Although seasonally cold weather continued to dominate
the country this week, the absence of January’s extreme temperatures resulted
in prices easing 20 to 75 cents per MMBtu since Wednesday, February 4. On the
week (Wednesday, February 4-Wednesday, February 11), the Henry Hub spot price
dropped 39 cents per MMBtu to $5.35. The NYMEX futures contract for March
delivery also fell 39 cents on the week to close at $5.26 yesterday (February
11). Natural gas in storage as of Friday, February 6, decreased to 1,603 Bcf,
which is 2.3 percent below the 5-year average inventory for the report week.
The spot price for West Texas Intermediate (WTI) crude oil rose $0.87 per
barrel on the week to yesterday’s closing price of $33.93 per barrel, or $5.85
but seasonal weather reigned in most regions of the country this past week,
leaving prices lower than last week at most Lower 48 market locations. For the
week, production area trading locations in Texas
and Louisiana generally dropped
nearly 40 cents per MMBtu, or about 7 percent, while declines in the Northeast
were higher at 60 cents or more. The Henry Hub spot price fell to $5.35 per
MMBtu, 39 cents lower than last week and the lowest spot price at that trading
location since December 1, 2003.
Since January 6, 2004, when
the Henry Hub spot reached this winter’s high to date of $7.04 per MMBtu, the
spot price has declined 32 percent. In the Northeast, a break from January’s
temperatures led to prices falling to just over $6 per MMBtu. The price at New
York citygates dropped 73 cents per MMBtu on the week
to $6.09. After reaching as high as $44 per MMBtu earlier this year, New
York citygate prices have ranged between $6-$7 per
MMBtu in the most recent eight trading sessions. Prices in the Midcontinent
production region fell 45 cents per MMBtu or more and at times dropped below
the $5-mark as space heating demand diminished and higher than average
withdrawals from storage may have allowed buyers to lower their reliance on
spot market purchases.Although prices
in the West continue to trade at a significant discount of 30 cents or more to
the Henry Hub, declines on the week were generally less than in the East. The
spot price at the El Paso Bondad trading point in Colorado fell 28 cents per
MMBtu on the week to $4.85.
the NYMEX, the price of the futures contract for March delivery at the Henry
Hub decreased about 39 cents per MMBtu since Wednesday, February 4, to a close
of $5.26 per MMBtu on Wednesday, February 11. As was the case with spot prices,
the near-month contract price traded with little relative variability through
the week, as storage levels appeared to counteract upward price pressure from
continued seasonal temperatures across the country. The biggest daily price
change came last Thursday, February 5, when the near-month contract fell 25
cents per MMBtu on a day when EIA reported an implied net withdrawal of 236
Bcf, one of the highest in EIA’s 9-year weekly storage database. At $5.26 per
MMBtu, the near-month contract price is the lowest since before Thanksgiving.
The March contract price is also at its lowest level since December
1,2003. In trading this week, the April contract declined 13 cents,
or 2.5 percent, to $5.207 per MMBtu. Further out, the prices from next month
through October are all within a narrow range of just 6 cents. The 12-month
strip, or the average price for contracts over the next year, closed yesterday
at $5.341, a decline of 6 cents on the week.
Estimated Average Wellhead Prices
Price ($ per Mcf)
Price ($ per MMBtu)
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 theAnnual
Energy Review 2001.
Source:Energy Information Administration, Office of Oil and Gas.
gas in underground storage decreased to 1,603 Bcf as of Friday, February 6,
according to EIA’s Weekly Natural Gas Storage
Report.Inventories now stand 2.3
percent, or 38 Bcf, below the 5-year average of 1,641 Bcf (See Storage Figure). This is the first time since mid-December 2003 that storage
inventories have fallen below the 5-year average. Despite the relatively cold
January and February weather to date, inventories are still 232 Bcf, or 17
percent, higher than last year’s level of 1,371 Bcf at this time. The implied
net withdrawal for the week was 224 Bcf, which is the second largest withdrawal
so far this heating season. The withdrawal was considerably higher than both
the 5-year average withdrawal (127 Bcf) and last year’s withdrawal (150 Bcf)
during the comparable report week. During the week ending February 7, the
weather for the country as a whole was approximately 5.6 percent colder than
normal, as measured by heating degree days (HDDs) published by the National
Weather Service, and 12 percent colder than last year. In the East North
Central region, which includes Chicago and other Midwest
population centers, temperatures were 2.4 percent colder than normal and 11
percent colder than last year. The Middle Atlantic experienced temperatures
that were about 1 percent warmer than normal, but 8 percent colder than last
year. (See Temperature Map)(See Deviations Map)
LNG Imports Reached Record Level in 2003: Imports of
liquefied natural gas (LNG) to the United States
in 2003 totaled 507 billion cubic feet (Bcf), which is more than double the
previous record for LNG deliveries to this country in a single year, according
to the Department of Energy’s Office of Fossil Energy. The previous record was
established in 1979, when the United States
received 253 Bcf from Algeria.
Last year, while Algeria
supplies totaled just 53 Bcf, Trinidad for the fourth
consecutive year was the source country with the largest volume imports to the United
States, delivering 378 Bcf in 173 cargoes. Trinidad
supplies accounted for approximately 75 percent of LNG
imported to the United States.
Other source countries included Nigeria
(50 Bcf), Qatar
(13.6 Bcf), Oman
(8.6 Bcf), and Malaysia
(2.7 Bcf).Southern Union’s LNG
terminal, located in Lake Charles, LA,
received the largest volume of any U.S.
terminal in 2003 with receipts of 238 Bcf, all through short-term or “spot”
cargo sales. Distrigas received 158 Bcf, all from Trinidad,
at its Everett, MA,
terminal. Dominion’s Cove Point, MD,
terminal, which re-opened in August 2003 for international trade, received 66
Bcf, while El Paso’s Elba
Island, GA, terminal received the
least of the four operating terminals with only 44 Bcf over the year.
Update on LNG
Receiving Terminal Proposals in North America: Project
sponsors of new liquefied natural gas (LNG)
terminals and existing terminal capacity expansions already have reached
important milestones in their efforts this year. Sound Energy Solutions, a subsidiary
of Mitsubishi Corp., filed with the Federal Energy Regulatory Commission (FERC)
for approval to build an LNG terminal at the
Port of Long Beach, CA, at a cost of $400 million. The terminal, projected to
be completed in late 2007 or early 2008, would have a send-out capacity of
700-1,000 million cubic feet per day (MMcf/d). Also on the U.S. West Coast,
Crystal Energy announced an agreement with the Alaska Gasline Port Authority to
supply up to 800 MMcf/d of gas for 20 years to the company’s proposed ClearwaterPort terminal, which would be
located offshore Ventura County, CA,
through the use of the existing “Platform Grace.” Crystal Energy filed an
application with the U.S. Coast Guard on January 27. The Energy Information
Administration (EIA) has identified at least three additional proposed
terminals for the U.S. West Coast, the most recent announcement of which is a
terminal possibly to be built on Puget Sound, near Bellingham,
WA, by Cherry Point Energy.
Several developments have occurred concerning the
dozen or so terminals proposed for the Gulf of Mexico
region. The U.S. Maritime Administration (MARAD) on January 15 approved El Paso
Corp.’s proposed Energy Bridge Gulf of Mexico project, an offshore receiving
terminal about 116 miles south of New Orleans. The EnergyBridge terminal, which would receive
only specially designed tankers with on-board regasification equipment, will
cost $60 million to construct. All funds will be provided by the owner of the “EnergyBridge” concept, Excelerate Energy,
which purchased related patents from El Paso
late in 2003. Cheniere Energy, which in late 2003 submitted applications to
FERC for the construction of terminals at Sabine Pass,
LA, and Corpus Christi,
TX, secured an option for yet another
terminal site near Mobile Bay, AL.
In the East, several developments have occurred
regarding the stiff competition to build infrastructure in the Bahamas,
along with pipelines to transport the re-gasified product into south Florida.
Most recently, Florida Power and Light’s (FPL) parent company purchased an
option to buy El Paso Corp.’s proposed High Rock LNG
facility on Grand BahamaIsland.
In addition, FPL obtained the right to purchase 50 percent of El
Paso’s Seafarer Pipeline, which is proposed to be a
128-mile, 26-inch diameter line from the Bahamas LNG
terminal into south Florida.
Tractebel and AES also are developing projects in the Bahamas.
While AES has won FERC approval for its Ocean Express pipeline, Tractebel
currently is awaiting approval for its Calypso LNG
project. In the U.S. Northeast, Weaver’s Cove Energy, a subsidiary of Poten and
Partners, filed with FERC a request to build its proposed 400 MMcf/d terminal
in Fall River, MA.
The project includes construction of a single storage tank and a jetty that could
handle ships carrying more than 3 Bcf of natural gas.
So far in 2004, two of the four existing LNG
terminals in the Lower 48 States also have announced plans for significant
expansions of their facilities. Trunkline LNG,
which already had planned an expansion to 1.3 Bcf/d by 2006, said in early
February that it now plans to increase its capacity to a total of 2.1 Bcf/d by
2006. Based on an agreement with BG Group, this “Phase II” project will cost
$125 million. Meanwhile, Dominion said that it signed an agreement with Statoil
for the expansion of its terminal in Cove Point,
MD. The expansion would increase the plant’s
output from 1 Bcf/d to 1.8 Bcf/d. Storage capacity would increase to about 14.6
Bcf.Cove Point now has 5 Bcf of
storage capacity and 2.8 Bcf of additional capacity under construction with an
estimated completion date in 2005.
Natural Gas Summary from the Short-Term
projects that natural gas wellhead prices will remain relatively high through
the rest of the winter and the first part of spring, with prices averaging
$5.19 per MMBtu through March and $4.58 in April (Short-Term
Energy Outlook, February 2004). Wellhead prices for the
current heating season (November 2003 through March 2004) are expected to
average $4.99 per MMBtu, or about 7 percent higher than last winter's level.
Spot prices at the Henry Hub averaged $5.90 per MMBtu in January as cold
temperatures (6 percent colder than normal nationally and 19 percent colder
than normal in the Northeast) kept natural gas prices and heating demand high.
Despite the severe weather, natural gas storage stocks were 3 percent above
average as of January 30 and spot prices in early February have moved down somewhat.
Overall in 2004, spot prices are expected to average about $4.90 per MMBtu and
wellhead prices are expected to average $4.63 per MMBtu, declining moderately
from the 2003 levels. In 2005, natural gas spot prices are projected to average
about $5.00 per MMBtu, under the assumption that domestic and imported supply
can continue to grow by about 1 percent per year.
estimates indicate that natural gas production increased by about 2.1 percent
in 2003. Natural gas production is expected to continue to expand modestly
through 2005, as natural gas well completions, which totaled an estimated
20,000 in 2003, continue to grow to between 21,000 and 22,000 wells per year
over the next 2 years. Natural gas demand is expected to have declined by 3.7 percent
in 2003 largely because high prices discouraged demand in the industrial and
electric power.However, expected
growth in the economy, along with somewhat lower projected annual average
prices, are expected to increase demand by about 2.2 percent in 2004. Demand in
2005 is expected to increase by 1.1 percent as the economy continues to expand
and prices ease slightly.
Short-Term Natural Gas Market Outlook, February 2004
Average Wellhead Price
Electric Utilities Price
(Trillion Cubic Feet)
Total Dry Gas Production
Suppl. Gaseous Fuels
Total New Supply
Working Gas in Storage
Net Storage Withdrawal
Total Primary Supply
(Trillion Cubic Feet)
Lease & Plant Fuel
Delivered to Consumers
Source:Energy Information Administration, Short-Term
Energy Outlook, February 2004.