for week ending November 12, 2003 | Release date: November 13, 2003 | Previous weeks
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.
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. |
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 $3.88 per MMBtu as the overall supply situation
improves.
Net imports of natural gas
are expected to increase by 5 percent in 2004, compared with a net decrease in
2003. Pipeline
imports from Canada are down this year for the first time since 1986 and are
projected to be 11 percent less than in 2002 (3.37 Tcf vs. 3.78 Tcf), while
liquefied natural gas (LNG) imports are expected to reach 590 Bcf compared with
230 Bcf in 2002. Both LNG and pipeline imports are expected to grow in 2004, by
8 percent and 6 percent, respectively.
Natural gas production is
expected to increase by about 3 percent in 2003. Following the downturn in
natural gas-directed drilling activity in 2002, higher natural gas prices and
sharply higher oil and natural gas field revenues continue to drive the
resurgence in drilling this year. The weekly number of rigs drilling for
natural gas has exceeded 900 since the week ending June 13 and averaged 936 in
September and 941 in October. The prospects for significant reductions in
natural gas wellhead prices in 2004 depend on the productivity of the expected
upsurge in drilling.
Natural gas demand is expected to fall by about 2
percent in 2003 because of reduced demand in the industrial and electric power
sectors as a result of high prices and the sharply lower weather-related demand
following the first quarter of 2003. This winter, natural gas demand is
expected to be about 2 percent less than last winter's level as gas-weighted
heating degree-days for the season (Q4 2003 and Q1 2004) are projected to be
about 2.5 percent less than year-ago levels. Overall in 2004, natural gas
demand is expected to increase because of accelerated economic growth and
generally lower prices.
Short-Term Natural Gas Market
Outlook, November 2003
|
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|
History |
Projections |
||||
|
Aug-03 |
Sep-03 |
Oct-03 |
Nov-03 |
Dec-03 |
Jan-04 |
PRICES
($/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.