Overview: Thursday, November 8, 2007 (next release 2:00
p.m. on November 15, 2007)
Natural
gas spot price movements varied this week (Wednesday-Wednesday, October
31-November 7). Prices in Lower 48
market areas in the West and the Midcontinent decreased significantly on the
week. Other regions, however, most notably the high-demand areas of the
Northeast and the Midwest, as well as Gulf Coast production areas, recorded
price increases. The spot price at the Henry Hub gained 16 cents per MMBtu, or about 2 percent, to $7.42 per MMBtu.
In contrast to the spot market, prices of futures contracts at the New York
Mercantile Exchange (NYMEX) for the next 12 months uniformly decreased, with
the futures contract for December delivery at the Henry Hub decreasing about 71
cents since last Wednesday to close yesterday (November 7) at $7.624 per MMBtu. Working gas stocks as of Friday, November 2,
again hit a record high with 3,545 Bcf in storage,
which is 8.9 percent above the 5-year average. The spot price for West
Texas Intermediate (WTI) crude oil increased $2.30 per barrel, or 2.4 percent,
since last Wednesday to trade yesterday at $96.46 per barrel or $16.63 per MMBtu. Yesterday’s crude oil price was $37.52 per barrel
higher than the year-ago level, when crude oil traded at $58.94 per barrel on
November 7, 2006.
Natural
gas spot price movements in the Lower 48 States varied during the report week.
Seasonally moderate temperatures in some regions of the country this week
(Wednesday-Wednesday) likely limited heating demand in many market areas;
however, some heating demand emerged in key market areas such as the Northeast,
parts of the Midwest, and in the South that resulted in price upticks on the
week. Prices at market locations in and to the west of the Rocky Mountains, as
well as in the Midcontinent, generally decreased on the week, with wide-ranging
declines between 9 cents and $3.44 per MMBtu. Average spot prices in the
Rockies were $3.42 per MMBtu on Wednesday, November 7, with seven locations
recording prices below $2 per MMBtu. The low prices in the Rockies,
particularly at Cheyenne Hub, which traded yesterday at $1.75 per MMBtu, are
expected to recover in the near future. Cheyenne Plains Gas Pipeline Company
announced the restoration of full system capacity of 874 MMcf per day on the
eastbound line. Capacity had been limited to 590 MMcf per day since
mid-September, when a compressor station fire forced the reduction. The price
decreases in the West and the Midcontinent were not matched elsewhere in the
Lower 48 States, as trading locations along the Gulf of Mexico and in the
Northeast and Midwest mostly recorded increases on the week. The Henry Hub spot
price increased 16 cents or about 2 percent on the week to $7.34 per MMBtu.
Other market locations in Louisiana had price increases on the week between 3
and 31 cents resulting in a regional average price of $7.58 per MMBtu. Average
prices in key Northeast and Midwest consuming areas as of yesterday were $8.08
and $7.39 per MMBtu, respectively. The spot price off the Algonquin citygate,
which supplies New England, including the key market area of Boston, increased
77 cents on the week to $8.57 per MMBtu.
The
price of the NYMEX futures contract for December delivery decreased about 71
cents, or 8 percent, since last Wednesday (October 31) to settle at $7.624 per MMBtu yesterday. Similarly, the contracts for delivery
during the remainder of the heating season (January-March) all decreased on the
week. During yesterday’s trading, prices of heating season futures contracts
decreased for the fourth session in a row, as mild weather is expected to keep
demand lower, according to new forecasts. Record-high volumes of gas in storage
also are thought to have contributed to the futures price decreases, as the
apparent supply seems to have eased concerns about tightness in the market for
now. On the week, the January 2008 contract decreased 66 cents or about 8
percent, settling yesterday at $7.996 per MMBtu, while the February 2008
contract, which was the highest priced contract, settled yesterday at $8.061
per MMBtu, or 7 percent lower than last Wednesday. The 12-month strip decreased
about 50 cents or 6 percent per MMBtu this week to $7.906 per MMBtu. The
differential between the Henry Hub spot price and the price of the futures
contracts this winter decreased this week. At the close of trading yesterday,
the price for delivery during peak winter months (December 2007 through February
2008) averaged about 47 cents per MMBtu more than the
Henry Hub price, decreasing considerably from the differential throughout most
of October, during which the differential reached as high as $1.991 per MMBtu.
Recent
Natural Gas Market Data
Working
gas in storage reached a record level for the second week in a row with 3,545 Bcf as of Friday, November 2. Factors contributing to the large volume in
storage include improved supply and favorable economics (see the recap of the
refill season at the end of this section).
The 3,545 Bcf is 8.9 percent above the 5-year average inventory level
for the report week, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure).
The net injection of 36 Bcf for the week contrasts sharply with both the 5-year
average net injection of 17 Bcf and last year’s withdrawal of 7 Bcf for the
report week. Natural gas stocks as of November 2 were 99 Bcf higher than at
this time last year and 291 Bcf higher than the 5-year average. While net
withdrawals are more typical for this time of year, this week’s net injection
reflects the seasonally moderate temperatures that prevailed across the Lower
48 States. Overall, temperatures were 15 percent warmer than normal and about
20 percent warmer than last year for the week (see
Temperature Maps). All Census
Divisions with the exception of West South Central recorded warmer-than-normal
temperatures, including New England, Middle Atlantic, and East North Central,
which recorded temperatures that were 14, 16, and 12 percent warmer than
normal, respectively.
Recap of the 2007 Natural Gas Injection
Season: The 2007 refill season (April
1-October 31) ended with an estimated 3,535 Bcf of working gas in storage,
which is the highest volume ever recorded. Natural gas inventories ended the
2006-2007 heating season with the second highest volume in storage for that
time of year since 1991 and then remained above historical averages throughout
the refill season. In all, 1,932 Bcf was
injected into storage during the refill season, which equals 97 percent of the
5-year (2002-2006) average. The
difference between actual net injections and the 5-year average is the
equivalent of 0.23 Bcf per day for the season.
The
record working gas stocks are attributable to a number of factors. First,
natural gas supplies in the past refill season were larger than the levels of
2006. Absence of significant tropical
storm activity or other supply disruptions contributed to an increase in
domestic production. Additionally, U.S. LNG imports for the April-August 2007
period were more than 168 Bcf, or 56 percent, higher than the level in
2006. However, the relative increase in
LNG imports for the entire refill season likely will not be at such a high
rate. As a result of several LNG
producers not being able to maintain full production levels and relatively
higher natural gas prices in other LNG-importing countries, the number of
cargoes that reached the U.S. terminals in September and October was
significantly lower than at the onset of the 2007 refill season, according to
trade press reports.
A
second factor contributing to the record storage levels was the favorable
economics that prevailed throughout the refill season. Average NYMEX contract prices for delivery during
peak winter months (December 2007 through February 2008) were in strong
contango with the Henry Hub spot prices.
The average differential for the season was $2.02 per MMBtu, which would
have exceeded expected storage costs by a considerable margin. These clear arbitrage opportunities for
holders of capacity would have been a significant economic incentive to inject
into storage or continue holdings of natural gas already in storage. Without supply disruptions or unexpected
weather-driven demand surges, the accumulation of gas in storage continued at a
pace sufficient to eclipse the previous record level.
Other Market Trends:
EIA Releases Advance Summary of Its 2006 Annual
Reserves Report: The Energy Information Administration (EIA) released the Advance
Summary: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006
Annual Report on November 5, which presents highlights of
petroleum industry activity that affected oil and natural gas proved reserves
and production during the year. According to the report, proved natural gas
reserves rose by 3 percent in 2006 to more than 211 trillion cubic feet (Tcf),
which extended the trend of year-over-year increases to 8 years. The level of
proved reserves in 2006 marks the highest level since 1976. Reserve additions
replaced 136 percent of 2006 dry gas production in 2006. Texas added the largest amount of gas
reserves in 2006, a 9-percent increase, mainly as a result of the rapid
development of Barnett Shale reservoirs in the Newark East Field. Total discoveries of natural gas reserves,
which comprise field extensions, new field discoveries, and new reservoir
discoveries in old fields, amounted to 23.3 Tcf. This was 1 percent more than in 2005 and 35
percent more than the previous 10-year average of 17.2 Tcf. Most natural gas total discoveries in 2006
were from extensions to existing gas fields.
Field extensions amounted to 21.7 Tcf or 3 percent of discoveries. Coalbed methane
accounted for 9 percent of proved dry gas reserves and 9 percent of dry natural
gas production. U.S. crude oil proved reserves declined by 4 percent in
2006 because of downward revisions and fewer new discoveries. Reserve additions of crude oil fell short of
production; operators replaced only 52 percent of 2006 crude oil production
with reserve additions. Crude oil proved reserves in the Gulf of Mexico Federal
Offshore and Alaska declined by 10 and 7 percent, respectively.
EIA Releases a
Report on Natural Gas Compressor Stations: The Energy Information Administration (EIA)
released a special report titled Natural
Gas Compressor Stations on the Interstate Pipeline Network: Developments Since
1996, which examines the use of natural gas pipeline compressor
stations on the interstate natural gas pipeline network that serves the Lower
48 States. The report also discusses compression facilities added over the past
10 years and how the expansions have supported pipeline capacity growth
intended to meet the increasing demand for natural gas. According to the
report, mainline natural gas pipeline compressor stations constitute a
significant element of the infrastructure that makes up the national pipeline
network. These facilities advance the flow of natural gas and ensure its
continuous flow between supply areas and consumers. As of 2006, a total of 1,201
compressor stations were operating on the interstate pipeline network. They are
generally situated between 50 and 100 miles apart along the system with an
average capacity of about 700 MMcf per day. The number of compressor stations
increased significantly since 1996, when 1,047 mainline compressor stations
were operating and pipeline companies reported investment in mainline
compressor station equipment of $9.4 billion. In 2005, however, the interstate
natural gas pipelines that owned and/or operated mainline compressor stations
reported plant costs or investment expenditures of more than $15 billion for
compressor station equipment, second only to the $50 billion they reported as
invested in natural gas transmission pipeline. Further increase in compressor
station infrastructure is expected to occur in the future, as more than 183 gas
pipeline projects were proposed for completion between the end of 2007 and
2010. These projects could result in 42 new compressor stations and 53
expansions of existing stations.
EIA Releases
Its November 2007 Short-Term Energy Outlook: In its latest Short-Term
Energy Outlook (STEO), released November 11, the Energy Information
Administration (EIA) projects that the Henry Hub spot price will average $6.94
per thousand cubic feet (Mcf) for October 2007 and reach $8.65 per Mcf in
January 2008. On an annual basis, the
Henry Hub spot price is expected to average about $7.30 per Mcf in 2007 and
$8.01 per Mcf in 2008. The high level of
natural gas in storage and limited fuel switching capability have mitigated the
impact of the recent petroleum product price increases on natural gas prices. Total natural gas consumption in 2007 is
expected to average 62.2 billion cubic feet per day (Bcf/d), an increase of 4.5
percent over the 59.50 Bcf/d in 2006.
The increase was mostly due to growth in the residential, commercial and
electric power sectors. In 2008, total
consumption is expected to continue to grow by 0.9 percent. Total dry natural gas production is expected
to increase by 1.4 percent in 2007 and by 1.3 in 2008. This growth in production is expected despite
an expected decline in Federal Gulf of Mexico (GOM) production of 2.8 percent
in 2007. The downward trend in GOM
production is projected to reverse in 2008 with an increase of 7.4 percent
resulting from developing deepwater supply infrastructure. Liquefied natural gas (LNG) imports slowed
since earlier in 2007 because of higher relative prices in other LNG-consuming
countries, which resulted in redirecting cargo away from the United
States. Nevertheless, LNG imports in
2007 are expected to be 39 percent higher than in 2006. For the first time, working gas stocks have
exceeded 3.5 Bcf; as of October 26, working natural gas in storage was 3,509
Bcf
Natural Gas Transportation Update:
·
California Gas
Transmission Pipeline Company issued a systemwide stage 2 high-inventory
operational flow order (OFO) for November 5 with penalties set at $1 per
decatherm (Dth). On November 7, the
company announced another systemwide stage 2 high-inventory OFO, also with
penalties set at $1 per Dth. The OFO did
not continue beyond Wednesday, November 7.
· On November 1, Florida Gas Transmission Company began pipeline maintenance upstream from compressor station number 6, located in Texas. Maintenance is expected to last about 15 days. During this project, the company will schedule up to approximately 150,000 million Btu (MMBtu) per day. Normally 300,000 MMBtu per day is scheduled.
·
Northern Natural Gas Company issued a force majeure that is expected to last from
November 3 to November 21 at the Perryton Barlow compressor station in
Ochiltree County, Texas. According to
the company, the station’s dehydration system is currently not operational,
requiring the pipeline company to shut in the station until repairs are
completed. During this period capacity will be zero.
· Cheyenne Plains Gas Pipeline Company announced that repairs have been completed on the compressor at the Cheyenne Plains Compressor Station and Treating Plant, in Colorado. Operationally available capacity was expected to increase on Wednesday, November 7, to 816 million cubic feet per day (MMcf/d) at the Cheyenne Plains West constraint point and 874 MMcf/d at the Cheyenne Plains East constraint point.
· On November 6, the El Paso Natural Gas Company announced a force majeure because of turbine mechanical failure at the Alamo Lake number 2 station. The station is located in La Paz County, Arizona. The estimated timeframe for the repair is approximately 2 weeks. According to the company, the force majeure will result in a reduction of 100 MMcf/d from the estimated base capacity of 620 MMcf/d on the Havasu Crossover.
