for week ending February 8, 2016 | Release date: February 9, 2016 | Previous weeks
Overview: Thursday, February 9 (next release 2:00 p.m. on February 16, 2006)
Despite
the slightly colder weather that dominated the country this week, natural gas
spot and futures prices generally decreased for the week (February 1-8). The Henry Hub natural gas spot price fell 83 cents,
or about 10 percent, while prices at most other regional markets ended the week
with decreases averaging 58 cents per MMBtu. The
price of the NYMEX futures contract for March delivery at the Henry Hub decreased
99 cents per MMBtu, or slightly over 11 percent,
settling yesterday (February 8) at $7.735 per MMBtu.
The Energy Information Administration (EIA) reported working gas in underground
storage of 2,368 Bcf as of February 3, which reflects
an implied net decrease of 38 Bcf. The spot price for
West Texas Intermediate (WTI) crude oil decreased $4.10 per barrel, or more
than 6 percent since last Wednesday (February 1), ending trading yesterday at $62.51
per barrel, or $10.78 per MMBtu.
The
continued warmer-than-normal temperatures across much of the Lower 48 States,
coupled with the decreasing crude oil prices, led to a decrease in natural gas
prices. For the week, spot prices at trading
locations in Texas generally decreased between 36 and 71 cents per MMBtu, or 4.7
and 8.5 percent, while declines in the Rocky Mountain region were greater at 50
cents or more. The Henry Hub spot price decreased to $7.88 per MMBtu, 83 cents
lower than last week. In the Northeast prices fell by an average of 52 cents to
$8.70 per MMBtu. The price at New York citygates dropped 38 cents per MMBtu on
the week to $8.98. Prices in the Midcontinent production region decreased 12
cents per MMBtu or more and in certain markets dropped below $7 for a few days.
The largest decline on the week of all Lower
48 markets was recorded at the Michigan Consolidated market location, which
recorded a 94-cent per MMBtu decrease to an average of $7.86 per MMBtu
yesterday (February 8). On a regional level, the Midwest recorded the largest
decreases since last Wednesday, averaging 85 cents per MMBtu, followed by
California (75 cents per MMBtu) and Louisiana (65 cents per MMBtu).
Spot
prices have exhibited a downward trend since mid-December, falling by $7.52 per
MMBtu or about 49 percent from the $15.40 recorded at the Henry Hub on December
13, 2005. Similarly, the price of the near-month futures contracts has decreased
by $7.643 per MMBtu or about 50 percent during the same time. While the current
heating season started out with gas inventories below last year's level, with
the difference expanding to more than 200 Bcf by mid December, current storage
levels are 437 Bcf higher than during the same week last year. The unusually
high levels of working gas in storage are due to the combination of warmer-than-normal
temperatures in the Lower 48 States and the level of spot prices relative to
futures contract prices. Weather for the Lower 48 States for November and
December 2005 was 13 percent warmer than normal and about 7 percent warmer than
during the same period last year, according to the National Weather Service.
Moreover, a recently published weather report by the National Climate Data
Center (NCDC) indicated that January 2006 was the warmest January on record,
averaging 39.5 degrees Fahrenheit, which is 8.5 degrees above average for
January. More than 74 percent of the country was classified as "much above
normal" when compared with the 1961-1990 climate normal. On average for the
entire month of January, none of the Lower 48 States had below average
temperatures, while 15 States had record high temperatures for the month. Beginning in the last week of December and
with few exceptions, the prices for future delivery in all months through next
winter have exceeded the prevailing Henry Hub spot price, often by a considerable
margin. The higher value for gas in the
future relative to current supplies poses a clear economic incentive to rely
more on current supplies and discourages heavy reliance on gas from storage.
At
the NYMEX, the price of the futures contract for March delivery at the Henry
Hub decreased almost $1 per MMBtu since Wednesday, February 1, to a settlement
price of $7.735 per MMBtu on Wednesday, February 8. While the March 2006
contract increased by about 27 cents during the Friday, February 3 trading, the
increase was not enough to offset the overall decline on the week. At $7.735
per MMBtu, the near-month contract price is the lowest since July 28, 2005,
when the September 2005 contact settled at $7.694 on its first day as the
near-month contract. The March 2006 contract price is also at its lowest level
since May 19, 2005. In trading this week, the April 2006 contract declined 94
cents, or 10.6 percent, to $7.935 per MMBtu. The 12-month strip, or the average
price for contracts over the next year, closed yesterday at $8.903, a decline
of 82 cents, or 8.5 percent on the week.
Recent
Natural Gas Market Data
Estimated Average Wellhead Prices |
||||||
|
Aug-05 |
Sept-05 |
Oct-05 |
Nov-05 |
Dec-05 |
Jan-06 |
10.02/1.0237Price
($ per Mcf) |
7.68 |
9.76 |
10.97 |
9.54 |
10.02 |
8.66 |
Price
($ per MMBtu) |
7.48 |
9.50 |
10.68 |
9.29 |
9.76 |
8.43 |
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 underground storage decreased to 2,368 Bcf as
of Friday, February 3, according to EIA's Weekly Natural Gas Storage Report. The
implied net withdrawal of 38 Bcf for the report week
was significantly lower than both the 5-year average of 158 Bcf
and last year's withdrawal of 178 Bcf (See Storage Figure). Currently, working gas stocks remain 649 Bcf or 37.8 percent
above the 5-year average and 437 Bcf or about 23 percent above last year's
level. While stocks in the East and West regions reflect implied net
withdrawals of 30 and 10 Bcf, respectively, there was an implied net injection
for the week of 2 Bcf in the Producing Region. As measured by heating degree days
(HDDs) published by the National Weather Service,
temperatures for the country as a whole were almost 32 percent warmer than
normal and about 33 percent warmer than last year for the week. (See
Temperature Maps). With 8 weeks left in the traditional heating
season, if storage is drawn down at a rate similar to the 5-year withdrawal
rate, inventories will end the heating season at about 1,700 Bcf. As of yesterday, only the near-month contract was
trading at a 15-cent discount to the Henry Hub spot price. Contracts through
the end of the next heating season (November 2006 - April 2007) were trading at
an average premium of $1.26 per MMBtu relative to the Henry Hub, indicating a
strong economic incentive to purchase natural gas at spot markets for delivery to
consumers and to refrain from withdrawing natural gas from underground storage.
LNG Imports to Continental United States
Fall in 2005: Growth in imports of
liquefied natural gas (LNG) to the continental United States stalled in 2005 as
price competition from other countries diverted volumes away from the U.S.
market. The United States imported the gaseous equivalent of 631 Bcf from a
total of seven countries, which was a decrease of 3 percent from the 652 Bcf
imported in 2004, according to the Department of Energy's Office of Fossil
Energy. Trinidad and Tobago was once again the leading supplier, accounting for
439 Bcf, or 70 percent, of U.S. LNG imports, maintaining a proportion
approximately equivalent to that of the past couple of years. In 2005, Algerian
supplies totaled 97.2 Bcf, the second highest volume of any source country for U.S.
LNG imports. Egypt, a new LNG producer and exporter in 2005, was the source
country for 72.5 Bcf during the year. The remaining 3.5 percent of U.S. LNG
imports in 2005 came from Malaysia (8.7 Bcf), Qatar (3.0 Bcf), Nigeria (8.1
Bcf), and Oman (2.5 Bcf). Dominion's regasification facility in Cove Point,
Maryland, received the greatest volume of LNG deliveries of any of the five
import facilities operating during the year (See Figure on LNG Imports to the
Continental United States by Terminal). Dominion Cove Point
received 221.7 Bcf, primarily from Trinidad and Tobago. Distrigas, located in
Everett, Massachusetts, received 168.5 Bcf, which was the second highest volume
received by the terminals. Southern LNG, located on Elba Island, Georgia,
received 132.0 Bcf, and Trunkline LNG in Lake Charles, Louisiana, received
103.8 Bcf. Gulf Gateway, a new import facility located offshore in the Gulf of
Mexico, received two cargos for a total of 5.2 Bcf.
AGA Reports a
Record Year in New Homes Built with Natural Gas:The American Gas Association (AGA) released a report
on Thursday, February 2, detailing the results of the 2004 annual Residential
Natural Gas Market Survey. The survey
found that more than 1 million single-family homes heated with natural gas were
completed in 2004, which is a new record and about 8 percent more than in
2003.Gas is the leading heating source
for all new single-family homes in 2004 with about 69 percent of these homes
heated by natural gas or propane. This
is followed by 29 percent with electric heat, 2 percent with oil, and 1 percent
with other fuel sources such as wood and kerosene. Regionally, the highest concentration of new
single-family gas-heated homes is in the Midwest and West with 91 percent
each.About 73 percent of new Northeast
homes were heated by gas followed by 45 percent in the South.Natural gas is also the leading heating
source overall. Out of the 108 million heated
housing units in the United States, 52 percent are heated by natural gas, 31
percent by electricity, 9 percent by heating oil, 6 percent by propane, and 2
percent by other fuel sources. The AGA
report also details other aspects of the residential natural gas market
including state comparisons of energy prices, bill paying assistance programs,
and customer comparisons.
EIA Releases
Its February Short-Term Energy Outlook:According to the Energy Information Administration's (EIA) latest Short
Term Energy Outlook (STEO), released February 7, total natural gas demand in
2006 is expected to remain near 2005 levels and increase in 2007 by about 2.3
percent. Domestic dry natural gas production
in 2005 is estimated to have declined by 2.7 percent, owing mainly to the
hurricane-impacted supply disruptions in the Gulf of Mexico, but it is
projected to increase by 3.0 percent in 2006 and 1.3 percent in 2007. The Henry Hub spot price in 2005 averaged
about $9.00 per thousand cubic feet (Mcf) and is projected to average $8.87 and
$8.70 in 2006 and 2007, respectively. According to the Minerals Management Service, production shut-ins
related to hurricanes Katrina and Rita still will be around 400 million cubic
feet (MMcf) per day of natural gas and 255 thousand barrels per day of crude
oil at the beginning of June 2006. During the month of January, natural gas prices were lower than
estimated in the previous (January 2006) STEO, which was a result of unusually
warm winter temperatures. Despite the
warmer-than-normal temperatures and lower than expected prices, space heating
expenditures this winter are still expected to be higher than in the 2004-2005
heating season. Homes heated with natural
gas may expect to spend $178 or 24 percent more for natural gas this winter
than last winter.
Natural Gas Transportation
Update: Natural gas pipeline
companies reported relatively few operational issues during this report
week.Gulf South announced that about 75
million cubic feet per day (MMcf/day) could be affected by unscheduled
maintenance that began last week on one of the Hall Summit Compressor Station
units. After a mechanical failure at the
Crawford Compressor Station in West Texas over the weekend, Transwestern
declared a force majeure which
reduced station capacity from 60,000 MMBtu per day to about 32,000 MMBtu per
day. A replacement compressor station is
expected to be available by today (Thursday). Florida Gas Transmission announced that it is currently scheduling
150,000 MMBtu per day of the normal 200,000 MMBtu per day at the ANR St. Landry
interconnect in South Louisiana.Lastly,
Transwestern has proposed an expansion of its West Texas Lateral to serve
customers in the Waha market area with a design capacity of 110 MMcf per
day. It is soliciting feedback through 3
p.m. this Friday.