Monthly Briefing: A Shoulder Month Without Shoulder Prices - CERA ,
 September Forecast
---------------------- Forwarded by Lorna Brennan/ET&S/Enron on 08/23/2000 
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webmaster@cera.com on 08/22/2000 10:28:10 PM
To: Lorna.Brennan@enron.com
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Subject: Monthly Briefing: A Shoulder Month Without Shoulder Prices - CERA 
Alert




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CERA Alert: Sent Tue, August 22, 2000
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Title: Monthly Briefing: A Shoulder Month Without Shoulder Prices
Author: Zenker, Snyder, Moritzburke
E-Mail Category: Alert
Product Line: Western Energy ,
URL: http://www.cera.com/cfm/track/eprofile.cfm?u=5526&m=1320 ,

Alternate URL: 
http://www.cera.com/client/ce/alt/082200_18/ce_alt_082200_18_ab.html
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As western markets continue to struggle through high August demand and prices 
for both power and natural gas, September looms as the start of the fall 
shoulder season. The shoulder season historically has brought the possibility 
of a break in weather and a demand drop in both power and gas prices from 
summer levels. CERA expects this shoulder season to differ from years past, 
however, with power and gas markets producing strong year-over-year prices 
and little relief from summer levels, even with normal September weather.

West-wide power loads will decline but will remain similar to those in June, 
a month with high power prices. In addition, compared with June levels 
hydroelectric capacity has dropped owing to reduced stream flows, leaving 
more expensive gas-fired generation to replace declining hydroelectric 
output. CERA expects occasional hot weather and higher gas prices to push 
on-peak prices in the West to 244 percent over September 1999 levels.

Continued strong use of gas-fired generation in the West, as well as low US 
storage inventories and tight supply demand balances, will keep the pressure 
on gas prices. Topock prices are expected to average $4.45 per million 
British thermal units (MMBtu) in September.

These high September gas and power prices are driven by

* Declining hydroelectric output. The months of September through November 
represent the low point for hydroelectric output in the West, with rainfall 
historically boosting output in December. Approximately 16,400 average 
megawatts (aMW) will be available from hydroelectric facilities during the 
three-month period. This represents a net reduction in capacity of 6,900 aMW 
when compared with the recent June-August summer months and a reduction of 
3,600 aMW when compared with September 1999 levels.

* Higher, more variable power demand. The Southwest and Southern California 
still experience hot weather in September, and regional utilities typically 
consider it possible that a year's peak load event will occur in September. 
Spiking loads, however, can quickly retreat with a return to cooler weather. 
Thus, power loads and power prices are expected to experience a high degree 
of variability during September.

* High levels of gas-fired generation. Load growth and a declining 
hydroelectric resource base will require gas-fired resources to serve 
approximately the same level of demand as in June 2000, a month with similar 
average demand and monthly average on-peak power prices in the $150-$178 per 
megawatt-hour (MWh) range, depending on the region. This strong pull on 
gas-fired plants will push deep into the generation resource base, driving 
prices upward. An additional 1.7 billion cubic feet (Bcf) per day will be 
required for gas-fired generators in the US West compared with September 1999 
levels.

* Strong North American gas prices. Natural gas prices are expected to retain 
most of this summer's peak levels, as North American supplies remain tight. A 
market anxious about winter demand and price levels will also limit a price 
retreat this fall. As a result, average September Henry Hub prices are 
expected to trade around $3.95 per MMBtu. An active storm season could keep 
Henry Hub prices near the $4.50 mark.

* Strong western basis differentials. The strong demand for gas to serve 
gas-fired generation and storage concurrently will maintain western basis 
differentials at high levels, especially in the California markets. CERA 
expects a Topock-to-Henry Hub differential of $0.40 per MMBtu during 
September. Extended operational problems associated with El Paso's pipeline 
rupture would raise that outlook.

Regional Power Market Drivers
Hotter-than-normal August weather, transmission and generator outages, high 
natural gas prices, and declining hydroelectric output all contributed to a 
rise in power price levels during August. Southern California average power 
prices in August have thus far exceeded July levels by an average of $90 per 
MWh during the on-peak period and by $14 per MWh during the off-peak period. 
Mid-Columbia power prices, bearing the brunt of fire-induced transmission 
outages, experienced a jump from July price levels of $114 per MWh for the 
on-peak period and $20 per MWh in the off-peak period.

Off-peak prices, which have averaged above $60 per MWh during the June-August 
period, are clearly defined by the production cost of gas-fired resources. 
On-peak prices during this same period, at over $100 per MWh in all regions 
in all months, have reflected a significant premium at times over the cost of 
the marginal system generator (see Table 1).

A return to normal weather should drive West-wide loads down by 8,300 aMW in 
September from August levels. However, load growth and a return to normal 
weather are expected to push loads up by 5,400 aMW when compared with 
September 1999 levels. These greater loads, coupled with a reduction in 
hydroelectric generation of 3,600 aMW from last September's levels, will 
create supply tightness during September (see Tables 2 and 3).

Hydroelectric, coal, and nuclear generation together will be insufficient to 
serve West-wide demand in September, even during much of the off-peak 
periods, requiring gas-fired resources to meet a significant portion of the 
load. Gas demand for power generation is expected to average 5.2 Bcf per day 
in September, down from over 5.9 Bcf per day in August but up by a dramatic 
1.7 Bcf per day compared with levels in September 1999.

September power prices will be defined by a floor set by the incremental cost 
of gas-fired generation, approximately $50 per MWh, with prices frequently 
higher as demand increases. As this summer has clearly demonstrated, prices 
rise in a nonlinear fashion as supplies grow very tight. Hot weather-induced 
loads should provide additional examples of this relationship. * Cooler- or 
hotter-than-normal weather in September, coupled with the inherent high 
variability of September loads, will produce a wide range of price outcomes. 
Under normal weather, on-peak power prices are expected to fall in the 
$113-$123 per MWh range, depending on location, representing a 244 percent 
premium to year-ago September prices (see Figure 1).

The latest revision of the California Independent System Operator's (ISO's) 
imbalance energy market cap down to $250 per MWh is expected to depress 
market prices during any weather events in September. CERA expects the ISO 
price cap to limit prices outside of California as well.

Pacific Northwest
Although demand levels in the Pacific Northwest are expected to retreat in 
September by at least 1,100 aMW compared with those in the hotter-than-normal 
month of August, the loss in available capacity from hydroelectric resources 
will amount to 1,900 aMW over the same period (see Table 4). Thus, the 
Pacific Northwest will be in an even more limited position to export power to 
other regions. With transmission interties operating at below rated capacity 
during this period, power prices in the Pacific Northwest will maintain their 
tight relationship with those in Northern California. These price levels will 
continue to support the operation of the region's limited quantity of 
gas-fired generation. Mid-Columbia on-peak price levels are expected to 
average $118 per MWh in September.

Off-peak power price levels in the Pacific Northwest will also receive a 
boost from the strong markets to the south. The expected September level of 
$54 per MWh represents the opportunity cost of power sales in surrounding 
markets.

California
The fall months initiate a seasonal shift in price differentials that 
separates the West into markets that lie north of transmission Path 15 and 
those to the south. As in years past, hydro-depleted Northern California 
should experience demand levels that must be served by generation resources 
within the region. Exports from the Pacific Northwest dwindle, and energy 
from the nuclear and coal-rich Southwest is constrained from entering 
Northern California by Path 15 import limitations. This condition, which is 
expected to persist from September through November, allows Northern 
California to price at a premium. The expected monthly average on-peak 
Northern California price of $123 per MWh incorporates this dynamic. Notably, 
the California ISO is completing a process to remap the zones in California, 
in part to capture locational price differences more effectively.

Southern California, like the Southwest, will typically experience hot 
weather episodes in September. During these high demand periods, prices will 
rise to peak levels as experienced this summer. In addition, California as a 
whole should see average loads in September that are 4,600 aMW higher than 
those of September 1999. Occasional cooler weather will sharply but 
temporarily reduce daily prices. Southern California benefits from the 
abundant export capacity of the Southwest during cooler weather in that 
region, allowing prices to fall well below those in Northern California. An 
$8 per MWh differential between the north and south portions of the state is 
expected, with Southern California on-peak prices averaging $115 per MWh.

Off-peak prices of $53 and $47 per MWh for Northern and Southern California, 
respectively, reflect the continued need for gas-fired resources to support 
September off-peak loads.

Rockies and Southwest
An extended period of hot weather in July and August has boosted demand in 
the Rockies, a region with growing saturation of residential air 
conditioning. Limited transmission capacity and a dearth of cheaper exports 
from surrounding regions have allowed the Rockies to price temporarily at a 
premium to all other regions in the West.

A return to normal weather in September should restore the previously tight 
relationship of Rockies prices to those in the North. Rockies prices are 
expected to fall with loads, with a September monthly on-peak price average 
of $113 per MWh and an off-peak price average of $43 per MWh.

CERA expects Southwest prices to be tightly connected to prices in Southern 
California on a monthly average basis. The two regions generally experience 
the same September weather patterns, and a strong 7,600 MW transmission link 
between the two market centers allows them to balance loads with each other. 
Strong gas prices and occasional market tightness-induced price run-ups will 
maintain on-peak prices at the $115 per MWh level in September. Off-peak 
prices will, like those in Southern California, be buoyed by the high cost of 
gas-fired generation. A price level of $47 per MWh is expected for off-peak 
prices.

Regional Gas Market Drivers
The summer competition for gas supply between power and storage continues in 
North America, with gas prices reflecting the intensity of that competition. 
Even as the summer power peak subsides in September across the United States, 
the need to continue strong storage injections and the threat of storms in 
the Gulf will keep prices high and volatile. The storage deficit now stands 
at approximately 350 Bcf, and US storage inventories look likely to head into 
winter at historically low levels. This critical storage situation will keep 
prices high despite overall declines in power loads in September. CERA 
expects a Henry Hub price of $3.95 per MMBtu during September.

In the West strong power loads and the potential for power peaks persist 
through September, especially in California. Overall, total demand for gas is 
expected to decline across the West from 10.1 Bcf per day during August to 
9.8 Bcf per day during September (see Table 5). This load will tend to keep 
intraregional differentials wide throughout the West during the month. The 
recent price disconnects between the supply-rich Rocky Mountains and San Juan 
Basin and demand-charged California will persist. October should bring some 
change in this dynamic as heating loads in the Rockies begin to increase.

In general, winter will bring a dramatic shift in regional pricing 
differentials throughout the West. The summer pressure on Rocky Mountain 
supplies caused by high utilization rates on most export pipelines will be 
relieved somewhat by regional heating loads. Declines in flows into the San 
Juan Basin from the Rockies will take some downward pressure off prices in 
the San Juan. On the other hand, healthy California storage inventories 
should limit price premiums at Topock through the heating season. The 
start-up of the new Alliance pipeline, which will draw gas to the Midwest, 
will support prices in the Pacific Northwest and California.

California
Topock continues to be the premium pricing point in North America, although 
differentials between Southern California and the Henry Hub subsided somewhat 
from peak levels near $1.00 per MMBtu before this weekend's pipeline 
explosion. Total imports into California reached record levels during July; 
total imports of 5.8 Bcf per day eclipsed the previous high by 300 million 
cubic feet (MMcf) per day (see Table 6). Pipeline capacity into the state 
during the month ran at 83 percent utilization. So far in August, pipeline 
capacity utilization is exceeding even that high rate, running at 85 percent. 
These high rates of capacity utilization are putting pressure on gas prices 
in Southern California, and the pressure should continue during September.

Total demand in California is expected to decline somewhat during September, 
but continued strong power loads and low seasonal hydroelectric generation 
will provide support. Total demand in the state should average 6.6 Bcf per 
day, down only slightly from August's total of 6.8 Bcf per day. Flows into 
the state between August and September are not likely to change 
significantly, but price pressure should decline somewhat with demand. The 
Topock differential to the Henry Hub should average approximately $0.50 per 
MMBtu for September (see Table 7).
Storage inventories in the West are still healthy relative to levels in the 
rest of the United States, but the storage surplus in the region has eroded. 
In California, inventories are running lower than last year, and the deficit 
in the state looks likely to widen during September. The end of injection 
season storage inventories will determine the vulnerability of Topock 
differentials to winter price spikes.

Pacific Northwest
Malin prices this summer have shown neither the strong premiums that Topock 
prices have shown nor the wide discounts that supplies in the Rocky Mountains 
and San Juan Basins have shown. So far this month, prices at Malin are 
averaging a $0.25 per MMBtu discount to the Henry Hub. Pipeline capacity into 
the region from the Rocky Mountains is running nearly full; flows on PGT out 
of Alberta have averaged nearly 2.2 Bcf per day this month. Export capacity 
out of the region on PGE GT NW is running close to capacity, and pipeline 
constraints to the south combined with strong California demand are driving 
the wide Malin-to-Topock differentials.

Continuing strong demand in the South will likely keep Topock prices strong, 
and the wide north-south differentials within the West will likely hold 
through September. In the Pacific Northwest demand is expected to climb 
through September to 1.5 Bcf per day from 1.4 Bcf per day in August. This 
demand level should keep Malin differentials from widening from current 
levels. For September CERA expects Malin prices to average $0.10 per MMBtu 
below the Henry Hub price.

Southwest
Prices in the San Juan Basin this summer have been left behind by rising 
California demand. Although the westward pull on supplies is strong, 
bottlenecks between California and the San Juan have led to disconnects 
between San Juan prices and Topock prices. Pipeline capacity utilization 
rates on Transwestern and the northern leg of El Paso reached 93 percent 
during July, with less than 200 MMcf per day of excess pipeline capacity. 
Increased flows from the Rockies on TransColorado and Northwest are 
contributing to downward pressure on San Juan Basin supply, and in general, 
the San Juan has followed Rocky Mountain prices rather than following prices 
at Topock or the Permian Basin.

Unlike in the past two summers, the bottleneck has not allowed power demand 
on the West Coast to support San Juan prices relative to Permian prices. The 
differential between San Juan and Permian has averaged $0.50 per MMBtu so far 
this month and $0.30 per MMBtu since June. Additional imports from the 
Rockies into the San Juan have increased supply by 200 MMcf per day relative 
to last summer, but these higher flows do not fully explain the disconnect. 
Without much change in Southwestern or Rocky Mountains local demand, the San 
Juan should continue to price at a wide discount during September. The San 
Juan-to-Henry Hub differential is expected to average $0.60 per MMBtu. As in 
the Rockies, differentials should narrow substantially in October.

Rocky Mountains
Downward pressures on Rocky Mountain prices intensified over the past month 
as utilization rates on pipelines out of the region continued to climb. 
Record heat and power generation levels have done little to boost gas demand 
within the region; generation is still largely coal-based, and the demand 
impact on gas of the additional load is minimal. CERA expects the heavy 
discount-current Rocky Mountain-to-Henry Hub differentials are around $0.90 
per MMBtu-to persist through September. Local area demand is not expected to 
change during September. Substantial gain in local demand comes in October 
with heating loads; October demand should average 1.4 Bcf per day, up from 
August and September averages of around 1.2 Bcf per day.

Although the winter heating season will relieve pipeline pressures in the 
Rockies, winter differentials are expected to stay in the $0.25 to $0.40 per 
MMBtu range. Strong storage inventories will limit the connection with 
broader North American markets this summer. Next summer, pressures on Rockies 
supplies will likely intensify relative to this summer. Although pipeline 
expansion projects have been announced-Trailblazer and Williams announced 
expansion plans this summer-the new capacity will not be online to relieve 
constraints next summer. CERA expects supplies within the Rocky Mountains to 
increase by 300 MMcf per day next year.

Western Canada
After widening to over US$1.50 per MMBtu, the AECO-Henry differential has 
begun to narrow somewhat; maintenance that has restricted flows has largely 
been responsible for the jump from $0.84 per MMBtu in July. With current 
supply able to fill the contracted pipe capacity and incremental volumes 
having to pay full cost to flow, differentials are likely to persist in the 
mid-US$0.70s per MMBtu for September. AECO is expected to be US$3.25 per 
MMBtu (C$4.53 per gigajoule) for September. Even with the start-up of the 
Alliance project, the contract nonrenewal on TransCanada is likely to 
continue the two-tiered pricing dynamics of contracted versus uncontracted 
pipeline costs. This will result in differentials that will range between 
US$0.60 and US$0.75 per MMBtu throughout the winter.

Supply build in western Canada continues to languish behind last year's 
levels. The pace of drilling (over 9,000 gas wells are expected this year) 
should provide growth in the fourth quarter and into 2001. Supply is expected 
to be flat with 1999 on an annual basis for this year and up at least 350 
MMcf per day in 2001.

Sumas prices have been quite volatile, driven by both weather in the Pacific 
Northwest and maintenance on the Westcoast system. For September, Sumas is 
expected to be slightly more stable and to price at a modest premium to AECO 
of US$0.05 per MMBtu.

**end**

Follow URL for PDF version of this Monthly Briefing with associated graphic 
and tables.


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