Overview:  Thursday, February 12, 2004 (next release 2:00 p.m. on February 19)

Although seasonally cold weather continued to dominate the country this week, the absence of January’s extreme temperatures resulted in prices easing 20 to 75 cents per MMBtu since Wednesday, February 4. On the week (Wednesday, February 4-Wednesday, February 11), the Henry Hub spot price dropped 39 cents per MMBtu to $5.35. The NYMEX futures contract for March delivery also fell 39 cents on the week to close at $5.26 yesterday (February 11). Natural gas in storage as of Friday, February 6, decreased to 1,603 Bcf, which is 2.3 percent below the 5-year average inventory for the report week. The spot price for West Texas Intermediate (WTI) crude oil rose $0.87 per barrel on the week to yesterday’s closing price of $33.93 per barrel, or $5.85 per MMBtu.

 

Prices:

Chilly but seasonal weather reigned in most regions of the country this past week, leaving prices lower than last week at most Lower 48 market locations. For the week, production area trading locations in Texas and Louisiana generally dropped nearly 40 cents per MMBtu, or about 7 percent, while declines in the Northeast were higher at 60 cents or more. The Henry Hub spot price fell to $5.35 per MMBtu, 39 cents lower than last week and the lowest spot price at that trading location since December 1, 2003. Since January 6, 2004, when the Henry Hub spot reached this winter’s high to date of $7.04 per MMBtu, the spot price has declined 32 percent. In the Northeast, a break from January’s temperatures led to prices falling to just over $6 per MMBtu. The price at New York citygates dropped 73 cents per MMBtu on the week to $6.09. After reaching as high as $44 per MMBtu earlier this year, New York citygate prices have ranged between $6-$7 per MMBtu in the most recent eight trading sessions. Prices in the Midcontinent production region fell 45 cents per MMBtu or more and at times dropped below the $5-mark as space heating demand diminished and higher than average withdrawals from storage may have allowed buyers to lower their reliance on spot market purchases.  Although prices in the West continue to trade at a significant discount of 30 cents or more to the Henry Hub, declines on the week were generally less than in the East. The spot price at the El Paso Bondad trading point in Colorado fell 28 cents per MMBtu on the week to $4.85.

 

 

At the NYMEX, the price of the futures contract for March delivery at the Henry Hub decreased about 39 cents per MMBtu since Wednesday, February 4, to a close of $5.26 per MMBtu on Wednesday, February 11. As was the case with spot prices, the near-month contract price traded with little relative variability through the week, as storage levels appeared to counteract upward price pressure from continued seasonal temperatures across the country. The biggest daily price change came last Thursday, February 5, when the near-month contract fell 25 cents per MMBtu on a day when EIA reported an implied net withdrawal of 236 Bcf, one of the highest in EIA’s 9-year weekly storage database. At $5.26 per MMBtu, the near-month contract price is the lowest since before Thanksgiving. The March contract price is also at its lowest level since December 1,2003. In trading this week, the April contract declined 13 cents, or 2.5 percent, to $5.207 per MMBtu. Further out, the prices from next month through October are all within a narrow range of just 6 cents. The 12-month strip, or the average price for contracts over the next year, closed yesterday at $5.341, a decline of 6 cents on the week.

  

Estimated Average Wellhead Prices
	Aug-03	Sep-03	Oct-03	Nov-03	Dec-03	Jan-04
Price ($ per Mcf)	4.72	4.58	4.43	4.34	5.08	5.53
Price ($ per MMBtu)	4.60	4.46	4.32	4.23	4.95	5.39
Note:  The price data in this table are a pre-release of the average wellhead price that will be published in forthcoming issues of the Natural Gas Monthly.  Prices were converted from $ per Mcf to $ per MMBtu using an average heat content of 1,025 Btu per cubic foot as published in Table A2 of the Annual Energy Review 2001.
Source:  Energy Information Administration, Office of Oil and Gas.

 

Storage:

Working gas in underground storage decreased to 1,603 Bcf as of Friday, February 6, according to EIA’s Weekly Natural Gas Storage Report.  Inventories now stand 2.3 percent, or 38 Bcf, below the 5-year average of 1,641 Bcf (See Storage Figure).  This is the first time since mid-December 2003 that storage inventories have fallen below the 5-year average. Despite the relatively cold January and February weather to date, inventories are still 232 Bcf, or 17 percent, higher than last year’s level of 1,371 Bcf at this time. The implied net withdrawal for the week was 224 Bcf, which is the second largest withdrawal so far this heating season. The withdrawal was considerably higher than both the 5-year average withdrawal (127 Bcf) and last year’s withdrawal (150 Bcf) during the comparable report week. During the week ending February 7, the weather for the country as a whole was approximately 5.6 percent colder than normal, as measured by heating degree days (HDDs) published by the National Weather Service, and 12 percent colder than last year. In the East North Central region, which includes Chicago and other Midwest population centers, temperatures were 2.4 percent colder than normal and 11 percent colder than last year. The Middle Atlantic experienced temperatures that were about 1 percent warmer than normal, but 8 percent colder than last year. (See Temperature Map) (See Deviations Map)

 

 

Other Market Trends:

LNG Imports Reached Record Level in 2003: Imports of liquefied natural gas (LNG) to the United States in 2003 totaled 507 billion cubic feet (Bcf), which is more than double the previous record for LNG deliveries to this country in a single year, according to the Department of Energy’s Office of Fossil Energy. The previous record was established in 1979, when the United States received 253 Bcf from Algeria. Last year, while Algeria supplies totaled just 53 Bcf, Trinidad for the fourth consecutive year was the source country with the largest volume imports to the United States, delivering 378 Bcf in 173 cargoes. Trinidad supplies accounted for approximately 75 percent of LNG imported to the United States. Other source countries included Nigeria (50 Bcf), Qatar (13.6 Bcf), Oman (8.6 Bcf), and Malaysia (2.7 Bcf). Southern Union’s LNG terminal, located in Lake Charles, LA, received the largest volume of any U.S. terminal in 2003 with receipts of 238 Bcf, all through short-term or “spot” cargo sales. Distrigas received 158 Bcf, all from Trinidad, at its Everett, MA, terminal. Dominion’s Cove Point, MD, terminal, which re-opened in August 2003 for international trade, received 66 Bcf, while El Paso’s Elba Island, GA, terminal received the least of the four operating terminals with only 44 Bcf over the year.

 

Update on LNG Receiving Terminal Proposals in North America: Project sponsors of new liquefied natural gas (LNG) terminals and existing terminal capacity expansions already have reached important milestones in their efforts this year. Sound Energy Solutions, a subsidiary of Mitsubishi Corp., filed with the Federal Energy Regulatory Commission (FERC) for approval to build an LNG terminal at the Port of Long Beach, CA, at a cost of $400 million. The terminal, projected to be completed in late 2007 or early 2008, would have a send-out capacity of 700-1,000 million cubic feet per day (MMcf/d). Also on the U.S. West Coast, Crystal Energy announced an agreement with the Alaska Gasline Port Authority to supply up to 800 MMcf/d of gas for 20 years to the company’s proposed Clearwater Port terminal, which would be located offshore Ventura County, CA, through the use of the existing “Platform Grace.” Crystal Energy filed an application with the U.S. Coast Guard on January 27. The Energy Information Administration (EIA) has identified at least three additional proposed terminals for the U.S. West Coast, the most recent announcement of which is a terminal possibly to be built on Puget Sound, near Bellingham, WA, by Cherry Point Energy.

 

Several developments have occurred concerning the dozen or so terminals proposed for the Gulf of Mexico region. The U.S. Maritime Administration (MARAD) on January 15 approved El Paso Corp.’s proposed Energy Bridge Gulf of Mexico project, an offshore receiving terminal about 116 miles south of New Orleans. The Energy Bridge terminal, which would receive only specially designed tankers with on-board regasification equipment, will cost $60 million to construct. All funds will be provided by the owner of the “Energy Bridge” concept, Excelerate Energy, which purchased related patents from El Paso late in 2003. Cheniere Energy, which in late 2003 submitted applications to FERC for the construction of terminals at Sabine Pass, LA, and Corpus Christi, TX, secured an option for yet another terminal site near Mobile Bay, AL.

 

In the East, several developments have occurred regarding the stiff competition to build infrastructure in the Bahamas, along with pipelines to transport the re-gasified product into south Florida. Most recently, Florida Power and Light’s (FPL) parent company purchased an option to buy El Paso Corp.’s proposed High Rock LNG facility on Grand Bahama Island. In addition, FPL obtained the right to purchase 50 percent of El Paso’s Seafarer Pipeline, which is proposed to be a 128-mile, 26-inch diameter line from the Bahamas LNG terminal into south Florida. Tractebel and AES also are developing projects in the Bahamas. While AES has won FERC approval for its Ocean Express pipeline, Tractebel currently is awaiting approval for its Calypso LNG project. In the U.S. Northeast, Weaver’s Cove Energy, a subsidiary of Poten and Partners, filed with FERC a request to build its proposed 400 MMcf/d terminal in Fall River, MA. The project includes construction of a single storage tank and a jetty that could handle ships carrying more than 3 Bcf of natural gas.

 

So far in 2004, two of the four existing LNG terminals in the Lower 48 States also have announced plans for significant expansions of their facilities. Trunkline LNG, which already had planned an expansion to 1.3 Bcf/d by 2006, said in early February that it now plans to increase its capacity to a total of 2.1 Bcf/d by 2006. Based on an agreement with BG Group, this “Phase II” project will cost $125 million. Meanwhile, Dominion said that it signed an agreement with Statoil for the expansion of its terminal in Cove Point, MD. The expansion would increase the plant’s output from 1 Bcf/d to 1.8 Bcf/d. Storage capacity would increase to about 14.6 Bcf.   Cove Point now has 5 Bcf of storage capacity and 2.8 Bcf of additional capacity under construction with an estimated completion date in 2005.

 

Natural Gas Summary from the Short-Term Energy Outlook:

EIA projects that natural gas wellhead prices will remain relatively high through the rest of the winter and the first part of spring, with prices averaging $5.19 per MMBtu through March and $4.58 in April (Short-Term Energy Outlook, February 2004). Wellhead prices for the current heating season (November 2003 through March 2004) are expected to average $4.99 per MMBtu, or about 7 percent higher than last winter's level. Spot prices at the Henry Hub averaged $5.90 per MMBtu in January as cold temperatures (6 percent colder than normal nationally and 19 percent colder than normal in the Northeast) kept natural gas prices and heating demand high. Despite the severe weather, natural gas storage stocks were 3 percent above average as of January 30 and spot prices in early February have moved down somewhat. Overall in 2004, spot prices are expected to average about $4.90 per MMBtu and wellhead prices are expected to average $4.63 per MMBtu, declining moderately from the 2003 levels. In 2005, natural gas spot prices are projected to average about $5.00 per MMBtu, under the assumption that domestic and imported supply can continue to grow by about 1 percent per year. 

 

Early estimates indicate that natural gas production increased by about 2.1 percent in 2003. Natural gas production is expected to continue to expand modestly through 2005, as natural gas well completions, which totaled an estimated 20,000 in 2003, continue to grow to between 21,000 and 22,000 wells per year over the next 2 years. Natural gas demand is expected to have declined by 3.7 percent in 2003 largely because high prices discouraged demand in the industrial and electric power.  However, expected growth in the economy, along with somewhat lower projected annual average prices, are expected to increase demand by about 2.2 percent in 2004. Demand in 2005 is expected to increase by 1.1 percent as the economy continues to expand and prices ease slightly.

 

Short-Term Natural Gas Market Outlook, February 2004
	History			Projections
	Nov-03	Dec-03	Jan-04	Feb-04	Mar-04	Apr-04
PRICES ($/MMBtu)
Average Wellhead Price	4.23	4.95	5.38	5.39	4.99	4.58
Residential Price	9.05	8.89	9.11	9.53	9.69	9.88
Electric Utilities Price	4.60	5.04	6.58	6.36	5.85	5.15
SUPPLY (Trillion Cubic Feet)
Total Dry Gas Production	1.592	1.650	1.663	1.551	1.690	1.640
Net Imports	0.292	0.328	0.322	0.280	0.282	0.286
Imports	0.344	0.381	0.375	0.331	0.339	0.338
Exports	0.052	0.054	0.053	0.051	0.057	0.052
Suppl. Gaseous Fuels	0.007	0.007	0.008	0.006	0.007	0.006
Total New Supply	1.890	1.985	1.992	1.837	1.979	1.932
Working Gas in Storage
Opening	3.155	3.063	2.582	1.804	1.309	1.102
Closing	3.063	2.582	1.804	1.309	1.102	1.234
Net Storage Withdrawal	0.092	0.481	0.778	0.495	0.207	-0.132
Total Supply	1.982	2.466	2.770	2.333	2.186	1.799
Balancing Item	-0.190	-0.226	-0.146	0.103	-0.011	0.011
Total Primary Supply	1.793	2.241	2.624	2.435	2.175	1.811
DEMAND (Trillion Cubic Feet)
Lease & Plant Fuel	0.090	0.093	0.092	0.085	0.092	0.089
Pipeline Use	0.054	0.069	0.081	0.075	0.064	0.052
Delivered to Consumers	1.649	2.078	2.452	2.276	2.019	1.670
Residential	0.419	0.687	0.964	0.851	0.660	0.427
Commercial	0.267	0.390	0.498	0.468	0.392	0.281
Industrial	0.602	0.628	0.646	0.627	0.612	0.590
Electric Power	0.361	0.373	0.344	0.329	0.355	0.372
Total Demand	1.793	2.241	2.624	2.435	2.175	1.811

 

Source:  Energy Information Administration, Short-Term Energy Outlook, February 2004.