---------------------- Forwarded by Vince J Kaminski/HOU/ECT on 07/19/2000 
06:47 PM ---------------------------


webmaster@cera.com on 07/14/2000 10:04:13 PM
To: vince.j.kaminski@enron.com
cc:  
Subject: Monthly Briefing: The Pressure Remains - CERA Alert




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CERA Alert: Sent Fri, July 14, 2000
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Title: Monthly Briefing: The Pressure Remains
Author: N. American Gas Team
E-Mail Category: Alert
Product Line: North American Gas ,
URL: http://www.cera.com/cfm/track/eprofile.cfm?u=5166&m=1272 ,

Pressure in the North American gas markets remains intense, despite moderate 
summer weather that so far has allowed storage injections to average over 10 
billion cubic feet (Bcf) per day. High injection rates have provided 
occasional relief for prices, but summer is far from over. The absolute level 
of storage inventories remains critical, and the prices should stay above the 
$4.00 per million British thermal units (MMBtu) level through August. The 
competition between power generation and storage for supply will continue, 
and gas prices must remain high enough to discourage marginal end-use demand 
and allow low storage inventories to build. CERA expects an average price of 
$4.20 per MMBtu at the Henry Hub for August (see Table 1), which will result 
in continued burning of residual fuel oil by the Atlantic Coast dual-fuel 
market and continued ammonia plant shutdowns, which began during the May and 
June price increases.

Although continued strong storage injections would take some pressure off the 
gas market, a shift to a lower pricing plane--below $4.00 per MMBtu--depends 
on sustained mild summer weather. CERA expects gas demand for power 
generation to climb through the end of July and into August, and higher 
temperatures and power loads will limit supply that is available for 
injections. The pressure in the market is likely to tighten over the weeks to 
come, and the market will remain vulnerable to price spikes above $4.50 per 
MMBtu through August and September.

Gas Storage--Not Yet Enough
Despite recent high storage injection rates, storage inventories are not high 
enough to ensure that supplies will reach adequate levels for next winter. An 
end of mild weather in the Midwest and Northeast and seasonally intense heat 
in the Southwest would cause injection rates to decline significantly over 
the remainder of July and into August. The result would be injections 
averaging approximately 9.0 Bcf per day for July, largely owing to higher 
rates early in the month, and 7.0 Bcf per day for August (see Table 2).

These rates would keep the year-over-year inventory deficit above 350 Bcf for 
July and August, with inventories on a path to reach between 2.7 and 2.8 
trillion cubic feet (Tcf) by the end of October, still an all-time low level 
for the beginning of winter. Reaching even this level would require at least 
two of the following to occur: a continuation of quite mild weather, little 
or no hurricane activity in the Gulf of Mexico, or warm weather through 
October. As a result, the pressure is likely to remain high in the gas market 
at least through August.

Regional Markets--The Topock Premium
Buoyed by strong regional power demand and high utilization rates on 
pipelines into California, Topock continues to be the highest pricing point 
in North America. High power loads in the West are supporting other prices in 
the region, but supply growth and pipeline capacity constraints out of the 
Rockies and high pipeline utilization rates between the San Juan Basin and 
California have maintained extremely wide differentials between those markets 
and California. California should remain strong, and CERA expects some modest 
strengthening in Rockies and San Juan basis differentials during July and 
August with increasing Pacific Northwest gas demand for power generation (see 
Table 3).

CERA's outlook by region follows:

* Rockies. Continued strong supply growth in the Rockies is challenging 
pipeline capacity out of the region, and differentials have come increasingly 
under pressure this summer. CERA expects some modest recovery in Rockies 
differentials as hydroelectric generation on the Pacific Northwest declines. 
Differentials should average $0.55 per MMBtu for August.

* San Juan. CERA expects continued strong power loads in the West to keep San 
Juan prices near current differential levels. August differentials should 
average $0.35 per MMBtu for August.

* Permian and Mid-Continent. Hotter weather and higher power loads in Texas 
have already strengthened differentials at the Permian Basin, and that 
tightening should hold through August. The Mid-Continent should continue to 
price at a discount to Permian supplies.

* Chicago. Chicago prices have held just above $0.05 above the Henry Hub for 
much of July, a condition CERA does not expect to change significantly during 
August. Chicago should average $0.06 above the Henry Hub.

* Northeast markets. Mild weather in the Northeast quickly cooled price 
premiums from the mid-$0.40s to the mid-$0.20s from early to mid-July. With 
hot weather still likely to return, however, New York prices for August 
should average $0.32 above the Henry Hub.

Canadian Markets--Western Supply No Longer in Decline?
Although TransCanada flows are down, the strong market overall and wide 
differentials have resulted in increased flows on PGT (up 300 million cubic 
feet [MMcf] per day year-over-year). Domestic demand is still down slightly 
from last year's levels. Storage injections have picked up (in both the East 
and West) and, although behind last year's, are still above the five-year 
average. Western Canadian supply increased slightly on a year-over-year basis 
in June; July thus far is basically running flat with last year.

The impact of the 1999 TransCanada capacity turnback and the current rate 
structure is beginning to be felt in the Canadian market. It is more and more 
apparent that TransCanada is becoming the swing pipeline, with flows 400 MMcf 
per day below last year's levels. The effect of the difference between 
contracted capacity (available to shippers at incremental cost) and 
uncontracted capacity (available only on a full-cost basis) is becoming 
evident. With supply filling contracted capacity on export pipes, the 
inability of TransCanada to discount below the minimum interruptible rate may 
be creating a two-tiered market. This shift results in a different netback 
for holders of capacity (similar to the higher netback achieved by the 
aggregators in the past) and those without capacity (those required to 
acquire full cost transportation, or to sell at AECO). This lack of 
flexibility is contributing to the wider differential between Henry Hub and 
AECO (currently averaging in the high U!
S$0.70s). AECO is expected to average C$4.91 per gigajoule (US$3.52 per 
MMBtu) for August.


**end**

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