Overview:
Thursday, March 17 (next release 2:00 p.m. on March 24)
Since
Wednesday, March 9, natural gas spot prices have risen
at most market locations in the Lower 48 States, while declining in the
Northeast region. For the week
(Wednesday–Wednesday), prices at the Henry Hub increased 9 cents, or about 1
percent, to $7.08 per MMBtu. Yesterday (March 16), the price of the NYMEX
futures contract for April delivery at the Henry Hub settled at $7.192 per MMBtu, increasing roughly 31 cents, or about 5 percent, since
last Wednesday. Natural gas in storage
was 1,379 Bcf as of March 11, which is about 24
percent above the 5-year average. The
spot price for West Texas Intermediate (WTI) crude oil increased $1.76 per
barrel, or about 3 percent, on the week to $56.50 per barrel or $8.741 per MMBtu.
Spot
prices increased since last Wednesday, March 9, at most market locations
outside the Northeast. Lingering cold
temperatures and climbing crude oil prices likely contributed to the continuing
strength in natural gas prices. The
largest price increases, ranging between 17 and 31 cents per MMBtu, occurred in the western region of the country
including California, Arizona, and the Rocky Mountains and West Texas regions.
In the gas-producing states bordering the Gulf of Mexico, price hikes were
relatively modest, climbing less than a dime since last Wednesday, March
9. In contrast to the rest of the Lower
48 States, prices in the Northeast region registered significant declines, as
prices fell more than 40 cents per MMBtu at most
locations in the region during the week.
Prices at the New York citygate fell 65 cents
per MMBtu or about 8 percent, and prices at the
Algonquin citygate, which serves the New England
region, fell 72 cents per MMBtu or about 8 percent in
trading since last Wednesday, March 9.
Despite price declines in the Northeast, prices in that region remain
the highest in the Lower 48. Whether
increasing or decreasing for the week (Wednesday-to-Wednesday), prices at most
markets in the Lower 48 States remain about 25 percent higher than last year at
this time. At the New York citygate, prices are $1.61 per MMBtu
or 26 percent higher than last year at this time. Similarly, prices at the Henry Hub are also
about 26 percent above last year’s level.
At
the NYMEX, the price of the futures contract for April delivery at the Henry
Hub increased about 31 cents per MMBtu since last
Wednesday, March 9, to $7.192 per MMBtu. Similarly,
prices for the futures contracts through the 2005 injection season (April 2005
through October 2005) also increased about 30 cents per MMBtu
or about 4.5 percent. With these increases, futures prices remained in contango, as prices for the futures contracts through
January 2006 were successively higher than each preceding month. Futures prices for delivery during the summer
months of 2005 are extraordinarily high for this time of year. For example, the August 2005 contract settled
at $7.503 per MMBtu yesterday (March 16) almost $1.63
per MMBtu or 28 percent more than the August 2004
contract at this time last year. These
relatively high futures prices during the summer months apparently reflect
market expectations of persisting tightness in the natural gas market, despite
continued high levels of working gas in storage levels relative to the
5-year-average.
Recent
Natural Gas Market Data
|
Estimated Average Wellhead Prices |
||||||
|
|
Sept-04 |
Oct-04 |
Nov-04 |
Dec-04 |
Jan-05 |
Feb-05 |
|
Price
($ per Mcf) |
4.86 |
5.45 |
6.07 |
6.25 |
5.52 |
5.59 |
|
Price
($ per MMBtu) |
4.73 |
5.30 |
5.91 |
6.08 |
5.37 |
5.44 |
|
Note:
Prices were converted from $ per Mcf to $ per MMBtu using an average heat content of 1,027 Btu per
cubic foot as published in Table A4 of the Annual Energy
Review 2002. |
||||||
|
Source: Energy Information Administration, Office
of Oil and Gas. |
||||||
Working
gas in storage was 1,379 Bcf, or 24.3 percent above
the 5-year average, as of Friday, March 11, according to EIA’s
Weekly Natural Gas Storage Report (See Storage Figure). Stock levels
exceeded year-earlier levels by 275 Bcf despite an
implied net withdrawal of 95 Bcf, which is large
compared with the 5-year average withdrawal of 64 Bcf
for this week, or last year’s withdrawal of 43 Bcf
for this week. The above average
withdrawal likely resulted from colder-than-normal temperatures across much of
the eastern United States, especially where major population centers account
for much of the space heating demand.
The relatively coldest temperatures prevailed throughout regions along
the Atlantic coast, where temperatures were 18 percent to 20 percent colder
than normal as measured by the National Weather Service heating degree days (HDDs) for the week ending Thursday, March 10, 2005. (See
HDD table). The East North
Central and East South Central regions also experienced 7 percent and 16
percent colder-than-normal temperatures, respectively. Warmer-than-normal temperatures across the
western regions—ranging from 14 percent to 33 percent above normal—roughly
offset the cold in the East, resulting in average temperatures for the entire
Lower 48 States that were only 1 percent colder than normal. If net withdrawals
for the remainder of the month match the 5-year average, working gas in storage
will be just below 1,300 Bcf at the end of the
heating season.
Other
Market Trends:
Alberta’s
Potential for Conventional Natural Gas Revised Upward: The Alberta Energy and Utilities Board (EUB) and the National
Energy Board (NEB) released on March 9, 2005 a report, entitled Alberta’s
Ultimate Potential for Conventional Natural Gas, increasing the official
estimates of resources available for development by 30 percent. The report
estimates that Alberta’s ultimate potential for marketable conventional gas is
223 trillion cubic feet (Tcf) and that 101 Tcf of conventional natural gas remains to be developed.
Data from 320,000 wells drilled to December 2004 were used to arrive at the
estimates. Alberta is a major contributor to the North American natural gas
market, as it accounts for almost 80 percent of total Canadian production, and
is equivalent to about 27 percent of the total U.S. natural gas production.
According to the report, recently, there have been record levels of drilling in
Alberta, and Alberta appears to have reached, or at least is very near, its
peak production capacity. Consequently, there is significant interest in
Alberta’s ultimate potential for marketable conventional natural gas. Although
increased from earlier estimates, Alberta’s remaining estimated ultimate
marketable conventional natural gas will require supplements from
unconventional gas supplies in order to continue meeting Canadian domestic and
export demands. The United States imported almost 3.6 Tcf
of natural gas from Canada, or about 82 percent of total U.S. imports in 2004.
Minerals Management Service Announces
Lease Sales 194 and 197: The Minerals Management Service (MMS) of the Department of the Interior
held two lease sales for tracts in the Gulf of Mexico on March 16, 2005. Final Sale 194, which encompassed areas in
the Central Gulf of Mexico, received 651 bids on 428 tracts. It collected $353,961,798 in high bids from
80 companies for oil and natural gas leases in the Federal waters of the Gulf
of Mexico. The lease sale area covers
4,063 blocks amounting to approximately 21.4 million acres in the Central Gulf
of Mexico Outer Continental Shelf (OCS) Planning Area offshore Louisiana,
Mississippi, and Alabama. The blocks are located from 3 to about 210 miles
offshore in water depths of 4 to more than 3,400 meters (approximately 13 to
11,155 feet). MMS had estimated the lease sale could result in the recovery of
between 276 and 654 million barrels of oil and from 1.59 to 3.30 trillion cubic
feet of natural gas. Sale 197 in the
Eastern Gulf of Mexico received 12 bids totaling $6,974,531 on 12 tracts
offered. The Sale 197 lease area
encompasses the unleased blocks in the Eastern Gulf
of Mexico OCS Planning Area, directly south of Alabama. These 124 unleased blocks cover about 714,240 acres and are located
from 100 to 196 miles offshore in water depths of 1,600 to more than 3,425
meters (approximately 5,249 to 11,237 feet). Estimates of undiscovered
economically recoverable hydrocarbons in this sale area range from 65 to 85
million barrels of oil, and 2.65 to 3.4 billion cubic feet of natural gas.
Summary:
Natural
gas spot prices increased at most market locations outside of the Northeast
region since last Wednesday, March 9.
Prices for the futures contracts through January 2006 were successively
higher than each preceding month.
Working gas in storage declined to 1,379 Bcf,
which is about 24 percent above the 5-year average.
