Overview:  Thursday, November 13 2003 (next release 2:00 p.m. on November 20)

Spot and futures prices moved in opposite directions for the week (Wednesday to Wednesday, November 5-12), as cash prices ended the week significantly higher in many locations, while futures prices moved lower.  At the Henry Hub, the spot price increased 32 cents on the week, or about 7 percent, to end trading yesterday (Wednesday, November 12) at $4.77 per MMBtu.  On the NYMEX, the futures contract for December delivery ended the week down by nearly 16 cents, settling yesterday at $4.739 per MMBtu, a decrease of more than 3 percent.  EIA reported that inventories were 3,187 Bcf as of Friday, November 7, which is 3.9 percent greater than the previous 5-year (1998-2002) average for the week.  The spot price for West Texas Intermediate crude oil increased on 4 out of 5 trading days, gaining more than $1 per barrel for the second week in a row and topping $31 per barrel for the first time in nearly a month, as it rose $1.08 to reach $31.37 per barrel, or $5.41 per MMBtu, in yesterday’s trading.   

Prices:

Spot prices displayed a fair amount of variability over the past 5 trading days, reflecting a similarly variable weather picture, although with a lagged response.  Though temperatures plunged into the 20s and 30s in much of New England and the Midwest over the weekend of November 8-9, this demand stimulus was trumped in Friday’s cash markets by the normal weekend drop in industrial demand, the large drop in futures prices of the day before, and forecasts for warming temperatures to begin the week.  Consequently, spot prices fell across the board, with decreases mostly ranging from 12 to 35 cents per MMBtu.  Spot prices finally increased on Tuesday, despite a warming trend beginning on that day.  Spot price increases accelerated on Wednesday, with the expectation of falling temperatures once again in many major gas-consuming areas to begin on Thursday and extend through the upcoming weekend.  For the week, spot prices ended higher at nearly every market location, with the largest increases, ranging from 22 to 58 cents per MMBtu, at Northeast locations. Increases in Louisiana/Gulf Coast markets were somewhat smaller at an average of 34 cents per MMBtu, and increases at Midwest points mostly ranged from 15 to 20 cents.  The New York citygate price increased 42 cents to $5.52 per MMBtu, while the Chicago citygate price rose 16 cents to $4.98 per MMBtu. 

 

Spot Prices ($ per MMBtu)	Thur.	Fri.	Mon.	Tues.	Wed.
	6-Nov	7-Nov	10-Nov	11-Nov	12-Nov
Henry Hub	4.75	4.48	4.42	4.53	4.77
New York	5.43	5.24	5.09	5.07	5.52
Chicago	5.05	4.73	4.61	4.75	4.98
Cal. Comp. Avg,*	4.72	4.52	4.41	4.42	4.56
Futures ($/MMBtu)
Dec delivery	4.658	4.706	4.711	4.869	4.739
Jan delivery	4.908	4.965	4.957	5.093	4.966
*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).

 

Futures prices trended down for the week, as settlement prices for contracts for delivery through the end of the heating season decreased by nearly a dime to almost 16 cents per MMBtu.  The near-month contract (December delivery) began and ended the week with significant decreases of $0.239 and $0.130 per MMBtu on last Thursday and yesterday (Wednesday, November 12).  A brief rally on Tuesday, sending the December contract price up by nearly 16 cents per MMBtu, may have been driven by short-term forecasts for falling temperatures, but this gain was nearly offset yesterday.  Further, the National Weather Service’s daily 6-10 day temperature outlooks for at least the last week have been consistently calling for warmer-than-normal temperatures in most high gas-consuming areas.  For the week, the December contract price fell $0.158 to $4.739 per MMBtu.  With the January and February 2004 contracts settling yesterday at $4.986 and $4.889, respectively, futures prices for all months of the current heating season were below $5 per MMBtu. With the week’s change in cash and futures prices, the differential between futures settlement prices and the Henry Hub spot price has narrowed considerably, and, in the case of the December contract, was negative on 2 of the 5 trading days this week.  This reduces the incentive for industry participants to inject gas into storage.

 

  

Estimated Average Wellhead Prices
	May-03	Jun-03	Jul-03	Aug-03	Sep-03	Oct-03
Price ($ per Mcf)	4.97	5.35	4.91	4.72	4.58	4.43
Price ($ per MMBtu)	4.84	5.21	4.79	4.60	4.46	4.32
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 increased to 3,187 Bcf as of the week ended Friday, November 7, according to EIA’s Weekly Natural Gas Storage Report.  The implied net injection of 32 Bcf greatly exceeds the previous 5-year (1998-2002) average net injection for the week of 6 Bcf, and increased the surplus with respect to the 5-year average to 3.9 percent.(See Storage Figure).  The net withdrawal in the West region reflects the colder-than-normal temperatures that prevailed along the West coast and throughout much of the Rocky Mountain and Northern Plains States during the report week. (See Temperature Map) (See Deviation Map)  The West North Central, Mountain, and Pacific Census divisions were 29.4, 24.1, and 43.3 percent, respectively, colder than normal for that week, as measured by gas-customer weighted heating degree days (HDD).  In sharp contrast were the significantly warmer-than-normal temperatures that prevailed throughout most of the rest of the nation.  The warm temperatures in many populous, high gas-consuming areas of the Midwest, Northeast, and Middle Atlantic kept swing demand for space heating in these areas at a minimum, allowing significant net injections into storage in the East and Producing regions.  HDDs ranged from 8.1 percent below normal for the week in the East North Central division to one-third less than normal in the Middle Atlantic division.

 

All Volumes in Bcf	Current Stocks 11/07/03	One-Week Prior Stocks 10/31/03	Implied Net Change from Last Week	Estimated Prior 5-Year (1998-2002) Average	Percent Difference from 5 Year Average
East Region	1,891	1,871	20	1,853	2.1%
West Region	392	399	-7	374	4.8%
Producing Region	904	885	19	839	7.7%
Total Lower 48	3,187	3,155	32	3,066	3.9%
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.  R=Revised

 

Other Market Trends:

The Minerals Management Service Reports Royalty Gas Sale for the First Time in Offshore Louisiana.  On November 4, the Minerals Management Service (MMS) of the United Sates Department of the Interior reported that more than 379,000 MMBtu (million British thermal units) of royalty-in-kind gas produced from federal leases in the Gulf of Mexico was sold to seven companies during a winter heating season sale conducted by the agency.  The sale, unique in that it offered royalty gas for the first time from the 8(g) zone offshore Louisiana, provides for the gas to be delivered to 10 offshore pipeline systems originating in the Gulf of Mexico, and destined for consumer and industry use during this winter’s heating season.  The sales are for 5- or 12-month terms with delivery beginning November 1, 2003.  According to MMS officials, this particular sale demonstrates continuing federal-state cooperation since it marked the first time royalty gas was offered from leases within the 8(g) zone offshore Louisiana.  Made possible by a cooperative Memorandum of Understanding between the State of Louisiana and the MMS, a percentage of the proceeds from those specific sales packages in the 8(g) zone will be returned to the state to help fund other programs.  Some of the sales packages also included royalty gas from the 8(g) zone offshore Texas, which also has a cooperative agreement with the Minerals Management Service. 

 

Natural Gas Summary from the Short-Term Energy Outlook:

The Energy Information Administration (EIA) projects that natural gas wellhead prices will average $4.18 per MMBtu during the last 2 months of 2003 and increase to $4.36 in January 2004 (Short-Term Energy Outlook, November 2003). Prices have fallen in the past few months as mild weather and reduced industrial demand have allowed record storage refill rates. As of October 31, 2003, working gas levels had reached 3,155 Bcf, which is about 3 percent higher than the 5-year average and the first time since October 2002 that stocks exceeded the year-earlier levels. With the improved storage situation, wellhead prices during the current heating season (November through March) are expected to be about 12 percent less than last winter ($4.12 vs. $4.68 per MMBtu). However, prices in the residential sector will likely be about 8 percent higher than last winter, as accumulated natural gas utility costs through 2003 are recovered in higher household delivery charges. Overall in 2003, wellhead prices are expected to average $4.76 per MMBtu, which is nearly $2 more than the 2002 annual average and the largest year-to-year increase on record. For 2004, wellhead prices are projected to drop by nearly $0.90 per MMBtu, or about 18 percent, to $3.88 per MMBtu as the overall supply situation improves.

Net imports of natural gas are expected to increase by 5 percent in 2004, compared with a net decrease in 2003. Pipeline imports from Canada are down this year for the first time since 1986 and are projected to be 11 percent less than in 2002 (3.37 Tcf vs. 3.78 Tcf), while liquefied natural gas (LNG) imports are expected to reach 590 Bcf compared with 230 Bcf in 2002. Both LNG and pipeline imports are expected to grow in 2004, by 8 percent and 6 percent, respectively.

Natural gas production is expected to increase by about 3 percent in 2003. Following the downturn in natural gas-directed drilling activity in 2002, higher natural gas prices and sharply higher oil and natural gas field revenues continue to drive the resurgence in drilling this year. The weekly number of rigs drilling for natural gas has exceeded 900 since the week ending June 13 and averaged 936 in September and 941 in October. The prospects for significant reductions in natural gas wellhead prices in 2004 depend on the productivity of the expected upsurge in drilling.

Natural gas demand is expected to fall by about 2 percent in 2003 because of reduced demand in the industrial and electric power sectors as a result of high prices and the sharply lower weather-related demand following the first quarter of 2003. This winter, natural gas demand is expected to be about 2 percent less than last winter’s level as gas-weighted heating degree-days for the season (Q4 2003 and Q1 2004) are projected to be about 2.5 percent less than year-ago levels. Overall in 2004, natural gas demand is expected to increase because of accelerated economic growth and generally lower prices.

 

 

Short-Term Natural Gas Market Outlook, November 2003
	History			Projections
	Aug-03	Sep-03	Oct-03	Nov-03	Dec-03	Jan-04
PRICES ($/MMBtu)
Average Wellhead Price	4.60	4.46	4.10	4.06	4.30	4.36
Residential Price	12.04	11.37	10.12	9.18	8.78	8.77
Electric Utilities Price	4.65	4.44	4.44	4.80	5.11	5.21
SUPPLY (Trillion Cubic Feet)
Total Dry Gas Production	1.657	1.611	1.683	1.640	1.664	1.676
Net Imports	0.291	0.279	0.296	0.289	0.309	0.311
Imports	0.348	0.334	0.353	0.346	0.367	0.369
Exports	0.057	0.055	0.057	0.057	0.059	0.058
Suppl. Gaseous Fuels	0.007	0.006	0.006	0.007	0.008	0.008
Total New Supply	1.955	1.896	1.985	1.936	1.980	1.995
Working Gas in Storage
Opening	2.127	2.444	2.868	3.171	3.092	2.642
Closing	2.444	2.868	3.171	3.092	2.642	1.959
Net Storage Withdrawal	-0.317	-0.424	-0.303	0.079	0.450	0.683
Total Supply	1.638	1.472	1.683	2.014	2.430	2.677
Balancing Item	-0.029	0.029	-0.120	-0.198	-0.165	-0.106
Total Primary Supply	1.609	1.501	1.562	1.817	2.265	2.571
DEMAND (Trillion Cubic Feet)
Lease & Plant Fuel	0.095	0.092	0.094	0.090	0.092	0.091
Pipeline Use	0.046	0.043	0.046	0.055	0.070	0.079
Delivered to Consumers	1.468	1.367	1.422	1.671	2.103	2.401
Residential	0.119	0.133	0.230	0.444	0.733	0.929
Commercial	0.125	0.126	0.172	0.276	0.405	0.486
Industrial	0.566	0.546	0.589	0.584	0.609	0.643
Electric Power	0.658	0.562	0.430	0.367	0.356	0.344
Total Demand	1.609	1.501	1.562	1.817	2.265	2.571

 

Source:  Energy Information Administration, Short-Term Energy Outlook, November 2003.