Overview: Thursday, August 2, 2007 (next release 2:00
p.m. on August 9, 2007)
Natural
gas spot prices increased this week (Wednesday-Wednesday, July 25-August 1) as tropical
storm activity increased and weather-related demand returned along with normal
summertime heat in large market areas in the East. On the week, the Henry Hub
spot price increased 62 cents per MMBtu, or 11.1
percent, to $6.19. At the New York Mercantile Exchange (NYMEX), the futures contract
for August delivery expired last Friday (July 27) at $6.11 per MMBtu. Although
the price of the expiring contract in the last couple days of trading rose
slightly, the expiration price was still the second lowest of the year (the
January 2007 contract expired at $5.838). Taking over as the near-month contract,
the September 2007 contract increased in price by $0.29 per MMBtu on the week
to $6.352. EIA’s Weekly Natural Gas Storage Report today reported natural
gas storage supplies of 2,840 Bcf as of Friday, July
27. This level of working gas in underground storage exceeds the maximum level
of the previous 5 years. The spot price for West Texas Intermediate (WTI) crude
oil increased $0.75 per barrel on the week to $76.49 per barrel. On a Btu basis,
the crude oil price is now more than double the price of natural gas at $13.19
per MMBtu.
After
dropping below $6.00 per MMBtu for all of the prior calendar week, the Henry
Hub spot price increased 51 cents on Monday following reports of tropical storm
activity and the return of seasonal weather in market areas. The Henry Hub
price ended this report week (the week ending Wednesday, August 1) at $6.19 per
MMBtu, which reflects an increase of 62 cents or 11.1 percent. As a result, the
Henry Hub spot price at the beginning of August was nearly the same as it was
at the beginning of July ($6.24 per MMBtu on July 1). Although Tropical Storm
Chantal may have caused some jitters in the market on Monday, it will not
affect production. Nevertheless, storm activity appears to be increasing, and
the National Hurricane center is watching low-pressures systems in the
Caribbean and Gulf of Mexico as of this writing. Meanwhile, temperatures returned
closer to normal in the East, boosting demand for natural gas as a fuel for
power generation to meet air-conditioning needs. For the report week, prices at
production-area trading locations along the Gulf Coast generally increased
between $0.48 and $0.79 per MMBtu (excluding an isolated
gain of more than $1 at Florida Gas Transmission Zone 3) to a regional average
of $6.24 in Louisiana and $6.02 in East Texas. Trading at Rockies
production-region locations, where relatively abundant supplies lack access to
markets, yielded the smallest gains of the week (as well as a net decline in
price at the Kern River trading point) and continued large price differentials
with other markets in the Lower 48 States. The average price in the region
yesterday was $4.42 per MMBtu, or $1.77 less than yesterday’s Henry Hub price. At
$3.51 per MMBtu as of Wednesday (August 1), the price at the Questar pool in
Utah was the lowest in the Lower 48 and a mere 8 cents higher than the previous
Wednesday. Following an average increase of 93 cents per MMBtu for the week in
the Northeast, prices at some trading locations exceed $7. Off Transcontinental
Gas Pipe Line in New York City, the average price yesterday was $7.20 per
MMBtu, or $1.15 cents higher on the week.
At
the NYMEX, the price of the futures contract for August delivery increased in the last 2 days of trading to reach $6.11
per MMBtu by its expiration as the near-month contract last Friday (July 27).
Nonetheless, the August contract expired near a low-point in its trading
history. For example the expiration price was $2.25 per MMBtu, 27 percent,
below its high for 2007 of $8.362 (on May 17). The August 2007 contract also
expired at a price substantially lower than the August 2006 price. Last year,
the August contract expired at $7.042 per MMBtu, about 93 cents more than the
expiration price of the August 2007 contract. During this report week, the September
2007 contract rose 29 cents per MMBtu, or about 4.8 percent, to $6.352, owing
at least in part to increased storm activity and hotter weather. The prices of
all futures contracts for the next 12 months all increased this week, albeit in
lesser amounts than the near-month contract. As a result, the price of the
12-month strip, or the average price for contracts over the next year, increased
20.7 cents per MMBtu, or less than 2.8 percent, to $7.97. The price of the new near-month
contract is $1.46 per MMBtu lower than last year’s price at this time (on
August 1, 2006, the September 2006 contract settled at $7.574 per MMBtu). The
difference between the current Henry Hub price and the price for the NYMEX
contract for delivery this January (the month that is normally the highest
price in the 12-month strip) is now $2.57 per MMBtu, providing a substantial
economic incentive to place natural gas in storage for delivery next winter.
Recent Natural Gas Market Data
Working gas in underground
storage was 2,840 Bcf as of July 27, which is 16.9 percent above the 5-year
average inventory level for the report week, according to EIA’s Weekly Natural
Gas Storage Report (see
Storage Figure). Current inventory levels are now 68
Bcf more than at this time last year and 410 Bcf higher than the 5-year
average. The implied net change for the week was 77 Bcf, which is significantly
higher than both the estimated net injection of 15 Bcf last year at the same
time and the 5-year average of 51 Bcf. Cooling degree-day (CDD) statistics
published by the National Weather Service for the period roughly coinciding
with the week covered by the storage report show that temperatures were significantly
lower relative to normal in most Census Divisions (see Temperature
Maps). For the United States as a whole, CDDs totaled
about 16 percent less than normal, which would have lowered weather-related gas
demand. In the West South Central Division, which includes Texas’ numerous
gas-fired power plants, CDDs were 22 percent less than normal. Temperatures in Census Divisions in populous
regions including the Northeast were also lower than normal. In the Middle
Atlantic Census Division, for example, CDDs numbered 25 percent lower than
normal during the report week.
Other Market
Trends:
NEB Releases Study on Hydrocarbon Pipeline Capacity: According to the July 27, 2007, National Energy
Board (NEB) study, Canadian crude oil pipelines could be facing a
transportation bottleneck this fall, as there likely will not be enough
pipeline capacity to transport the crude oil produced in Alberta’s oils sands.
Natural gas pipelines, on the other hand, have spare capacity even during
winter, when demand for natural gas hits seasonal peaks. The report notes that
between January 2003 and January 2007, there has consistently been capacity in
excess of throughput volumes, which persisted through the warmer-than-normal
summers of both 2005 and 2006, as well as following hurricane induced
production losses in the Gulf of Mexico. Both circumstances resulted in an
increase in demand for Canadian natural gas in the United States. The eastern
part of the TransCanada system, which connects to U.S. pipelines in New England
(at Iroquois and Niagara Falls), underwent a number of expansions in 2006 that
are directed towards connecting to additional supply from Dawn, Ontario, and to
access markets in the U.S. Northeast. This resulted in average excess capacity
of 1.4 Bcf per day over the past 4 years. Similarly, the average annual
capacity utilization on TransCanada’s Foothills Pipeline, which connects to
markets in the Midwest (through the Northern Border Pipeline), was 88 percent
in 2006, a significant decrease from an average of 94 percent in 2003.
TransCanada’s B.C. (British Columbia) system, which primarily serves
California, showed an annual average capacity utilization of 64 percent in
2006, slightly higher than in previous years despite competing with supplies
from the Rocky Mountains, and San Juan and Permian basins.
Natural Gas Transportation Update:
●
Northern Natural
Gas Company declared a force majeure on July 30 reporting that it is
investigating a possible leak on the 26-inch C East Leg pipeline east of the
Earlville, Iowa, compressor station. As a result of the force majeure, the
company lowered the line pressure in order to inspect the pipeline and
determine if there is any damage. As a result, primary firm service is being
allocated as of the July 31 gas day. The force majeure is expected to remain in
place until the repairs have been completed, which should occur by August 4 according
to the pipeline.
●
Questar Pipeline
Company reported experiencing mechanical failure at its Greasewood compressor
station, as a result of which nominations to Trans Colorado Interstate Pipeline
were reduced to 30,000 decatherms (Dth) per day on July 26. Because the repairs
were completed the same day, the pipeline was able to increase the capacity at
the interconnect to 45,000 Dth the same
day.
●
Questar also
announced that owing to seasonal operating conditions, it reduced the injection
capacity at its Clay Basin Storage Facility to 325,000 Dth per day.
Additionally, 25,000 Dth per day of capacity will be available for park and
loan. The new capacity was effective with the cycle 1 gas day August 2 and is
expected to last until November 1, 2007.
●
Pacific Gas and
Electric issued a systemwide Stage 2 high inventory operational flow order
(OFO) for Saturday, July 28. Penalties were set at $1 per Dth for exceeding a 5
percent tolerance level for positive daily imbalance.
●
Sea Robin
Pipeline issued an OFO for all offshore receipt points for Saturday, July 28,
through Monday, July 30. The OFO resulted from imbalances that existed at the
time, along with those that continued to build, leading to an unacceptable
increase in pressure.
●
ANR Pipeline
Company announced on Monday that it began unplanned engine repairs at the St.
John Compressor Station in Indiana, located in the northern fuel segment. The
total St. John west-east capacity was reduced by 115 MMcf per day on August 1,
leaving 1,190 MMcf per day available.
