for week ending March 8, 2006 | Release date: March 9, 2006 | Previous weeks
Overview: Thursday, March 9 (next release 2:00 p.m. on March 16, 2006)
Natural
gas spot price movements were mixed this week (Wednesday to Wednesday, March
1-8) as temperatures varied across the Lower 48 States. Spot prices at some
market locations climbed 2 to 49 cents per MMBtu
since last Wednesday, primarily in areas that experienced colder-than-normal
temperatures during the week, while price declines in the East, Midwest, and
Louisiana averaged 34 cents per MMBtu. The Henry Hub spot price decreased 14
cents per MMBtu, or 2 percent, to $6.48. At the New
York Mercantile Exchange (NYMEX), the futures contract for April delivery at
the Henry Hub fell by 9 cents per MMBtu, settling at
$6.648 on Wednesday, March 8. Natural gas in storage as of Friday, March 3, decreased
to 1,887 Bcf, which is 54 percent above the 5-year
(2001-2005) average. The spot price for West Texas Intermediate (WTI) crude oil
traded at $60.06 per barrel, decreasing $1.95, or $0.34 per MMBtu
on the week.
Spot prices received a boost this week in some regions,
as colder-than-normal temperatures were recorded across the Midwest and the
Rocky Mountains, driving space-heating demand in those regions. The spot price at the Henry Hub declined 14
cents per MMBtu since Wednesday (March 1) to $6.48
per MMBtu. Elsewhere in the Gulf producing region, price changes ranged between
a 27-cent decrease and a 32-cent increase per MMBtu. The
highest price increase during the week occurred at the Questar trading location
in the Rockies, where prices averaged $5.50 per MMBtu, 49 cents higher than a
week ago. On a regional level, the West Texas region recorded the largest average
increase, averaging 36 cents per MMBtu, followed by the Rocky Mountain region (34
cents per MMBtu) and California (30 cents per MMBtu). In contrast to the market
response to wintry conditions in the West, market locations in the Northeast
recorded considerable price decreases, despite lower-than-normal temperatures. On
the week, the average price for the Northeast trading locations decreased about
73 cents to $6.89 per MMBtu. The price off Algonquin Gas Transmission, which
serves much of New England, decreased by $1.52 per MMBtu,
or 18 percent, to an average of $6.97 per MMBtu. The price declines in the
Northeast despite the cold temperatures likely reflects market adjustments that
bring basis differentials back to more typical levels. On Wednesday, March 1,
prices in the Northeast averaged $7.59 per MMBtu, which was as much as $2 per
MMBtu higher than other market locations in the Lower 48 States.
At
the NYMEX, the futures settlement price for April delivery at the Henry Hub decreased
by about 9 cents or slightly over 1 percent, to $6.648 per MMBtu
yesterday. The April contract has been
the near-month contract for less than 2 weeks, and during this period the
contract price has decreased by more than 2 percent. Additionally, on its first
day of trading as the near-month, the April contract fell below $7 per MMBtu,
and since then has been trading in the $6.547 and $6.790 per MMBtu range. Similarly,
the May contract registered a decrease of 8 cents on the week, ending trading
yesterday at $6.858 per MMBtu. For the week, the prices of futures contracts decreased
at successively smaller amounts through the August 2006 contract. However, the
September 2006 contract and those through the end of the next heating season
(March 2007) increased. Natural gas spot and futures prices are currently in
contango (future delivery contract prices exceed current spot prices) and have
generally been so since the last week of December with few exceptions.The 12-month strip, which is the average of
the monthly futures prices for the coming year, settled at $8.347 per MMBtu, or about one-tenth of a percent less than a week
ago. As of yesterday, January and February 2007 futures contracts were the
highest priced contracts, both settling at $10.473 per MMBtu. The average price
differential between the futures contract prices for delivery next winter (November
2006-March 2007) and the Henry Hub spot price was $3.43 per MMBtu in
yesterday's trading. This difference provides
suppliers economic incentives to rely more on current supplies (production and
imports) rather than withdrawals from storage.
Recent
Natural Gas Market Data
Estimated Average Wellhead Prices |
||||||
|
Sept-05 |
Oct-05 |
Nov-05 |
Dec-05 |
Jan-06 |
Feb-06 |
Price
($ per Mcf) |
9.76 |
10.97 |
9.54 |
10.02 |
8.66 |
7.28 |
Price
($ per MMBtu) |
9.50 |
10.68 |
9.29 |
9.76 |
8.43 |
7.09 |
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 inventories were 1,887 Bcf as of Friday, March 3,
according to EIA's Weekly Natural Gas Storage Report. The implied net withdrawal of 85 Bcf for the
report week was 21 percent lower than the 5-year average of 108 Bcf and 37 percent lower than last year's withdrawal of 134 Bcf (See Storage Figure). As of yesterday, contracts through the end of the next
heating season (November 2006 - March 2007) were trading at a premium relative
to the Henry Hub. The average premium of $3.43 per MMBtu, as well as the
average 70 cent premium for the refill season (April - October), helps explain
the relatively low drawdown from storage. These premiums serve as 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. For the report week ended Thursday, March
2, warmer-than-normal temperatures prevailed in much of the western half of the
Nation, contributing to a net addition of 2 Bcf in the Producing region. The East experienced up to 26 percent
colder-than-normal temperatures, resulting in significant space-heating demand.
The East Region had a withdrawal of 77 Bcf, which is
12 percent higher than the 5-year average withdrawal of 69 Bcf
for the week. According to the National Weather Service, temperatures for the
entire Lower 48 States, as measured by gas-customer weighted heating degree
days (HDD), were about 2 percent warmer than normal, and about 13 percent
warmer than last year for the week. (See Temperature Maps)
The data for the winter months, November through February, show withdrawals
this winter have been much below average. Warmer-than-normal weather and the pervasive
premiums between future delivery contract prices and corresponding spot prices led
to an estimated cumulative net withdrawal of 1,271 Bcf, which is the lowest
total for the 4-month period since 1984. The estimated net withdrawal of 251 Bcf during January 2006 is 423 Bcf,
or 63 percent less than the 5-year (2001-2005) average January withdrawal of 674
Bcf. In comparison, weekly net withdrawals have exceeded the entire January
2006 withdrawal twice since the beginning of 1994. As of the end of February,
about 1,923 Bcf of working gas remained in underground storage, which is 52
percent above the 5-year average and 359 Bcf or 23 percent higher than last
year at the same time.
Greenhouse Gas Emissions
Reductions Associated With Natural Gas: The Energy
Information Administration released its 2004 annual report, titled Voluntary
Reporting of Greenhouse Gases, on March 6, 2006, which records
the results of voluntary measures to reduce, avoid, or sequester greenhouse gas
emissions. Although not specific to
natural gas, the report includes several natural gas related activities that
contributed to reduced emissions in 2004. Electric power projects were the most numerous project type reported in
2004, accounting for 23 percent of all projects. Since 1990, carbon dioxide
emissions from the electric power industry have increased by about 27 percent.
However, the emissions intensity of electricity generation has fallen by about
2.1 percent partly reflecting the increased use of natural gas which has lower
carbon content than coal or oil. A total
of 51 fuel-switching projects (coal or oil to natural gas) were reported for
2004, which is 3 more than in 2003 and about 10 percent of all the reported
electric power projects. Natural gas
projects also played a key role in reducing greenhouse gases through reduced
methane emissions in 2004. Although only
27 of the 443 methane reduction projects, 6 percent of the total, were listed
as natural gas production, transmission and distribution projects, they
resulted in direct methane emission reductions of about 9.4 percent of all
direct methane emission reductions. Another large source of greenhouse gas emissions reduction comes from
energy end use. For 2004, 64 entities
reported 345 energy end-use projects, accounting for 18 percent of all the
projects. Although the amount of
reductions attributable to natural gas activities is not available owing to
entities that aggregate information on a range of activities into a single
project, the report provides examples of emission reductions related to natural
gas use such as fuel switching and the use of natural-gas-fueled vehicles.
DOE Awards Funds for Coal Gasification
Project: As part of President George
W. Bush's 2002 Clean Coal Power Initiative (CCPI), the Department of Energy
(DOE) awarded a $235 million grant to aid in Southern Gas Services' development
of a combined cycle power plant fired by coal-derived gas. This project was
announced in October 2005 and in February 2006 DOE signed a cooperative
agreement that launches the design and construction of this plant. The Nation's
abundant coal resources are increasingly emerging as a key resource in the
future energy portfolio, especially in the electric power generation sector.
High oil and natural gas prices, as well as environmental constraints have led
to initiatives to identify alternative resources to natural gas in chemical
production and electric power generation.One option is coal gasification, where coal-derived gas would replace
natural gas. For electric power generation, the gas is used in an integrated
gasification combined cycle (IGCC) - a variation on a natural gas-fired
combined cycle power plant. The gas is
first passed through a gas turbine to generate electricity. The hot gas then is
used to heat water to produce steam to power a steam turbine and generate
additional electricity. The coal-derived gas also can be used as a feedstock or
fuel once it has been converted into syngas. The total projected cost of
Southern Company Service's plant, which is co-owned by Orlando Utilities
Commission and Southern Power Company, is $557 million. The plant is expected
to come on line in 2010 and expected to produce 285 megawatts of electricity,
which will power about 285,000 households. The plant will be located in Orange County, Florida, near Orlando, at
the Orlando Utilities Commission's Stanton Energy Center. Advanced emission controls will be added to
make it one of the cleanest, most energy-efficient coal power plants ever. Using the IGCC, the plant will turn different
types of coal into gas in order to generate electricity, while reducing capital
and operating cost.
EIA Releases
Its March Short-Term
Energy Outlook:According to the Energy
Information Administration's (EIA) latest Short
Term Energy Outlook (STEO), released March 7, total natural gas demand in 2006
is expected to remain near 2005 levels and increase in 2007 by about 2.4
percent. Domestic dry natural gas
production in 2005 is estimated to have declined by 3.2 percent, owing mainly
to the hurricane-impacted supply disruptions in the Gulf of Mexico, but it is
projected to increase by 2.2 percent in 2006 and 1.7 percent in 2007. According to the Minerals Management Service,
approximately 400 million cubic feet per day of natural gas production are
expected to remain offline prior to the start of the next hurricane season,
June 1, 2006 The Henry Hub spot price
in 2005 averaged about $8.98 per thousand cubic feet (Mcf) but has recently
dropped below $8 owing to weak heating-related demand this winter and the
resulting high levels of natural gas in storage. The 2006 Henry Hub spot price is expected to
average $8.11 per Mcf or about 10 percent less than in 2005. In 2007 demand is expected to increase. Heating fuel demand has been down this winter
across fuels and regions owing to the overall warm weather. 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 $126 or 17 percent more for natural gas this winter than last
winter.
Natural Gas Transportation Update: Several
maintenance projects were announced this week by pipeline companies in the
United States. Gulf South Pipeline
Company scheduled a 1-day pigging on March 9 (Thursday) of one of its lines
from Lafayette to Weeks Island in South Louisiana and another week-long pigging
starting March 14 on a segment from Lake Charles to Iowa, Louisiana. In North Louisiana, the Logansport Compressor
Station, operated by Southern Natural Gas Company, will be out of service
starting March 8 for 2 or 3 days owing to pipeline modifications at the station
and at the Spider Field tap. According
to El Paso, the ongoing force majeure involving repair at the Belen Station will
continue until further notice, reducing San Juan Crossover capacity by 35 MMcf
per day from a base capacity of 650 MMcf per day.Questar
Corporation announced maintenance plans at its Oak Spring Compressor
Station for March 21-23. Capacity at
this location will be reduced by about 30 percent during the maintenance. Lastly,
Northern Natural Gas Company has contracted a repair crew and dive boat to
repair a leak site on the Northern-operated Matagorda Offshore Pipeline System
offshore Texas. After setbacks because
of logistical constraints, Northern Natural Gas said it expects restoration of
all but three platforms downstream of Matagorda 758 sometime on March 9. In
addition to maintenance announcements, ANR Pipeline Company announced that it
will be limiting storage account activity owing to current and projected
storage inventory and the current weather outlook. Customers are not allowed to exceed their
account balances as of March 2. Also, Southern Natural Gas announced
an open season for bids on 140 MMcf per day of capacity in the Production Zone on
the South Mainline system. Ninety MMcf per day will become available on February
1, 2007, and the other 50 MMcf per day will become available on March 1, 2007.