Mike,

Just got it this morning. An area to focus on.

Vince


---------------------- Forwarded by Vince J Kaminski/HOU/ECT on 01/21/2000 
07:15 AM ---------------------------


webmaster@cera.com on 01/20/2000 04:04:48 PM
To: Vince J Kaminski/HOU/ECT@ECT
cc:  
Subject: Briefing Note: Demand Overtakes Hydro in 2000 - CERA Alert





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CERA Alert:Thu, January 20, 2000
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Title: Briefing Note: Demand Overtakes Hydro in 2000
Author: Moritzburke, Zenker, Snyder
E-Mail Category: Alert
Product Line: California Energy ,
URL: http://www.cera.com/cfm/track/eprofile.cfm?u=5166&m=1054 ,

Western energy markets are starting the new year with precipitation 
conditions that suggest a repeat of 1999's hydroelectric conditions: 
near-normal snowpacks in the Pacific Northwest and Canada and low snowpacks 
in California. More significantly, even if snowpacks remain high in the 
Pacific Northwest, normal demand growth coupled with normal runoff patterns 
in the second and third quarters of 2000 would

*  reinforce the likelihood that gas prices will again set the floor for 
on-peak power prices

*  keep differentials across western power markets narrow

*  support higher power prices and increase volatility as gas-fired 
generation is run more intensively to meet demand in a market with tightening 
capacity margins

From 1999 to 2000, natural gas demand will swing upward by nearly 1,200 
million cubic feet (MMcf) per day in the third quarter in response to a 
return to normal hydroelectric output and demand growth. Gas price increases 
will follow from this increased demand. Although differentials between Topock 
and the Henry Hub during the third quarter of last year averaged only $0.05 
per MMBtu above the Henry Hub price, CERA expects to see differentials this 
year averaging around $0.25 per MMBtu above Henry. This stronger western 
demand should also narrow differentials between the Henry Hub and the San 
Juan Basin, and to a lesser extent, between Henry and the Permian Basin.

Western Snowpack and Hydro Capacity: A Subregional Story
Since the beginning of winter the Pacific Northwest has received normal 
precipitation, with greater snowpacks in the northern part of that region 
than in the southern part. California currently lags behind historical 
precipitation levels at roughly 26 percent of average (see Figure 1). Given 
current conditions, it is possible that California will end winter at 
below-average hydroelectric conditions.

Western hydroelectric facilities are concentrated in Oregon, Washington, and 
British Columbia, which contain over 75 percent (roughly 46,500 megawatts 
[MW]) of the Western Systems Coordinating Council's (WSCC's) hydroelectric 
capacity, producing 80 percent (roughly 253,500 gigawatt-hours [GWh]) of the 
region's total hydroelectric generation in an average year (see Figure 2). 
Because of this high concentration of facilities, above-average precipitation 
in the Pacific Northwest can help to offset below-average precipitation in 
California and other parts of the West, although transfer capabilities limit 
the amount of energy exported from those regions.

Power Markets for 2000: Building on 1999 Dynamics
Despite hydroelectric output that was 15 percent higher than average in 1999, 
western power prices reflected the cost of gas-fired generation resources 
during nearly all periods of the year. This was a greater proportion of the 
year than in 1998 even though hydroelectric production in 1998 was only 95 
percent of 1999 levels.* CERA expects several factors to strengthen this 
dynamic in 2000, assuming normal weather conditions:

*  Western demand growth. Normal weather and economic growth will increase 
regional demand by roughly 2 percent in 2000. Growth will be strongest in the 
second and third quarters, at 6 percent and 3.5 percent, respectively, adding 
9,000 GWh of demand in the second quarter, followed by 6,000 GWh in the third.

*  Return to normal hydroelectric production levels and patterns. Not only 
was 1999 hydroelectric production above normal, but 1999 Pacific Northwest 
runoff was prolonged by cool weather in the second and third quarters. Normal 
runoff dynamics in 2000 would remove roughly 6,500 MW of hydro capacity from 
the Pacific Northwest resource stack from the second to the third quarters 
(see Figure 3). By contrast, Pacific Northwest hydroelectric capacity was 
depleted by an estimated 3,000 MW from the second to the third quarters in 
1999 as a result of slower snowpack melt. This provided unseasonably high 
hydroelectric availability in the Pacific Northwest through the third and 
fourth quarters. The combination of reduced hydroelectric availability in a 
normal-weather year in 2000, a shifting of hydroelectric production back to a 
second quarter peak, and higher West-wide demand will increase the pull on 
nonhydroelectric generation resources (see Figure 4).

*  Energy exports to California. Sustained hydroelectric availability in 1999 
in the Pacific Northwest allowed exports from the region to California to 
remain strong through the third and fourth quarters, with exports at 150 and 
290 percent of normal, respectively. Exports added roughly 1,400 average 
megawatts (aMW) above average--and as much as 2,000 aMW in August--to 
California's resource base throughout the year. For 2000, CERA expects normal 
hydroelectric exports to average roughly 2,000 aMW (total of 17,500 GWh) 
during the year and 2,400 aMW (total of 5,300 GWh) in the third quarter (see 
Figure 5).

In 2000 the combination of normal load growth, normal spring and summer 
weather, and reduced hydroelectric availability will cause capacity margins 
to shrink, particularly in California (see Figure 6). The impact on power and 
gas prices will be

*  Higher average power prices. Lower average streamflows will diminish the 
output of run-of-river hydroelectric facilities during peak summer demand 
periods. As runoff dwindles into the summer, production from reservoir-fed 
facilities is available for a decreasing period of the on-peak hours. Other 
generation resources, particularly gas-fired, will be used to meet demand 
during a growing number of shoulder and off-peak hours in 2000. On-peak power 
prices will be driven higher by the increased use of gas-fired generation 
during shoulder hours. Off-peak power prices will respond to the greater 
reliance on gas-fired generation during those hours.

*  Higher average gas prices. Gas demand for power generation is expected to 
increase by 600 MMcf per day on average in 2000 and by up to 1,200 MMcf per 
day in the third quarter. This will contribute to price strength in western 
gas markets and to the higher costs of generating power.

Natural Gas Market
Although the effects of a return to normal hydro conditions become most 
evident in the third quarter as overall generation loads increase, CERA 
expects that some decline in hydroelectric output relative to last year is 
already causing a modest increase in gas demand in California. Although 
January West Coast weather has been comparable to last year, flows into 
California are up by 300 MMcf per day so far this month; storage withdrawals 
are up on a year-over-year basis as well. Based on the lower snowpack and 
lower average precipitation in California this month relative to last 
January, in-state hydroelectric generation explains approximately 400 MMcf 
per day of increased gas demand.

Normal hydroelectric generation this year will likely bring a 250 MMcf per 
day increase in western gas demand for power generation during the first 
quarter. Early indications of normal-to-above-normal snowpack and 
precipitation in the Pacific Northwest should center these increases in 
California.

This modest demand increase has helped support prices in the western markets, 
with regional weather differences contributing to western strength as well. 
Weather in both the United States as whole and the West averaged 10 percent 
warmer than normal during December, but during January temperatures in the 
West averaged only 8 percent warmer than normal while temperatures in the 
United States averaged 30 percent below normal.

Western Regional Prices
Over the next two months as seasonal heating loads within the West begin to 
tail off and hydroelectric generation increases modestly, differentials 
between western producing basins and the Henry Hub should widen. At the same 
time, as required flows into California decline, the Topock premium above 
Henry Hub prices should decline, with prices eventually falling below the Hub 
price. However, with normal weather in the West, that general weakening in 
western prices will likely take place toward the end of February and into 
March. Given the warm January, CERA expects heating load to decline by only 
400 MMcf per during February. Loads look sufficient to sustain western 
differentials near current levels.

California
As more normal winter weather takes hold in the East, prices should increase 
in that market relative to California. So far this month, strong flows into 
the state have held Topock differentials around $0.10 per MMBtu relative to 
the Henry Hub. During February flows into the state are expected to decline 
somewhat as heating demand begins to decline. Table 1 shows expected flows 
into California for winter 1999/2000 compared with winter 1998/1999. That 
weakening in the Topock differential is limited, however. Expected lower 
storage inventories in California relative to last year, as well as a low 
upside to eastern prices, should keep Topock prices from falling more than 
$0.05 per MMBtu below the Henry Hub during February. Topock prices are 
expected to maintain a $0.03 per MMBtu premium to the Henry Hub price (see 
Table 2).

Pacific Northwest
Although some cold weather in the Pacific Northwest has held Malin prices 
close to Topock prices during January, CERA expects the Malin price to weaken 
relative to Topock during February--and more dramatically in March. Two 
factors are expected to contribute to this weakening:

*  Hydroelectric output. Although February will bring a decline in heating 
load in both the Pacific Northwest and California regions, gas will receive 
some support from decreased hydroelectric generation relative to last year in 
California. In the Pacific Northwest gas demand is limited during spring even 
in normal hydroelectric generation conditions.

*  Canadian flows. Flows to the West Coast on Pacific Gas Transmission during 
the first quarter of 1999 dropped from an average of 2.6 Bcf per day during 
1998 to 2.4 Bcf per day as Canadian supplies headed into the Midwest on the 
Northern Border expansion. This year, given the year-over-year increase in 
Canadian supply, those flows into the Pacific Northwest should rebound to 
1998 levels.

The Topock-Malin differential so far this month has averaged only $0.06 per 
MMBtu. During the first quarter of 1999, that differential averaged $0.09 per 
MMBtu. Because of the forces described above, CERA expects a wider 
differential--$0.13 per MMBtu--this February.

Rocky Mountains
Similar forces will drive a widening in Rocky Mountain prices relative to 
prices in the south. Regional Rockies supplies are likely to increase as 
regional demand declines--although warm January weather will limit declines 
to 100 MMcf per day during February. The decline in heating load in the 
Pacific Northwest, with continued strong Canadian imports, will allow 
increased exports from the Pacific Northwest into the Rocky Mountain region 
on Northwest pipeline--similar to 1998 conditions. Within the Rockies, supply 
builds continue in the Powder River Basin; the new Fort Union and Thunder 
Creek gathering systems are now delivering a total of approximately 100 MMcf 
per day into the Rocky Mountain interstate pipeline system. Rockies 
differentials to the Henry Hub should average $0.25 per MMBtu during February.

Southwest
As demand declines and supply builds in the Rocky Mountains, CERA expects the 
spread between Rocky Mountain and San Juan Basin prices to increase slightly, 
but for February, Rockies heating load will likely keep the prices close. 
Although the differential between the two basins has averaged $0.03 this 
month and held at less than $0.05 during December, a $0.05 per MMBtu spread 
appears likely for February. This slight increase marks only the beginning of 
a wider divergence. CERA expects the differential between the two basins to 
widen to over $0.15 per MMBtu this summer as San Juan prices gain support 
from strong demand in California power markets.





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