---------------------- Forwarded by Lorna Brennan/ET&S/Enron on 06/26/2000 
02:53 PM ---------------------------


webmaster@cera.com on 06/23/2000 10:27:33 PM
To: Lorna.Brennan@enron.com
cc:  

Subject: New Peaks, New Prices - CERA Alert




**********************************************************************
CERA Alert: Sent Fri, June 23, 2000
**********************************************************************

Title: New Peaks, New Prices
Author: Zenker, Moritzburke, Snyder
E-Mail Category: Alert
Product Line: Western Energy ,
URL: http://www.cera.com/cfm/track/eprofile.cfm?u=5526&m=1247 ,

In the West, July typically marks the start of the summer cooling season, 
which, along with waning hydroelectric energy production and the more 
frequent use of gas-fired generators to meet demand, causes steadily rising 
power prices. CERA expects the West to be the only region in North America 
with a year-over-year increase in peak electricity demand. Power prices 
already established new record highs in June, suggesting that as demand 
reaches its peak during the coming summer months western power markets will 
continue to experience increased volatility compared with last year's levels. 
The convergence of natural gas prices that are much higher than last year's 
levels, growing demand for power, and reduced hydroelectric energy production 
when compared with levels in 1999 is pushing up western power prices. 
Merchant and other gas-fired generators will be pressed into service, 
experiencing their strongest utilization rates since the drought year of 1994.

Greater utilization of gas-fired generators within the West has supported 
western differentials and contributed to high gas prices throughout North 
America. Western gas prices should continue to be strong, boosted by 
continuing increases in regional gas demand for power generation and pressure 
across North America to inject gas into storage in anticipation of summer 
power loads.

The main drivers of higher power and gas prices when compared with 
year-earlier levels will be

*  Peak WSCC load season. Summer weather will drive loads to the year's 
coincident peak, which is most likely to occur during the July/August period 
but could arrive any time during the June through October air-conditioning 
season. CERA expects demand growth of 3.1 percent in the third quarter 
compared with levels in 1999, which will push Western Systems Coordinating 
Council (WSCC) coincident peak demand levels to 2.7 percent over 1999 levels.

*  Waning hydroelectric output. Hydroelectric production is on its normal 
downward seasonal slide. This resource decline is more visible when compared 
with the 1999 hydro season, which was both abundant and prolonged.

*  High utilization rates for gas-fired generators. Growing demand for 
electricity, coupled with a declining availability of hydroelectric energy, 
will drive utilization rates of gas-fired power plants to their highest 
levels since the drought year of 1994.

*  Higher fuel prices. Western gas prices have remained at $1.00-$1.50 per 
MMBtu above 1999 levels. Growing year-over-year gas demand for power 
generation is providing much of the price pressure in western markets. These 
higher gas prices provide a boost to both on-peak and off-peak power prices 
of between $10 and $15 per megawatt-hour (MWh).

Regional Power Market Drivers

Power markets in the West are poised to break records for demand, peak load, 
and gas-fired plant utilization and, as a result, power prices.

A return to normal summer weather coupled with growing demand for power will 
push demand for electricity up by 5,274 gigawatt-hours (GWh) in the US West 
for the third quarter compared with 1999 levels, or almost 2,400 megawatts 
(MW) on average (see Table 1). This growth in the demand for electricity will 
also drive peak loads to new highs. CERA expects the 1999 WSCC coincident 
peak to be exceeded by 2.7 percent, climbing to nearly 119,000 MW. As was 
demonstrated by the mild summer of 1999, deviations from normal weather could 
boost or thwart this peak demand growth figure.

Two key factors will significantly reduce third quarter hydroelectric 
production levels compared with 1999 levels.

*  First, CERA expects West-wide total season hydroelectric production in 
2000 of roughly 100 percent of historical average levels, substantially lower 
than the approximately 120 percent of average in 1999.

*  Second, runoff was prolonged in 1999, serving to push a substantial 
portion of the hydroelectric production into the summer period (see Figure 
1). On average, CERA expects these factors will remove 9,187 GWh, or almost 
4,200 average megawatts (aMW), from the western resource base compared with 
1999 levels. Exacerbating this decline, refilling of reservoirs and flow 
restrictions to assist fish migration will cause periodic but significant 
curtailments in power production at key Pacific Northwest hydroelectric 
facilities.

Natural gas-fired facilities will be called upon to supply most of the 
expected increase in demand, while also replacing hydroelectric resources as 
they continue to decline. This will push average annual utilization rates of 
gas-fired combined cycle, steam, and cogeneration plants to approximately 38 
percent in 2000--levels not experienced since the 41 percent annual average 
utilization rate in 1994, a year marked by drought and warmer-than-normal 
summer weather. Utilization rates for these facilities will also surge past 
1999 levels, especially this summer. CERA anticipates a West-wide third 
quarter utilization rate of 59 percent for these facilities under normal 
summer weather conditions, compared with 46 percent for the same period of 
1999.

This level of utilization will certainly establish gas-fired generation as 
the floor to power prices during the third quarter, during not only the 
on-peak demand period but the off-peak as well. With natural gas prices at 
$1.00-$1.50 per MMBtu higher than 1999 levels, power prices are boosted by 
$10-$15 per MWh owing to fuel price increases alone. With supply tightness 
already evident in western power markets, the stage is set for increased 
price volatility compared with 1999 levels as episodes of hot weather require 
increased utilization of less-efficient generators throughout this summer.

Pacific Northwest

The water supply forecast for the Columbia River remains near average but has 
dropped a couple percentage points from last month. Flows are expected to 
remain at roughly 96 percent of average through September on the Lower 
Columbia and 103 percent of average on the Upper Columbia. Conditions overall 
are still sufficient to be considered average. This return to normal 
conditions in the Pacific Northwest should produce hydroelectric output 
nearly 2,700 GWh (18 percent) lower than last year for July and 8,405 GWh 
lower for the third quarter as a whole (see Table 2).

The region's load growth coupled with lower hydro supply will continue to 
elevate power prices in the Pacific Northwest relative to 1999 levels. 
Tighter supply conditions in California and the Southwest will attract energy 
exports from the Pacific Northwest, preserving a differential between the 
Pacific Northwest and California of about $1 per MWh on average.

Price differentials between the Pacific Northwest and California have varied 
dramatically recently, with the north at times rising above those to the 
south owing to local demand and hydroelectric constraints caused by reservoir 
filling operations. Since the end of May, volatility in both markets has 
pushed the difference between daily on-peak prices at COB and those in 
California from a premium of $120 per MWh to a discount of $55 per MWh within 
a few days. CERA expects that over the long run, California markets will 
clear at a premium as the summer progresses, but the differential will vary 
widely, with episodes of Pacific Northwest power pricing at a premium to 
those in California.

California

Despite below-average precipitation and snowpack this year, California 
reservoir storage levels throughout the state are higher than normal, ranging 
between 108 and 166 percent of average for the state's primary runoff 
regions. Under these conditions hydroelectric output should be roughly 4 
percent (363 GWh) below last year's levels for the third quarter (see Table 
2). With a return to normal weather conditions relative to third quarter 
1999, cooling demand this summer will increase most in California, where 
weather was nearly 30 percent cooler than average last year.

Recent day-ahead power prices in California have drawn attention to the West 
as the highest-cost market (if only temporarily) in North America. Record 
high temperatures and unscheduled unit outages produced new day-ahead price 
records, with power prices on June 15 at $457 per MWh in the day-ahead 
on-peak market and real-time hourly prices at the market cap of $750 per MWh. 
Increased utilization of gas-fired generation and daily gas prices of around 
$5 per MMBtu (burner-tip in Southern California) have kept daily average 
off-peak prices between $40 and $80 per MWh. Notably, these higher price have 
occurred during periods when roughly 1,800 MW more coal-fire generation was 
available in the West compared with the same period in 1999. CERA expects 
prices to continue to respond to the tight capacity environment this summer.

Rockies and Southwest

During summer 1999, the Rockies/Southwest was the only region to experience 
above-average cooling demand, suggesting that normal weather should bring 
only moderate demand growth of less than 1 percent (see Table 3). However, 
growing energy demand in neighboring regions and a large transmission 
transfer capability will pull energy from the Rockies/Southwest region when 
excess capacity is available, ensuring that prices in the region will remain 
tightly connected to price levels in other parts of the West.

Palo Verde prices have generally kept pace with other western markets, while 
maintaining their characteristic premium to the California Power Exchange 
during spring and early summer. CERA expects Southwest prices to strengthen 
relative to California when summer weather periodically shifts the locus of 
demand to the Southwest. However, California prices will maintain a premium 
on average to those in the Southwest, as the effects of the state's tight 
supply situation translates to higher prices than those in either the 
Southwest or Pacific Northwest.

Regional Gas Market Drivers

Under continuing pressure to inject gas into storage in the face of declining 
supply and increasing gas demand for power generation, gas prices at the 
Henry Hub are expected to average $4.45 per MMBtu in July. The strong demand 
for gas for power generation will keep differentials strong in the southern 
half of the West. In the Rockies, pipeline constraints will keep 
differentials wide.

The heightened call on gas demand for power generation, driven by the 
declining hydroelectric generation and increasing power loads, is expected to 
drive demand increases of 1.6 Bcf per day relative to July 1999 and 660 MMcf 
per day relative to June 2000 demand levels. Gas demand for power generation 
is expected to reach a monthly average record level of 4.9 Bcf per day in 
July (see Tables 4 and 5). These increases will result in declines in western 
storage injection rates and in exports from the West. Both Permian and San 
Juan supplies will be pulled increasingly toward the West Coast during July.

Low storage inventories and needed increases in injections are driving North 
American gas pricing. The West is the one US region actually running a 
storage surplus, but the recent heat waves and associated pull on gas 
supplies have eroded that surplus, particularly in California (see Table 6). 
Given the expected increases in gas demand, the western surplus should 
continue its decline. This decline and very high demand will reinforce the 
volatility in differentials already evident this summer.

California

Because of the early hot weather in the West and strong gas demand for power 
generation, Topock prices have been extremely high and volatile. So far this 
month, Topock has averaged over $0.30 per MMBtu above the Henry Hub. Flows on 
El Paso and Transwestern into California increased by over 300 million cubic 
feet (MMcf) per day during June relative to May averages, and flows are 
expected to continue to climb by an additional 400 MMcf per day during July. 
PGT continues to run near capacity (see Table 7). At the same time, the 
storage levels within California look likely to fall below last year's levels 
sometime during the month.

This intense demand pressure--California demand should increase by nearly 500 
MMcf per day in July relative to June--will keep utilization rates on import 
pipelines high and sustain Topock differentials. CERA expects the Topock to 
Henry Hub differential to average $0.30 per MMBtu during July (see Table 8). 
This high differential will likely persist through the summer, with 
differentials rising above $0.50 per MMBtu during West Coast heat waves.

Southwest

San Juan price differentials have been volatile, narrowing during periods of 
very high western demand. However, a very high utilization rate on pipeline 
capacity into California has widened the Topock-San Juan differential, and 
that wide gap is expected to persist. On average, San Juan differentials to 
the Henry Hub are expected to narrow from current levels as southwestern 
demand increases with western temperatures. Demand in the Southwest is 
expected to climb from 1.4 Bcf per day in June to 1.5 Bcf per day in July. 
This increased call on regional supplies and an expected strengthening in 
Permian prices should result in an average San Juan differential to the Henry 
Hub of $0.18 per MMBtu.

In the Permian Basin, prices are expected to strengthen as Texas power demand 
climbs. Combined with the pull on supplies from the West, Permian 
differentials should narrow from their current levels of $0.20 per MMBtu to 
below $0.10 per MMBtu.

Pacific Northwest

Strong June hydroelectric output has limited the call on gas supplies in the 
Pacific Northwest so far this summer, but as hydroelectric output decreases 
in June and July, gas demand will increase dramatically. CERA expects an 
increase of nearly 200 MMcf per day during July relative to June levels. The 
limited demand so far has meant differentials between Malin and the Henry Hub 
of as much as $0.30 per MMBtu and Topock to Malin differentials of over $0.60 
per MMBtu. The Malin to Henry Hub differential has narrowed slightly to 
around $0.20 per MMBtu. It should continue to strengthen with growth in 
regional demand and average $0.00 per MMBtu during July.

Rocky Mountains

Regional gas supply within the Rocky Mountains continues to increase, 
bolstered by continuing growth in the Powder River Basin. This April, exports 
out of the Rockies reached 3.2 Bcf per day, a record high. Although there is 
excess pipeline capacity out of the region into the Southwest on the 
Transcolorado and Northwest pipelines, high utilization rates have widened 
Rockies differentials with the rest of the West. In particular, Rockies to 
San Juan differentials have averaged nearly $0.25 per MMBtu for June after 
pricing close to parity earlier in the year. That gap should persist through 
the summer, as gas-fired generation climbs across the rest of the West. 
Demand is expected to average the same level in July as in June in the Rocky 
Mountains, where coal limits gas's gains in power generation.

CERA expects prices within the Rockies to gather some support from increasing 
power loads in the Pacific Northwest, as well as from stronger differentials 
in the San Juan Basin. On average, Rockies differentials to the Henry Hub are 
expected to average $0.52 per MMBtu during July.

In response to the increasing supplies flowing out of the Powder River Basin 
and the increasing pipeline capacity utilization on export pipelines, 
Trailblazer has announced an open season for two possible options to extend 
and expand the 500 mile pipeline from Wyoming into Nebraska. Although timing 
and volumes have yet to be announced, the additional capacity could prevent 
serious bottlenecks from developing out of the region, which CERA would 
expect by 2002 without capacity additions.


**end**


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

Please note: Should the above URL not work, please use the following:
http://www.cera.com/client/ce/alt/062300_17/ce_alt_062300_17_ab.html





**********************************************************************
Account Changes
To edit your personal account information, including your e-mail
address, etc. go to: http://eprofile.cera.com/cfm/edit/account.cfm

This electronic message and attachments, if any, contain information
from Cambridge Energy Research Associates, Inc. (CERA) which is
confidential and may be privileged. Unauthorized disclosure, copying,
distribution or use of the contents of this message or any attachments,
in whole or in part, is strictly prohibited.

Terms of Use: http://www.cera.com/tos.html
Questions/Comments: webmaster@cera.com
Copyright 2000. Cambridge Energy Research Associates