Natural Gas

Overview:

Warmer weather in many regions of the country last weekend contributed to a continuation of the November reprieve from October's steep rise in natural gas prices. Spot prices eased 7 to 14 cents per MMBtu at most Gulf Coast and Southwest production-area trading locations since Wednesday, November 6. Spot gas at the Henry Hub traded at a steady $3.83 per MMBtu on each of the past 3 days. At $3.83 per MMBtu, this price declined 10 cents for the week (Wednesday-Wednesday). Despite considerable price swings within daily sessions this week, the price of the NYMEX futures contract for December delivery at the Henry Hub increased a moderate $0.023 per MMBtu for the week to $3.877. Natural gas in storage decreased to 3,097 Bcf, which exceeds the 5-year average by 2.4 percent. A general decline in energy prices, including a 91-cent per barrel decline in the spot price for West Texas Intermediate (WTI) crude oil, followed yesterday's decision by Iraq to accept the United Nations resolution on weapons inspections. On the week, the WTI price fell 44 cents per barrel to $25.28, or $4.36 per MMBtu.

 

 

 

Prices:

October's steep increase in natural gas prices seems a distant memory after two weeks of prices drifting lower in November. While prices at most production-area trading locations eased about a dime or slightly more since last Wednesday (November 6), declines in market regions lacking heating load were steeper. The regional average price for the Northeast fell 25 cents per MMBtu to $4.16. At New York City, where the temperature reached 68 degrees on Sunday, the average price for gas flows through the weekend dropped to $4.03 per MMBtu, which is the lowest price at the citygate since the end of September. Price declines in the Midwest were steep as well late last week, with the average price at the Chicago citygate falling 13 cents per MMBtu to $3.72 for gas flow through the weekend. However, slightly colder-than-expected weather early this week contributed to the Chicago citygate price regaining 14 cents per MMBtu to an average of $3.86 yesterday (November 13). In the West, Rockies prices remained well above the extreme lows last summer, but lost 10 to 25 cents per MMBtu for an average regional price of $3.03, which was about 80 cents less than the Henry Hub price.

 

At the NYMEX, the price of the futures contract for December delivery at the Henry Hub increased a slight $0.005 per MMBtu in trading yesterday (Wednesday, November 13) to close at $3.877, which is just over 2 cents higher than last Wednesday's close. Factors likely contributing to the weakness in the contract included forecasts of warm weather across the country along with a general decrease in energy prices following news that Iraq had accepted the United Nations resolution requiring weapons inspections. At its closing price yesterday, the December contract had lost almost 47 cents since its open at $4.345 as the near-month contract on October 30. The futures contracts for this winter registered slight gains of 1 to 2 cents per MMBtu on the week.

 

 

Spot Prices ($ per MMBtu)	Thur.	Fri.	Mon.	Tues.	Wed.
	7-Nov	8-Nov	11-Nov	12-Nov	13-Nov
Henry Hub	3.91	3.77	3.83	3.83	3.83
New York	4.28	4.03	4.14	4.20	4.21
Chicago	3.85	3.72	3.83	3.85	3.86
Cal. Comp. Avg,*	3.89	3.70	3.75	3.72	3.70
Futures ($/MMBtu)
Dec delivery	3.831	3.903	3.778	3.872	3.877
Jan delivery	3.971	4.032	3.910	3.991	3.982
*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).

 

Storage:

Working gas in storage was 3,097 Bcf, or 2.4 percent above the 5-year average for the week ending November 8, according to EIA's Weekly Natural Gas Storage Report. During the first full week of the unofficial heating season, the implied net withdrawal was 48 Bcf. The decline in inventories, the second net withdrawal this season, compares with a 5-year average net injection of 19 Bcf for this week and an injection of 35 Bcf last year. Across the country, temperatures were about 6 percent colder than normal as measured by heating degree days (HDDs), according to the National Weather Service. (See Temperature Map) (See Deviation Map) Moreover, in the key market regions of the New England and Mid-Atlantic, temperatures were 25 and 23 percent colder than normal, respectively. The cold weather in the East contributed to a 19 Bcf reduction in regional inventories to 1,835 Bcf, which marks the first time this year that storage inventories in the East Consuming Region have fallen below the 5-year average. Although net injections are possible in the coming weeks, it now appears that storage inventories peaked at 3,172 Bcf on October 25. Although storage inventories of 3,097 Bcf are 90 Bcf lower than last year at this time, inventories remain 74 Bcf above the 5-year average. (See Storage Figure)

 

 

All Volumes in Bcf	Current Stocks 11/08/02	Estimated Prior 5-Year (1997-2001) Average	Percent Difference from 5 Year Average	Implied Net Change from Last Week	One-Week Prior Stocks 11/01/02
East Region	1,835	1,849	-0.8%	-19	1,854
West Region	410	366	12.0%	-1	411
Producing Region	852	810	5.2%	-28	880
Total Lower 48	3,097	3,024	2.4%	-48	3,145
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 Announces Policy for Revisions to Weekly Natural Gas Storage Report: Following a review of comments received, the Energy Information Administration on November 12, 2002, issued a Federal Register that establishes a policy for revisions to weekly estimates of working gas volumes held in underground storage facilities at the national and regional levels disseminated in EIA's Weekly Natural Gas Storage Report (WNGSR). Under this policy, revisions shall be disseminated in the WNGSR according to the established schedule and shall occur when the effect of reported changes is at least 7 billion cubic feet (Bcf) at either a regional or national level. Revisions shall not be disseminated outside the established schedule. EIA is deferring temporarily further updates in estimation parameters, and is exploring ways to minimize revisions, including analysis of the sensitivity of the estimates to parameter changes. EIA will continue with the current estimation parameters and will report revisions as a result of respondent changes only, until further change is announced in the Weekly Natural Gas Storage Report.

Natural Gas Summary from the Short-Term Energy Outlook:

EIA projects that natural gas wellhead prices will average about $3.49 per MMBtu through December 2002 and then increase to $3.76 in January 2003, the peak demand month of the heating season (Short-Term Energy Outlook, released November 7, 2002). Natural gas prices were higher than expected in October as storms in the Gulf of Mexico in late September temporarily shut in some gas production, causing spot prices at the Henry Hub and elsewhere to rise above $4.00 per million Btu for most of October. In addition, early winter-like temperatures, particularly in the Midwest and Northeast, increased demand for natural gas, placing upward pressure on gas prices. Overall in 2002, wellhead prices are expected to average about $2.84 per MMBtu compared with $4.00 in 2001. Prices during the heating season (November through March), assuming normal weather, are expected to average $3.56 per MMBtu, which is about $1.20 higher than last winter's price. Prices to residential customers during the heating season are expected to average $7.81 per MMBtu compared with $7.14 last winter. In 2003, wellhead prices are projected to average $3.28 per MMBtu, or about $0.44 per MMBtu more than in 2002, owing to expectations of increasing economic growth, little or no change in the annual average crude oil price for 2003, and lower storage levels for most of 2003 compared with 2002 levels.

 

Domestic dry natural gas production is projected to fall by about 1.3 percent in 2002 compared with the 2001 growth rate of 2.4 percent. Lower natural gas prices have reduced production and resource development incentives from their highs of last year. However, current supplies appear to be at very adequate levels. Working gas in storage has remained well above the previous 5-year average since the beginning of the year. As of November 1, 2002, working gas stocks were 3,145 Bcf, which exceeds the 5-year average by almost 5 percent despite net withdrawals during the last week of October 2002. Furthermore, natural gas-directed drilling, while down sharply from 2001 levels, is still quite strong by a longer historical perspective. The weekly gas rig count in October averaged 709, down from the September average of 736. But this is only slightly below the 2000 average of 720, which itself exceeds the level of average rigs running in any year in the 1990s by at least 28 percent. In 2003, production is expected to rebound by 2.6 percent as demand rises and inventories fall back closer to normal.

 

Natural gas demand is expected to increase through the rest of 2002 and into 2003 because of an expected upswing in the U.S. industrial economy and the return of colder weather. Overall in 2002, natural gas demand growth is projected to be 1.1 percent, as increased demand in the electric power sector and weather-related demand in the residential and commercial sectors offset weakness in industrial demand and declines in space-heating demand in the first part of 2002. Natural gas demand in the combined residential and commercial sectors for the last 6 months of 2002 is expected to be 13.2 percent higher than 2001 levels. In 2003, natural gas demand growth is expected to increase by 6.8 percent as the economy continues to recover.

 

Short-Term Natural Gas Market Outlook, November 2002
	History			Projections
	Aug-02	Sep-02	Oct-02	Nov-02	Dec-02	Jan-03
PRICES ($/MMBtu)
Average Wellhead Price	2.70	2.90	3.18	3.47	3.50	3.76
Residential Price	9.40	9.49	8.43	7.81	7.67	7.76
Electric Utilities Price	3.26	3.29	3.45	3.99	4.22	4.46
SUPPLY (Trillion Cubic Feet)
Total Dry Gas Production	1.59	1.54	1.60	1.57	1.62	1.68
Net Imports	0.29	0.27	0.29	0.28	0.30	0.30
Imports	0.34	0.32	0.34	0.33	0.34	0.35
Exports	0.05	0.05	0.05	0.05	0.05	0.05
Suppl. Gaseous Fuels	0.01	0.01	0.01	0.01	0.01	0.01
Total New Supply	1.894	1.820	1.894	1.860	1.919	1.992
Working Gas in Storage
Opening	2.558	2.792	3.059	3.149	3.000	2.523
Closing	2.792	3.059	3.149	3.000	2.523	1.881
Net Storage Withdrawal	-0.234	-0.267	-0.090	0.149	0.478	0.641
Total Supply	1.660	1.553	1.804	2.009	2.397	2.633
Balancing Item	-0.049	-0.026	-0.199	-0.150	-0.069	0.034
Total Primary Supply	1.611	1.527	1.605	1.859	2.327	2.667
DEMAND (Trillion Cubic Feet)
Lease & Plant Fuel	0.098	0.097	0.101	0.100	0.103	0.104
Pipeline Use	0.043	0.039	0.043	0.051	0.066	0.075
Delivered to Consumers	1.471	1.391	1.462	1.708	2.159	2.488
Residential	0.129	0.146	0.255	0.457	0.733	0.939
Commercial	0.151	0.150	0.194	0.273	0.386	0.469
Industrial	0.844	0.825	0.816	0.827	0.902	0.947
Elec Utility	0.346	0.270	0.196	0.151	0.138	0.132
Total Demand	1.611	1.527	1.605	1.859	2.327	2.667

 

Source: Energy Information Administration, Short-Term Energy Outlook, November 2002.