Note:  The following was sent out by CERA and has a short term forecast of 
prices and alternate fuel pricing.  Note the price differential forecasts by 
basin.

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CERA Alert: Sent Wed, November 15, 2000
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Title: Midmonth Report: Early Warning
Author: N. American Gas Team
E-Mail Category: Alert
Product Line: North American Gas ,
URL: http://www.cera.com/cfm/track/eprofile.cfm?u=5526&m=1420 ,

Alternative URL: 
http://www.cera.com/client/nag/alt/111500_18/nag_alt_111500_18_ab.html
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After a warm October, the first cold weather this year
has provided an early warning of what winter could bring
for the gas market. Cold weather across much of the
great plains and a cold forecast for larger heating
markets in the Midwest and Northeast have driven a surge
in gas prices of more than $1.00 per million British
thermal units (MMBtu) over the past week. This rebound
in price highlighted the continued tightness of supply
and moved the price of gas back above that of residual
fuel oil, assuring that dual-fuel loads remain off of
gas. Supplies for the winter are not adequate to allow
most dual-fuel end users to burn gas. If this cold snap
extends through the remainder of November, a heavy
early-winter draw on storage could set the stage for
unprecedented high prices through the winter.

Though storage inventories have reached near the 2,750
billion cubic feet (Bcf) level, they remain at a record
low heading into the heating season, and even a normal
winter would reduce inventories to a near record or
record absolute low by spring. This supply tightness
places the gas price playing field in the broad
territory above the resid price (near $5.00 in the Gulf
Coast) and into a range potentially testing the next,
difficult level of demand resistance. This resistance
could come from switching to distillate oil, but low
distillate inventories and high distillate prices mean
that switching would require a gas price above $7.50 per
MMBtu, and any move to switch to distillate would likely
drive prices of both commodities higher. Rather, a
combination of some switching to resid in industrial
boilers and a shutdown of a few more price-sensitive end
users may be required. None of these measures comes
easily or cheaply, however, and they can be overwhelmed
by weather-driven swings in demand. As a result, as cold
weather settles in, CERA expects heightened price
volatility at levels above the price of resid and
extreme sensitivity in the market to weather and weather
forecasts. Under normal weather conditions, CERA expects
Henry Hub prices to average $5.70 during December (see
Table 1), which by itself would represent an all time
high for December. But even this estimate could prove
low. If the current cold snap extends through early
December, prices could easily climb into the $6.50-$7.00
per MMBtu range.

Gas Storage-The Record Low Maximum
CERA estimates that storage inventories reached a
maximum of 2,746 Bcf as of the end of October, a record
low for that month by 64 Bcf (see Table 2). Even this
level was reached only through a fortunate combination
of a lack of storms in the Gulf of Mexico and consistent
warmth through most of October. The withdrawal season is
likely to have begun this week, however, and in a strong
way. The cold weather now settling in is likely to
offset warmth early this month, increasing the
withdrawal rate this November to 3.5 Bcf per day on
average, well above the 1.0 Bcf per day average rate of
the past two years. By the end of this month, the US
inventory deficit is likely to have widened again, to
350 Bcf.

CERA estimates that normal December weather would
require storage withdrawals of approximately 17.0 Bcf
per day, which is above last year's rate of 16.6 Bcf per
day. This year, however, this withdrawal rate would
apply consistent pressure in the market through December
and beyond, as it would keep inventories on a path to
reach 756 Bcf by the end of March, just below the 1996
all-time end-of-March low of 758 Bcf. So long as
inventories remain on this path the pressure does not
end even with the end of winter, as a significant
increase in injections next year would be required for
inventories to reach even 2.6 trillion cubic feet (Tcf)
by next fall. Although the supply build will begin to
help by late winter, it is unlikely to be of the
magnitude required both to offset power generation
demand growth and to allow this increase in storage
injections to occur-unless demand continues to be priced
out of the market.

Demand-Keeping Warm
After last year's warm winter, CERA expects a strong
rebound in heating demand, and this week's weather and
forecast reinforce that expectation. Weather last winter
(November through March) was the warmest of the decade,
and there will be a significant rebound in heating
demand in the residential and commercial sectors as
weather returns toward normal this heating season.

Under normal weather conditions,
* Average heating demand through the winter would be 3.5
Bcf per day higher than last year's.

* Monthly average heating demand through the winter
would be 36.7 Bcf per day, peaking at 45.6 Bcf per day
in January.

* December heating demand would increase by 4.8 Bcf per
day relative to last December.

Weather 5 percent colder than normal could further
increase December demand by 1.8 Bcf per day relative to
normal weather; likewise, a 5 percent warmer-than-normal
scenario could decrease demand by 1.7 Bcf per day
relative to normal weather.

Fuel Switching
With natural gas markets this tight, there is
significant pressure for demand to be backed out of the
market. Residential and commercial demand is inelastic
to price in the short run, which leaves industrial
demand and power demand as the only relief valve for the
market. This winter we expect

* all plants capable of burning residual fuel oil as an
alternative to gas to do so

* a loss of 700 million cubic feet (MMcf) per day of
demand for power generation relative to last winter

* industrial consumers to switch the equivalent of 500
MMcf per day off of gas

* gas prices to act as a ceiling for residual fuel oil
prices, as much as resid will act as a floor for gas

For December CERA expects an overall demand increase of
4.5 Bcf per day relative to last December and a 14.4 Bcf
per day increase in demand relative to November, with
increasing heating load offset somewhat by fuel
switching.

Supply-The Rebound
The pressure from increasing demand and lower storage
inventories is intense, but US supply is beginning to
rebound. The recent steep decline in US lower-48
capacity is expected to reverse in late 2000, given the
soaring gas-related rig count.

* The success in reversing the decline in the Gulf of
Mexico is related to the combination of

- the ramp-up of the Hickory and Tanzanite subsalt
discoveries on the shelf, adding to the recent startup
of the Muni field; these fields could add over 0.5 Bcf
per day later in 2001

- the response of the shallow water to the strong
late 1999 turnaround in drilling activity

* Other important capacity additions are occurring in
the deepwater Gulf of Mexico, with 0.5 Bcf per day in
2000 and 2001, and onshore, led by the Bossier sand play
in Freestone County, Texas, the Barnett Shale play in
Wise County, Texas, and the Powder River Basin coal seam
play.

* Further increases in drilling are likely to slow. New
deep land rigs are under construction and shallow rigs
are being refurbished with cannibalized parts from older
rigs. Producers are experiencing delays in obtaining
rigs as the supply of quality rigs depletes and drilling
companies struggle to round out drilling crews.

Regional Markets-Wild Winter in the West
Extremely cold weather in the West has brought Rockies
prices close to parity with Henry Hub prices and
triggered early season spikes at Sumas in the north and
Topock in the south. Pipeline maintenance on El Paso is
exacerbating the regional demand pressure and has
contributed to Topock differentials of over $2.00 per
MMBtu. Tight pricing relationships to the Henry Hub in
the San Juan and Rocky Mountains should hold through
February, with significant widening in differentials as
heating loads decline.

Winter has arrived in earnest across North America, but
the start-up of firm transportation service on Alliance
is delayed once again, this time until December 1.
Nonetheless, flows on the pipeline are under way; CERA
estimates that flows during October averaged 450 MMcf
per day. During November that total should climb to 750
MMcf per day, despite the later published start date.
With or without Alliance flows, a weather-driven rebound
in midwestern demand relative to November and December
last year should keep prices in Chicago at a significant
premium to Henry Hub prices. In the Northeast,
differentials remain extremely strong and exposed to
spikes throughout the winter, despite greater flows into
the region from Atlantic Canada this year (see Table 3).

CERA's outlook by region follows:
* Rockies. Very cold weather within the region has
brought Rocky Mountain prices near parity with Henry Hub
prices. A break in the cold or a cold snap in the East
will likely widen the differentials, but strong heating
demand in the region will keep differentials within
about $0.25 per MMBtu below the Henry Hub price. CERA
expects a December average differential of $0.25 per
MMBtu; however, this differential is expected to show
significant volatility based on regional weather. A warm
week in the Rockies could still push differentials
toward $0.50 per MMBtu.

* San Juan. San Juan prices will continue to hold close
to Rockies prices through the winter, with significant
pipeline capacity between the two regions. Heating loads
in the Rockies will determine the San Juan to Henry Hub
differential, with extended cold weather in the Rockies
pulling both prices close to the Henry Hub price. CERA
expects the December differential in the San Juan Basin
to average $0.20 per MMBtu.
* Permian and Mid-Continent. Unlike prices within the
rest of the West, differentials between the Henry Hub
and the Mid-Continent and Permian Basins are likely to
trade within a relatively narrow range during the
winter, as supplies from those basins are pulled either
east or west, depending on regional weather. CERA
expects a Permian to Henry Hub differential of $0.11 per
MMBtu and a Mid-Continent differential of $0.08 per
MMBtu for December.
* Chicago. Alliance flows into the Chicago market are
now running close to 750 MMcf per day. However, the
onset of the heating season has offset those increased
flows and pushed Chicago differentials up to near $0.15
per MMBtu relative to the Henry Hub, despite delays in
the completion of the Vector pipeline. CERA expects the
strong pricing at Chicago to continue, and December
differentials should average $0.25 per MMBtu.

* Northeast markets. Assuming normal weather, we expect
to see December basis for New York relative to Henry Hub
at $1.03 per MMBtu. New England will likely see prices
$0.05-$0.15 higher, depending on the pipeline. Much of
this increased basis differential is caused by fuel
costs. For example, with a 9 percent retention rate from
the Gulf Coast into New England, last December would
have seen retention costs of approximately $0.22; at
$5.70, that same retention equates to $0.50. Despite
additional volumes of gas deliverable into the Northeast
from the Atlantic Canadian fields, there have been no
additional regional pipeline facilities to deliver this
gas to the local markets, and an additional 166,000
MMBtu per day of potential demand will compete for the
capacity. Because of this tightness, should this month's
weather be colder than normal, we could see severe
spikes in basis similar to those seen in January 2000.
These spikes could even exceed the highs seen in
January, depending on the severity of any cold snaps and
the extent to which new electric loads are realized.

Canadian Markets-Winter Begins
The colder-than-normal weather has increased demand in
western Canada but is only now being felt in the East.
Storage peaked in the West in early October at
approximately 225 Bcf below last year's level and 6 Bcf
below the five-year average. Even with modest
withdrawals since that time, storage inventories are
still estimated to be adequate to meet winter needs.
Easter Canadian storage has continued to grow, pushing
levels to over 245 Bcf, 11 Bcf above last year and well
above the five-year average. With the eastward movement
of the colder weather, withdrawals are likely to begin.
This higher level of eastern storage will be useful with
the expected reduction of flows on TransCanada.

The good news resulting from the cold is a more normal
"freeze-up," which bodes well for a longer winter
drilling season. Gas well completions are expected to
reach 8,500 for 2000 and will likely be even higher next
year.

Further Delays for Alliance?
The "commercial" in-service date for Alliance has been
delayed until December 1, the result of a combination of
problems with clearing the line, delays in the
completion of the Aux Sable liquids extraction plant,
the delay of Vector, and a lack of supply. The pipeline
has been flowing gas, however, with volumes building up
since September. It is estimated that flows for November
will average 750 MMcf per day. TransCanada has taken the
full brunt of the Alliance flows so far, with Northern
Border and PGT remaining strong. December should see
Alliance flows build to between 900 and 1,000 MMcf per
day, with modest reductions in flows on Northern Border
and PGT. Storage withdrawals will likely keep
TransCanada reductions close to 350 MMcf per day, year-
over-year, until Vector begins service to eastern
Canada.

High Prices: Strong Pull West
The high demand in the Pacific Northwest has also
provided strength for AECO. The AECO-Henry differential
has dropped to the high $0.30s and low $0.40s as a
result of this increased pull. For December, the
differential is expected to average $0.50 per MMBtu, for
a resulting AECO average of C$6.97 per gigajoule
(US$5.10 per MMBtu).

**end**

Follow URL for PDF version of this message with associated Tables.

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CERA's Autumn 2000 Roundtable event dates and agendas are now available at 
http://www.cera.com/event
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