for week ending June 12, 2002 | Release date: June 13, 2002, 2002 | Previous weeks
Moderate price increases on
Monday and Wednesday of this week could not offset declines during the other
three trading days of the week (Wednesday to Wednesday, June 5-12), leaving
spot prices lower at most locations for the sixth consecutive week. At the
Henry Hub, the average spot price decreased by 13 cents to $3.15 per
MMBtu. Six weeks ago, on Wednesday, May
1, the Henry Hub spot price stood at $3.79 per MMBtu. Futures prices also trended
lower for the sixth consecutive week. The NYMEX futures contract for July delivery at the Henry Hub declined
by $0.203 per MMBtu for the week, settling Wednesday, June 12 at $3.057 per
MMBtu–a decrease of a little over 6 percent from the previous Wednesday. EIA's estimate of net injections into
storage for the week ended June 7 is 81 Bcf, bringing total working gas
inventories to 1,974 Bcf, or about 20 percent above the previous 5-year
(1997-2001) average. On Thursday, June
6, the spot price for West Texas Intermediate (WTI) crude oil fell below $25
per barrel for the first time since April 16, and ended trading on Wednesday,
June 12 at $24.79 per barrel, or $4.27 per MMBtu.
Prices:
Prices
received a boost on Monday from continuing hot weather in California, the
desert Southwest, and much of the Southeast, and weekend temperatures in the
Northeast and parts of the Midwest that were much higher than normal. However, the hot temperatures in the
nation's northern tier were forecast to dissipate by mid-week and lead to
lower-than-normal temperatures for the coming weekend and beyond. Prices responded on Tuesday with another
downturn, but the market's expected weakness was delayed for at least one more
day, as spot prices seemed to get a lift from a jump in crude oil and heating
oil futures and cash prices. Wednesday's gains were largest in the Rockies and California locations,
ranging around 15 to 20 cents per MMBtu. Increases at other locations were less than a dime. However, for the week, spot prices declined
at most locations between 10 to 15 cents per MMBtu; only the Rockies and
California experienced net price gains. The spot price at TRANSCO Zone 6 for delivery to New York fell 13 cents
to $3.46 per MMBtu; the Chicago price dropped a dime to $3.14 per MMBtu. In Florida, the opening of a new
interconnect between Florida Gas Transmission (FGT) and the new Gulfstream
pipeline helped ease demand on the FGT system, and contributed to the lifting
of a two-day-old Overage Alert notice on Wednesday, June 12. Nonetheless, the FGT citygate price is still
the highest in the nation, but, at $3.60 per MMBtu, its premium over prices in
other major markets has declined. Indeed, spot prices in most markets have declined on a week-to-week
basis for six straight weeks, with a few exceptions in the highly variable
markets of the Rocky Mountain region, and isolated points in the Midcontinent.
On the NYMEX, the settlement price for the near-month (July delivery) contract declined for the third straight trading session, and for the fifth time in six days, to end trading Wednesday, June 12 at $3.057 per MMBtu. This is the lowest price for the July delivery contract in three months. Futures prices have also declined fairly steadily for the past six weeks. Since it settled at $3.794 per MMBtu on May 8, the July contract has dropped almost 20 percent in price.
Spot Prices ($ per MMBtu) |
Thur. |
Fri. |
Mon. |
Tues. |
Wed. |
6-Jun |
7-Jun |
10-Jun |
11-Jun |
12-Jun |
|
Henry Hub |
3.20 |
3.11 |
3.14 |
3.10 |
3.14 |
New York |
3.49 |
3.37 |
3.51 |
3.49 |
3.46 |
Chicago |
3.19 |
3.07 |
3.15 |
3.10 |
3.14 |
Cal. Comp. Avg,* |
2.74 |
2.61 |
2.71 |
2.64 |
2.76 |
Futures ($/MMBtu) |
|
|
|
|
|
July delivery |
3.182 |
3.204 |
3.135 |
3.132 |
3.057 |
Aug delivery |
3.242 |
3.280 |
3.203 |
3.197 |
3.124 |
*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:
Total working gas in storage was 1,974 Bcf for the
week ended June 7, according to EIA's Weekly Natural Gas Storage Report,
which is 324 Bcf, or 20 percent, above the 5-year average. All regional inventory levels exceeded their
respective 5-year averages, with the Producing region, at 39 percent above its
average of 515 Bcf, showing the largest percentage difference. The net change in storage stocks during the
week of June 7 was 81 Bcf, which is 7 Bcf, or about 8 percent, less than the
previous 5-year (1997-2001) average for this week. Net injections into storage in the Consuming East were 1 Bcf
above average. However, net storage changes in the Consuming West and Producing
regions were about 22 and 26 percent, respectively, less than their 5-year
averages of 10 Bcf and 20 Bcf. This
pattern of net additions to storage reflects the general temperatures across
the country. The northern tier,
including the normally high gas-consuming Northeast and several large cities in
the Midwest, enjoyed cooler-than-normal temperatures, mostly in the 50s to 70s,
while temperatures generally were above normal in the rest of the nation (see maps: (See Temperature Map)
(See Deviation Map). Given the unusually high stocks at present,
net injections through the remainder of the refill season only have to be 76
percent of average to achieve the unofficial target of 3,000 Bcf entering the
next heating season. (See Storage Figure)
All Volumes
in Bcf |
Current
Stocks 6/07/2002 |
Estimated
Prior 5-Year (1997-2001) Average |
Percent
Difference from 5 Year Average |
Net Change
from Last Week |
One-Week
Prior Stocks 5/31/2002 |
|
East Region |
968 |
900 |
8% |
58 |
910 |
|
West Region |
292 |
235 |
24% |
8 |
284 |
|
Producing
Region |
714 |
515 |
39% |
15 |
699 |
|
Total Lower
48 |
1,974 |
1,650 |
20% |
81 |
1,893 |
|
Source: Energy Information Administration: Form EIA-912, "Weekly Underground
Natural Gas Storage Report," and the Historical Weekly Storage Estimates
Database. |
||||||
Other Market Trends:
Natural Gas Rig Counts: The number of rigs drilling
for natural gas decreased by 11 to 710 for the week ended Friday, June 7,
according to Baker-Hughes Incorporated. This is the second consecutive week that the number of rigs has fallen. Nevertheless, the rig count is now over 20
percent above the level on April 5, when the number bottomed out at 591. During
the period between the weeks ended April 5, 2002, and May 24, 2002, the number
of rigs increased for 7 consecutive weeks, climbing almost 3 percent per week
on average from 591 to 725 rigs. Natural gas rigs are over 32 percent below last year at this time when
they numbered 1,051. Although rigs
drilling gas prospects are below levels recorded in the unprecedented drilling
surge from July 2000 through January 2002, they remain well above the long-term
level of gas rig counts. At 710 rigs,
the latest count exceeds by 31 percent the average of 540 gas rigs for
1997-1999, which were the peak drilling years of the past decade.
Natural Gas Summary from the
Short-Term Energy Outlook:
EIA
projects that natural gas wellhead prices will average $2.83 per MMBtu in 2002
compared with about $4.00 last year (Short-Term Energy Outlook, June
2002). Average wellhead prices have increased by nearly 50 percent from $2.09
per MMBtu in February to an estimated $3.11 per MMBtu in May. Spot prices at
the Henry Hub have also increased, rising more than $1.00 per MMBtu since early
February. It is atypical to see higher spot gas prices in the cooling season
than during the heating season, particularly when working gas in underground
storage is at high levels, as it has been for the past several months. As of
the end of May, working gas levels were more than 20 percent above the previous
5-year average for that month. Moreover, gas-directed drilling, while down
sharply from summer 2001 levels, is still quite strong from a historical
perspective. The gas rig count as of May 31 was up 22 percent from the recent
low of 591 for the week ending April 5.
Given the
ample storage stocks and overall resource development efforts of the past 10-18
months, EIA expects that wellhead prices will fall somewhat during the next few
months if summer weather is normal or cooler than normal. If the summer
temperatures are mild so the incremental demand for gas-fired electricity
generation (to run air-conditioners) turns out to be moderate, the wellhead
price could once more dip below $3.00 per MMBtu. Wellhead prices are expected
to average $2.81 per MMBtu in the third quarter of 2002 and $3.23 in the fourth
quarter.
Natural gas production is projected to fall by more than 3 percent in 2002 compared with the 2001 level. Major energy companies reported reductions in natural gas output for first quarter 2002 (compared with the same period in 2001) of between 3 and 4 percent. (Some of this decline may have been due to asset sales.) Lower natural gas prices have reduced production and resource development incentives from their highs of last summer. U.S. natural gas production continued to rise through December 2001, then began to fall in January 2002, a lagged response to the lower demand and prices. Natural gas net imports have been dropping monthly on a year-over-year basis since October 2001, reflecting the slowing demand for natural gas. Net imports of natural gas are projected to recover by November 2002 as natural gas demand increases. Natural gas demand this summer is projected to be 4.7 percent higher than last summer's level mainly because of the fall in natural gas prices since a year ago and the slowly reviving economy. Natural gas demand for the entire year 2002 is projected to increase by 3.2 percent over the level in 2001.
Short-Term Natural Gas
Market Outlook, June 2002
|
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|
History |
Projections |
||||
|
Mar-02 |
Apr-02 |
May-02 |
Jun-02 |
Jul-02 |
Aug-02 |
PRICES ($/MMBtu) |
|
|
|
|
|
|
Average
Wellhead Price |
2.45 |
2.94 |
3.11 |
2.93 |
2.79 |
2.81 |
Residential Price |
6.53 |
6.88 |
7.67 |
8.67 |
9.10 |
9.27 |
Electric
Utilities Price |
3.09 |
3.48 |
3.68 |
3.46 |
3.29 |
3.32 |
|
|
|
|
|
|
|
SUPPLY (Trillion Cubic Feet) |
|
|
|
|
|
|
Total Dry
Gas Prod |
1.557 |
1.561 |
1.590 |
1.553 |
1.598 |
1.594 |
Net Imports |
0.258 |
0.249 |
0.258 |
0.255 |
0.270 |
0.273 |
Imports
|
0.319 |
0.304 |
0.314 |
0.309 |
0.327 |
0.330 |
Exports |
0.060 |
0.055 |
0.056 |
0.055 |
0.056 |
0.057 |
Suppl.
Gaseous Fuels |
0.006 |
0.005 |
0.004 |
0.004 |
0.005 |
0.005 |
Total New
Supply |
1.822 |
1.815 |
1.852 |
1.812 |
1.873 |
1.872 |
|
|
|
|
|
|
|
Working
Gas in Storage |
|
|
|
|
|
|
Opening |
1.852 |
1.532 |
1.620 |
1.893 |
2.152 |
2.443 |
Closing |
1.532 |
1.620 |
1.893 |
2.152 |
2.443 |
2.709 |
Net
Storage Withdrawal |
0.320 |
-0.088 |
-0.273 |
-0.259 |
-0.291 |
-0.266 |
|
|
|
|
|
|
|
Total
Supply |
2.142 |
1.727 |
1.579 |
1.553 |
1.582 |
1.606 |
|
|
|
|
|
|
|
Balancing
Item |
0.098 |
0.088 |
0.002 |
-0.048 |
-0.002 |
-0.011 |
|
|
|
|
|
|
|
Total
Primary Supply |
2.240 |
1.816 |
1.582 |
1.505 |
1.580 |
1.594 |
|
|
|
|
|
|
|
DEMAND (Trillion Cubic Feet) |
|
|
|
|
|
|
Lease
& Plant Fuel |
0.095 |
0.095 |
0.097 |
0.095 |
0.098 |
0.098 |
Pipeline
Use |
0.058 |
0.049 |
0.042 |
0.038 |
0.042 |
0.042 |
Delivered
to Consumers |
2.087 |
1.672 |
1.443 |
1.372 |
1.441 |
1.454 |
Residential |
0.694 |
0.433 |
0.254 |
0.167 |
0.136 |
0.127 |
Commercial |
0.403 |
0.286 |
0.211 |
0.175 |
0.171 |
0.169 |
Industrial |
0.807 |
0.749 |
0.741 |
0.750 |
0.780 |
0.806 |
Elec
Utility |
0.182 |
0.204 |
0.237 |
0.280 |
0.354 |
0.353 |
Total
Demand |
2.240 |
1.816 |
1.582 |
1.505 |
1.580 |
1.594 |
Source: Energy Information Administration, Short-Term Energy Outlook,
June 2002.