Natural Gas

Overview:

Since Wednesday, December 10, natural gas spot prices have decreased at most market locations in the Lower 48 States. For the week (Wednesday-Wednesday), prices at the Henry Hub decreased 9 cents or about 1 percent to $6.56 per MMBtu. Prices declined in most areas as temperatures moderated following the first significant winter storms of the 2003-2004 heating season. Yesterday (Wednesday, December 17), the price of the NYMEX futures contract for January delivery at the Henry Hub settled at $6.993 per MMBtu, increasing roughly 28 cents or 4 percent since last Wednesday. Natural gas in storage decreased to 2,850 Bcf as of December 12, which is 1.4 percent above the 5-year average. The spot price for West Texas Intermediate (WTI) crude oil gained $1.44 per barrel or about 5 percent since last Wednesday, climbing to $33.36 per barrel or $6.993 per MMBtu.

Prices:

Spot prices fell at most market locations in the Lower 48 States since last Wednesday, December 10, as cold temperatures subsided somewhat following the first significant snowfalls and associated price spikes of the heating season late last week. The largest price declines during the week principally occurred in the Gulf of Mexico producing region and the Midwest and Midcontinent regions. Declines in the Gulf of Mexico producing region ranged between 2 and 59 cents per MMBtu, with many markets in the region experiencing declines of more than 20 cents per MMBtu. Prices at most market locations in the Midwest and Midcontinent regions fell between 10 and 38 cents per MMBtu. In the Northeast region, declines were less pronounced, as prices fell less than 14 cents in most markets. In contrast to the pattern of decline in the rest of the country, prices west of the Rockies were mixed. In the Rocky Mountains region, where temperatures in the 20s were expected, prices climbed more than a nickel at most locations. In California, prices fell in the northern markets and were mixed in the south. However, prices remain at significantly higher levels than last year at this time. For example, prices at the Henry Hub are nearly 24 percent greater than last year's level. At the New York citygate and the Algonquin citygate, which serves the New England area, prices were $7.19 and $7.28 per MMBtu, respectively, which is more than 10 percent greater than levels last year at this time.

 

Spot Prices ($ per MMBtu)	Thur.	Fri.	Mon.	Tues.	Wed.
	11-Dec	12-Dec	15-Dec	16-Dec	17-Dec
Henry Hub	6.57	6.73	6.64	6.58	6.56
New York	7.34	7.91	7.25	7.16	7.19
Chicago	6.62	6.80	6.66	6.56	6.56
Cal. Comp. Avg,*	5.98	6.10	6.03	6.05	5.97
Futures ($/MMBtu)
Jan delivery	6.615	7.221	6.954	6.747	6.993
Feb delivery	6.655	7.149	6.991	6.786	6.993
*Avg. of NGI's reported avg. prices for: Malin, PG&E citygate,
and Southern California Border Avg.
Source: NGI's Daily Gas Price Index (http://intelligencepress.com).

 

At the NYMEX, the prices of the futures contracts for January delivery at the Henry Hub increased about 28 cents or 4 percent since last Wednesday (December 10). Prices of futures contracts for delivery in January and February 2004 climbed above the $7 threshold on Friday, December 12, but retreated the following day. Prices of futures contracts for delivery during the 2003-2004 heating season months continue to trade at a premium to the Henry Hub spot price, which provides suppliers some incentive to forego withdrawals of natural gas from storage for the time being. As in the spot markets, the price of the January contract is significantly higher than last year at this time. Yesterday, December 17, the January contract settled about $1.75 per MMBtu or 33 percent higher than last year's level at this time.

 

Estimated Average Wellhead Prices
	Jun-03	Jul-03	Aug-03	Sep-03	Oct-03	Nov-03
Price ($ per Mcf)	5.35	4.91	4.72	4.58	4.43	4.34
Price ($ per MMBtu)	5.21	4.79	4.60	4.46	4.32	4.23
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 storage was 2,850 Bcf as of Friday, December 12, 2003, according to the EIA Weekly Natural Gas Storage Report. This is 1.4 percent above the 5-year average for the report week and 215 Bcf above the level last year for the same week (See Storage Figure). The implied net withdrawal during the report week was 134 Bcf, which is 43 percent more than the 5-year average withdrawal of 94 Bcf for the week. Cooler-than-normal temperatures across most of the Lower 48 States likely contributed to the larger-than-normal withdrawals of natural gas from storage. (See Temperature Map) (See Deviation Map) Nevertheless, withdrawals were significantly lower than the net change of 159 Bcf for the same report week last year.

 

All Volumes in Bcf	Current Stocks 12/12/03	One-Week Prior Stocks 12/05/03	Implied Net Change from Last Week	Estimated Prior 5-Year (1998-2002) Average	Percent Difference from 5 Year Average
East Region	1,678	1,756	-78	1,689	-0.7%
West Region	360	371	-11	350	2.9%
Producing Region	812	857	-45	772	5.2%
Total Lower 48	2,850	2,984	-134	2,811	1.4%
Source: Energy Information Administration: Form EIA-912, "Weekly Underground Natural Gas Storage Report," and the Historical Weekly Storage Estimates Database. Row and column sums may not equal totals due to independent rounding.

 

Other Market Trends:

EIA Forecasts Lower Demand and Supply, Growing Role for LNG Imports: According to the Energy Information Administration's (EIA) recently released annual long-term forecast, Annual Energy Outlook 2004 (AEO2004), natural gas demand grows more slowly and gas prices are higher than previous projections. Total supply, including contributions from Alaska and liquefied natural gas (LNG) imports, will rise to 31.3 trillion cubic feet (Tcf) in 2025. This is approximately 3.3 Tcf less than forecast in the AEO2003. Domestic production is expected to increase from 19.1 Tcf in 2002 to 24.1 Tcf in 2025, which is 2.8 Tcf less than last year's forecast. The decrease is due, in part, to lower conventional onshore production because of slower reserve growth, fewer new discoveries, and higher development costs. Making up the difference in supplies are unconventional domestic sources such as coal-bed methane, Alaskan production, and LNG imports. The completion of a pipeline into the Lower 48 States in 2018 will increase Alaskan production from 0.4 Tcf in 2002 to 2.7 Tcf in 2025, according to the forecast. Total U.S. imports will account for more than 23 percent of supply in 2025, or 7.2 Tcf. With more LNG regasification terminals expected to be built, EIA forecasts that LNG's share of imports will rise to 66 percent, or 4.8 Tcf. EIA projects the construction of new terminals serving the Gulf, Mid-Atlantic, South Atlantic States, and New England. Additionally, an LNG facility is expected to be constructed in the Bahamas, with deliveries of natural gas to the United States by undersea pipeline into the Florida market. EIA further expects the construction of a new terminal in Baja California, Mexico, resulting in higher natural gas imports from Mexico into Southern California. Average natural gas wellhead prices are projected to increase from $2.95 per thousand cubic feet (Mcf) in 2002 to $4.40 in 2025 (constant 2002 dollars), which is 44 cents per Mcf higher than last year's projection. Higher prices are expected to have an impact on demand for gas, particularly in the energy-intensive industrial sector and the power sector, as other fuels for power generation become more competitive. Demand growth slows in the later years of the forecasts, from 1.6 per year from 2002 to 2020 to just 0.6 percent from 2020 to 2025.

 

Summary:

Moderating temperatures reduced natural gas demand in most parts of the country, contributing to lower spot prices at most market locations. However, prices climbed at the NYMEX futures market from last week's level. Working gas in storage decrease d to 2,850 Bcf, which is 1.4 percent above the 5-year average.

 

Natural Gas Summary from the Short-Term Energy Outlook