot price for West Texas Intermediate (WTI) crude oil decreased $4.90 per barrel on the week to $57.61, or $9.93 per MMBtu.
Spot natural gas prices moved lower in three of five trading sessions this week as a cold weather front in the Northeast last weekend and another currently in the Midwest were not enough to offset several factors contributing to the lowest prices since last summer. With only 6 weeks left in the traditional heating season, storage supplies are viewed as ample. To date this winter, the weather has yet to show sustained cold temperatures, and prices for competing fuels have fallen. On Tuesday, February 14, the average price at the Henry Hub was $7.03 per MMBtu, the lowest price since July 1, 2005. On the week, the price declined more than 7 percent to an average of $7.31 per MMBtu. Price changes were largest in the Northeast region, where the average price decrease was 86 cents per MMBtu. The price off Algonquin Gas Transmission in New England registered the steepest decline, falling $1.09 per MMBtu to $8.03. Prices in the West, including the Rockies, registered slightly lower declines at an average of 20 cents per MMBtu as temperatures were moderate in parts of Nevada, Arizona, and California. The Southern California Border price decreased 26 cents on the week to $6.72 per MMBtu.
Moderate temperatures this February and ample storage supplies led to NYMEX futures prices falling this week by relatively large amounts. The near-month contract (for March delivery) declined on the week by 67 cents per MMBtu, or 8.6 percent, as it settled yesterday at $7.066, the lowest settlement price for the near-month contract since the August 2005 contract settled at $6.981 on June 30. The March contract is trading $2.32 per MMBtu lower than on the first day of its tenure as the near-month contract. The March contract is also priced 54 percent less than its peak price of $15.287 per MMBtu on December 13, 2005. Nonetheless, at its settlement price yesterday, the March contract was still $0.76 per MMBtu higher than the final settlement price of $6.304 for the March 2005 contract. The 12-month strip, which is the average price for futures contracts over the next 12 months, closed yesterday at $8.23 per MMBtu, a decrease of 67 cents since last Wednesday. Prices for all the contracts in the 12-month strip exhibited similar decreases. However, because the contracts for the next winter heating season are priced considerably higher than the near-term contracts, the percentage declines for the next winter were much lower at 6 percent or less. Currently, the highest-priced contract in the 12-month strip is the February 2007 contract, which closed yesterday at $10.109 per MMBtu, a premium of $2.80 to yesterday’s Henry Hub price.
Recent Natural Gas Market Data
Working gas in underground storage was 2,266 Bcf as of February 10, which is 43.9 percent above the 5-year average inventory level for the report week, according to EIA’s Weekly Natural Gas Storage Report (See Storage Figure). Although the net change was the largest withdrawal since the week ending December 23, 2005, it continued a string of low net withdrawals relative to the 5-year average. The implied net change for the week was a net withdrawal of 102 Bcf, which is 29 percent lower than the 5-year average withdrawal of 144 Bcf. As a result, the difference between current inventory levels and the 5-year average expanded to 691 Bcf. During the report week, the weather for the country as a whole was about 12 percent warmer than normal, as measured by heating degree days (HDDs) for the week ending February 9, according to the National Weather Service (See Temperature Maps). Key markets for space heating demand were considerably warmer than normal. In the Middle Atlantic, HDDs were 20 percent lower than normal. In the East North Central, which includes Chicago and other major population centers in the Midwest, HDDs were 8 percent below normal. While the NYMEX futures contracts for March and April 2006 delivery are trading at a discount to the Henry Hub spot price, contracts for the months after April are trading at significant premiums relative to the Henry Hub, up to an average premium of $2.38 per MMBtu for next winter (November 2006 – March 2007). This appears to indicate a strong economic incentive to purchase natural gas at spot markets for delivery to consumers and to refrain from withdrawing natural gas from underground storage.
Other Market Trends:
EIA Releases the Annual Energy Outlook 2006: According to the Energy Information Administration’s (EIA) newly-released annual long-term forecast, the Annual Energy Outlook 2006 (AEO2006), future natural gas prices are expected to be higher and demand will grow more slowly than in previous projections. Total natural gas supply, including contributions from Alaska and liquefied natural gas (LNG) imports, is projected to increase at an average annual rate of 0.7 percent to 26.48 trillion cubic feet (Tcf) in 2030. Domestic production is expected to increase to 20.8 Tcf in 2030, which is an average increase of 0.5 percent per year. In 2025, domestic natural gas production is projected to be 21.2 Tcf, compared with 21.8 trillion cubic feet in the AEO2005 reference case. Previous net LNG import projections have been revised downward, and are expected to reach 4.36 Tcf in 2030. More rapid growth in worldwide demand for natural gas in the AEO2006 reference case reduces the availability of LNG supplies to the United States and raises worldwide natural gas prices, making LNG less economical in U.S. markets. LNG imports, Alaskan natural gas production, and Lower 48 production from unconventional sources are not expected to increase sufficiently to offset the impacts of resource depletion and increased demand. Average natural gas wellhead prices in 2004 dollars are projected to decline to $4.46 in 2016, increasing thereafter to $5.92 in 2030, which amounts to an average annual increase of 0.3 percent. Total consumption for natural gas is projected to increase at an average annual rate of 0.7 percent from 2004 to 2030, to 26.9 Tcf in 2030, primarily as a result of increasing use for electricity generation and industrial applications, which together account for about 57 percent of the projected consumption in natural gas demand in 2030.
MMS Proposes 5-Year Plan for OCS Oil and Gas Leasing Program: The Minerals Management Service (MMS) is seeking comments on a draft proposal for its Outer Continental Shelf (OCS) leasing plan for 2007-2012. The draft plan proposes 21 lease sales in 7 of the 26 OCS planning areas, some of which are also included in the current program for 2002-2007. As part of the draft leasing program, MMS will study the potential for oil and gas development in areas off the coast of Virginia and a previously underdeveloped area in the North Aleutian Basin in offshore Alaska. Currently, more than 85 percent of the OCS is under Presidential and Congressional moratoria, and thus not available for energy development. MMS, in order to comply with the Energy Policy Act of 2005, has conducted an inventory of the oil and gas resources, and estimated that 85.9 billion barrels of oil and 419.9 Tcf of natural gas are technically recoverable from all Federal offshore areas. The draft plan is available at http://www.mms.gov/5-year/PDFs/DPP2007-2012.pdf.
GAO Testifies on Natural Gas Prices: The U.S. Government Accountability Office (GAO) presented testimony on February 13, 2006, to the U.S. Senate Committee on Homeland Security and Governmental Affairs, Permanent Subcommittee on Investigations. The testimony, “Natural Gas: Factors Affecting Prices and Potential Impacts on Consumers,” addresses three issues that Congress asked GAO to examine after natural gas prices sharply increased in late 2005. Specifically, Congress asked about (1) the factors causing the natural gas price increases, (2) how consumers are affected by higher prices, and (3) the roles that Federal agencies play in the natural gas market. In the testimony, GAO explains that tight supplies have made the market susceptible to extreme price spikes when demand or supply shifts suddenly such as in August 2005 when hurricanes hit the Gulf Coast of the United States. GAO found that the extent to which consumers are affected by these high prices depends partly on how much they depend on the wholesale spot market for supplies. According to the testimony, some of the largest natural gas utilities in a few States expect to buy at least 70 percent of their gas this winter at spot market prices, and the utilities generally pass the costs on to the consumers. Also, high gas prices in general mean that particular consumers such as low-income households and fertilizer manufacturers may potentially be hit hard. The testimony goes on to say that utilities in more than half the States have hedged up to 50 percent of their supply this winter in order to help stabilize prices for consumers. GAO mentions that the Federal Energy Regulatory Commission (FERC), the Commodities Futures Trading Commission (CFTC), and the Energy Information Administration (EIA) all play key roles in the natural gas marketplace. GAO is currently conducting additional research on the extent to which market manipulation affects wholesale natural gas prices. The results of this work are expected later this year.
Natural Gas Transportation Update:
<![if !supportLists]>· <![endif]>Tennessee Gas Pipeline announced Friday, February 10, that it was ending a force majeure declaration in effect since September 30, 2005, owing to Hurricane Rita. This affected meters upstream of the Johnson Bayou Separation and Dehydration Facility in southwest Louisiana. It also affected meters upstream of the Pecan Island Compressor Station and Separation and Dehydration Facility and the Grand Chenier Processing Plant and Separation and Dehydration Facility. Several meters outside the affected areas will continue to be unavailable for service.
<![if !supportLists]>· <![endif]>Starting on Monday, Westcoast Energy began a 2- to 3-day inspection on its 36-inch diameter loop south of Station 2 which has triggered higher pressure for upstream customers. This work must be completed before they tie in with the White Rock project.
<![if !supportLists]>· <![endif]>Columbia Gulf Transmission Co. has started accepting up to 125,000 decatherms (Dth) per day in receipt nominations from the Targa-Venice Plant in southeast Louisiana, effective with intraday nominations Tuesday.
<![if !supportLists]>· <![endif]>CenterPoint Energy announced an operational alert effective yesterday, February 15, and announced that its delivery capacity at Columbia Gulf/Perryville in northeast Louisiana will be limited to 265,000 Dth per day as a result of unscheduled repairs to the Delhi Station. The unscheduled repairs are expected to last about 2 to 4 days.
<![if !supportLists]>· <![endif]>Natural Gas Pipeline Company of America announced on Wednesday, that the Transco-Wharton receipt point in Wharton County, Texas, is unavailable until further notice because of the current operating conditions. The delay of the completion of unscheduled maintenance may affect Thursday’s scheduling and nominations.
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