---------------------- Forwarded by Lorna Brennan/ET&S/Enron on 07/27/2000 
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webmaster@cera.com on 07/26/2000 10:57:49 PM
To: Lorna.Brennan@enron.com
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Subject: The West: Keeping Its Fingers Crossed - CERA Alert




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CERA Alert: Sent Wed, July 26, 2000
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Title: The West: Keeping Its Fingers Crossed
Author: Zenker, Moritzburke, Snyder
E-Mail Category: Alert
Product Line: Western Energy ,
URL: http://www.cera.com/cfm/track/eprofile.cfm?u=5526&m=1286 ,

A strong dose of summer weather in June propelled West-wide demand levels up 
by nearly 12 percent over the same period in 1999. These higher demand levels 
provided the year's first example of the power price spikes that can be 
produced when the West's tight capacity intersects with normal summer load 
levels, lower-than-normal hydroelectric levels, strong gas prices, and 
California's immature wholesale power market structure. As power markets 
reacted in June with unprecedented price strength throughout the region, 
regulators and the California Independent System Operator (ISO) intervened to 
dampen markets from a maximum of $750 per megawatt-hour (MWh) to $500 per 
MWh.* Although some market participants have filed protests at the Federal 
Energy Regulatory Commission to raise or eliminate the caps, utilities, 
legislators, and consumer advocates are moving to protect consumers or 
completely redesign what they perceive as a flawed market.

As western markets move through the critical July-August peak electricity 
demand period, market participants and regulators alike are wondering if 
power supplies will be sufficient and if price levels will rival those in 
June. CERA expects that western supplies will be adequate under normal summer 
weather conditions, barring abnormal unit and transmission line outages. 
However, normal August weather conditions will push demand levels 
significantly higher than in June, creating an even tighter supply-demand 
balance, straining the ability of the transmission system to supply key 
demand regions adequately. A hot weather event could exhaust both in-state 
and imported supplies for California.

The tight supply and demand situation will almost certainly prompt a strong 
price response, similar to that in June. This will fuel the unease of 
regulators in states that have restructured their markets and in those that 
are considering restructuring. Even as regulators' continued support of 
restructured power markets begins to waver, a weather event that forces 
regional blackouts would force regulators to intervene.

CERA's outlook for August power markets is driven by
* High peak loads. Under normal weather conditions, West-wide August loads 
will be on average 1,400 megawatts (MW) higher than last August. The peak 
load in California is expected to push capacity margins to 6 percent, even 
after curtailing interruptible load.

* Lower hydroelectric output. As the West enters its peak load period, 
hydroelectric production is expected to decline systemwide by roughly 3,900 
average megawatts (aMW) from July to August. Compared with the high, 
sustained output of last August, hydroelectric output this August, although 
roughly average on a historical basis, will be roughly 4,900 aMW (20 percent) 
lower.

* High levels of gas-fired generation. Compared with August 1999, higher 
utilization rates, along with gas prices that have climbed $1.88 per million 
British thermal units (MMBtu), will increase the incremental cost of energy 
production by over $20 per MWh. Although CERA expects power prices in August 
to diverge from production costs owing to the expected supply tightness, 
higher production costs will create a higher floor for energy prices in all 
periods of the day.

The extremely tight power supply-demand balance within the West, and within 
California specifically, has resulted in unprecedented high summer gas demand 
for power generation. This high demand level-combined with seasonal storage 
injection needs in California-has pushed up utilization rates on pipelines 
into California and pushed Topock differentials over $0.75 per MMBtu to the 
Henry Hub. Strong demand should continue through August in the West and 
support premium pricing at Topock.

The Rocky Mountains represent the opposite extreme to the high premium placed 
on Topock deliveries. In the Rockies supply is building relative to export 
pipeline capacity, and market access is becoming a challenge. Weak seasonal 
demand compounds the problem; the strong western demand for gas for power 
generation does not extend to the Rockies. Generation within the region 
remains nearly all coal-fired. These regional pressures should remain a 
feature of western gas markets through September.

Moderate summer weather and reassuring injection rates nationwide during 
recent weeks have allowed some easing in prices at the Henry Hub. However, 
summer is not yet over and absolute storage inventories are still at critical 
levels. Higher gas prices are likely to resurface.

Regional Power Market Drivers
August demand under normal weather is expected to rise by an additional 7 
percent, or nearly 5,500 aMW, over average June levels (see Table 1). Peak 
demand levels should exceed those in June as well, with a coincident peak 
over the whole Western Systems Coordinating Council (WSCC) of 118,600 MW 
expected under normal weather conditions in 2000, a 2.7 percent increase over 
the weather-muted 1999 peak. California alone should experience peak loads 
that are approximately 3,600 MW higher than peak levels in June.

Available generation capacity in the West has been at normal levels for this 
time of year, although coal-fired plants are responding to a record 
production year with repeated but short-lived outages. The steady decline in 
hydroelectric generation will remove 3,900 aMW from the West resource base 
when compared with July levels and about 6,800 aMW since June, although 
reservoir refilling operations temporarily removed significant quantities of 
hydroelectric generation during portions of June. Given hydro operators' 
economic interest in maximizing on-peak production at the expense of off-peak 
production, the loss of capacity during the on-peak period will be lower than 
these levels.

August will be a critical month for the heavily import-dependent state of 
California. While the state will be drawing approximately 7,000 aMW of 
imports during August to meet demands during peak periods, CERA expects the 
level of imports to exceed 8,200 MW during peak demand conditions. The 
Southwest's need to supply native demand first will limit its ability to 
export to California, and lower year-over-year hydroelectric production in 
the Pacific Northwest will limit exports from that region.

Pacific Northwest
CERA expects Pacific Northwest demand in August to climb by nearly 1,300 aMW 
when compared with June levels. The water supply for the Pacific Northwest 
has declined to 91 percent of normal levels for the Lower Columbia owing to 
warmer-than-normal weather in June. In addition, normal seasonal decline in 
runoff levels will drop about 6,000 aMW from the resource base when compared 
with levels in June (see Table 2). Generation plant operators have responded 
to both growing native demand and a robust export market by running coal and 
gas-fired generation at high levels. Although less than 4,000 MW of gas-fired 
generation is currently available in the region, it has been running at high 
utilization rates.

High energy demand in California for Pacific Northwest energy will keep 
differentials low between the regions. As in June, Pacific Northwest prices 
will respond in kind to the volatility CERA expects to occur in California in 
August. In addition, if hot weather in the Pacific Northwest pressures 
regional energy reserves, local prices will rise to keep energy in the 
region, potentially causing prices in the Pacific Northwest to move higher 
than those to the south.

California
California is entering the peak load season with relatively little generating 
capacity down for maintenance. Although hydroelectric output continues to 
decline, statewide reservoir storage levels remain high at roughly 118 
percent of normal. Nevertheless, declining hydroelectric production is 
expected to remove about 730 aMW when compared with hydroelectric production 
levels in June.

Normal summer weather will push demand in the state up by about 3,600 aMW 
over June levels, which were high (see Table 3). California's peak load is 
expected to exceed 57,000 MW, compared with a peak load in June of 
approximately 53,500 MW (43,447 MW on the state's ISO system alone, according 
to its own estimate). Assuming normal plant outage rates, this demand level 
will necessitate the import of about 8,200 MW of energy to meet the statewide 
peak. Even after curtailing the approximately 2,800 MW of interruptible load 
available for tight supply situations, the state has a precarious 6 percent 
capacity margin during the system peak. An extreme hot weather event could 
push state loads up by an additional 3,000 MW. Outages are likely if 
additional imports are not available.

A capacity limit of 4,600 MW will be in place during the summer for energy 
exports from the Pacific Northwest to Northern California. The import limit 
from the Pacific Northwest to southern California will be 3,100 MW.

Rockies and Southwest
August demand levels in the combined Rockies/Southwest region will increase 
only slightly above levels in August 1999, climbing approximately 275 aMW, as 
loads in the region-unlike the rest of the below-average WSCC-were near 
normal last August. Even so, August loads will increase demand by over 1,250 
aMW when compared with levels in June of this year. As with last year and 
this June, supplies in the region should be sufficient to meet peak demand 
conditions under normal weather, although growing loads in the 
Rockies/Southwest region have reduced its ability to supply neighboring 
regions with energy during peak demand conditions.

High loads driven by hot weather will keep the region's prices high. 
Differentials between the region and California will be tight, but 
California, having tighter supply-demand balances, will need to price at a 
premium to attract energy. The high-capacity transmission ties between the 
Rockies/Southwest and the California market, which is about 150 percent the 
size of the Rockies/Southwest market, will ensure that prices in the 
Rockies/Southwest stay close behind California prices whenever loads are high 
in California.

Regional Gas Market Drivers
Evidence of pipeline bottlenecks has emerged across the West, and supply and 
demand forces over the next year look likely to intensify these pressures. 
Since the Northern Border expansion in late 1998, narrow north-south and 
east-west differentials across pricing points defined the market. This 
summer, the continuing supply growth in the Rocky Mountains has widened 
differentials between the Rockies and the rest of the West. At Topock, 
increasing gas demand in California and high utilization rates have resulted 
in high premiums.

Overall in North American gas markets, strong storage injection rates in 
recent weeks have allowed some easing in prices-from an early July Henry Hub 
price of $4.50 per MMBtu to under $4.00 per MMBtu. However, despite these 
high injection rates, the supply-demand balance and absolute level of storage 
inventories remain precarious. Summer is not over and higher nationwide power 
loads in weeks to come will likely cut into storage injections and boost 
prices. The ongoing competition between power and storage for supply should 
support an average Henry Hub price of $4.20 per MMBtu in August.

Through the end of the summer, differentials in the West should hold near 
current levels. The pressure of growing Rocky Mountain supply will continue 
until heating loads start climbing in the fall. In California high seasonal 
power loads should continue through August with hot weather and continued 
declines in hydroelectric generation. Demand strength is expected to 
continue. Across the West, August demand for gas should climb from 9.8 
billion cubic feet (Bcf) per day in June to 10.4 Bcf per day, buoyed by an 
increase in gas demand for power generation (see Table 4).

California
High gas demand for power generation within California will continue through 
August. CERA expects an increase from the state's June demand levels of 5.6 
Bcf per day to 6.2 Bcf per day during August. The increase stems from 
declines in hydroelectric generation and increases in overall power loads. 
Total demand is expected to exceed last year's demand level by 1.2 Bcf per 
day. This will increase flows on pipelines into California, reduce the 
state's storage surplus, and sustain high prices. CERA expects pipeline 
utilization rates during August to average 95 percent (see Table 5). CERA 
expects an August Topock-Henry Hub differential of $0.45 per MMBtu (see Table 
6).

Pacific Northwest
Despite the extremely high prices at Topock and high demand in California, 
until recently gas at Malin priced at a slight discount to Henry Hub prices. 
After averaging $0.17 per MMBtu below the Henry Hub during the third quarter 
last year, the differential so far during the third quarter this year is 
$0.15 per MMBtu below the Hub. This week Malin is pricing at a $0.25 per 
MMBtu premium relative to the Henry Hub. The Topock-Malin differential has 
swelled to over $0.60 per MMBtu, signaling intra-California pipeline capacity 
constraints. Two factors pressured Malin differentials during the early 
summer.
* Pressure on Rocky Mountain and AECO differentials. Prices in the two areas 
supplying the Pacific Northwest are under some pressure. Increasing supplies 
in the Rockies are beginning to reach the limits of export capacity and put 
downward pressure on Rockies prices by limiting external market access. At 
AECO, although export capacity out of the province is available, almost all 
of that excess capacity accesses eastern Canada on TransCanada Pipeline. 
Pipelines into the United States are running near capacity. Because of 
TransCanada's limited ability to discount interruptible transport, the 
available space is more expensive and therefore the last to be filled.

* Low early summer regional demand. Gas demand in the Pacific Northwest is 
limited during late spring and early summer by declines in heating loads and 
very strong hydroelectric output. Even in a normal or dry hydroelectric year, 
seasonal runoff holds down gas demand for power generation in May and June 
even as gas demand for power generation begins climbing in California. 
Increasing power loads are already evident.

The first factor will likely endure until heating season begins in late fall 
and regional demand in the Rockies and western Canada begins climbing. 
However, gas demand for power generation in the Pacific Northwest has 
increased already this summer and will continue to climb through the end of 
July and into August as hydroelectric generation wanes. This added demand-200 
million cubic feet (MMcf) per day above June demand levels-will provide some 
support for Malin prices and limited support for Rockies and AECO prices. 
Malin-Henry Hub differentials are expected to average $0.05 per MMBtu above 
the Henry Hub price during August.

Rocky Mountains
Pressure on regional supplies within the Rockies continues as exports out of 
the region reach new highs. Differentials to the Henry Hub have widened to 
over $0.70 per MMBtu and although prices in the rest of the West will gain 
some support from high power loads, regional demand in the Rockies is 
expected to remain near low seasonal levels through August. August demand is 
expected to average 1.2 Bcf per day in the region, approximately equal to 
June's 1.1 Bcf per day total demand. Demand begins to build during September, 
but until the heating season begins in October, Rocky Mountain prices will 
lag well below prices in the rest of the West. CERA expects a Rocky 
Mountain-Henry Hub differential of $0.60 per MMBtu during August.

Although some narrowing in Rocky Mountain differentials looks likely as 
seasonal demand increases through the fall, the rapid build in supply in the 
region will likely keep differentials wide during 2001. CERA expects a supply 
build this year of nearly 300 MMcf per day, followed by a build of over 350 
MMcf per day during 2001. Currently, approximately 300 MMcf per day of excess 
pipeline export exists out of the region, with the largest increment on 
Transcolorado into the San Juan Basin. Next summer, all capacity will likely 
run close to full. Until export pipelines expand-the first likely expansion 
is Trailblazer-differentials will remain wide. For 2001, CERA expects an 
average annual differential below the Henry Hub of $0.65 per MMBtu.

Southwest
Differentials in the San Juan and Permian Basins have gained considerable 
strength relative to Henry Hub prices amid the recent hot weather in Texas. 
Permian supplies are pricing at a slight premium to the Henry Hub price, and 
in the San Juan Basin prices have narrowed from an early July differential of 
$0.35 per MMBtu to a differential of less than $0.20 per MMBtu. CERA expects 
demand in the Southwest during August of 1.4 Bcf per day, an increase from 
June's level of 1.3 Bcf per day, but the larger Texas market will determine 
the relative strength of differentials in those two basins. CERA expects a 
San Juan differential of $0.30 per MMBtu during August, with a Permian Basin 
differential of $0.06 per MMBtu.

Differentials between the Rocky Mountains and the San Juan Basin have widened 
substantially over the past two months with supply increases in the Rocky 
Mountains. Flows on Transcolorado increased from a monthly average of under 
20 MMcf per day to over 100 MMcf per day during June. Supply in the two 
regions is following opposite paths; Rockies supply is climbing rapidly, and 
San Juan supply has likely peaked and should decline slowly beginning this 
year. CERA expects a decline in supply of 30 MMcf per day during 2000 
relative to 1999 and an additional decline of 150 MMcf per day during 2001. 
Because of these different outlooks, wider Rockies-San Juan differentials 
will persist.

**end**

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