below is an article on California for your review - Eric

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----- Forwarded by Eric Benson/NA/Enron on 01/26/2001 04:58 PM -----

	webmaster@cera.com
	01/26/2001 02:48 PM
		 
		 To: insights@cera.com
		 cc: 
		 Subject: Western Energy Markets Stuggle Along - CERA Monthly Briefing



Title: Western Energy Markets Stuggle Along
URL: http://www20.cera.com/eprofile?u=35&m=2220


Western Market Overview

As the California power crisis remains unresolved and blackouts in California
have gone from threat to reality, the western gas and power markets grow
increasingly distorted by the perceived risk of selling energy to California,s
two largest utilities. Normal power plant operations and power pricing 
dynamics
have been supplanted with federal mandates to deliver power to California, and
power basis differentials are being influenced by credit risk. Regional
hydroelectric supplies have been drawn down at abnormally rapid rates to meet
current demand such that, in the absence of increased precipitation throughout
the West, suppliers will be unable to depend heavily on hydroelectric output 
in
February and later in the year. Gas suppliers are growing increasingly wary
about shouldering the increased risk.

Natural gas and power prices have declined from December,s record levels,
driven in part by January-to-date weather that has been warmer than normal.
Although Topock gas prices remain above the $10 per million British thermal
units (MMBtu) level, basis differentials to the Henry Hub have declined
dramatically from a premium over Henry Hub prices of $15 per MMBtu in December
to an average of $5.00 per MMBtu in January. Demand levels will likely hold
near January levels during February, as the already intense pull of gas for
power generation continues. Because storage levels in California remain low,
the California citygates will be exposed to temporary price spikes during
spells of cold weather. Differentials for February are expected to average
$0.65 to $0.75 per MMBtu, in the Rocky Mountains and San Juan producing basins
during February, $0.65 per MMBtu at AECO, and $3.00 per MMBtu at Topock.

Power prices in January have followed both the decline in gas prices and the
shift to warmer weather. However, there is growing unease in the power markets
with the dry precipitation season to date. A significantly lower-than-average
hydroelectric season would permeate through the power markets for all of 2001,
placing gas-fired generation on the margin virtually the entire year. CERA has
incorporated a lower-that-average view of hydroelectric generation into its 
gas
and power analyses. February on-peak power prices are expected to average 
$140)
$166 per megawatt-hour (MWh) in February, depending on location, but temporary
price spikes are likely as California reserves reach critically low levels and
the independent system operator (ISO) struggles to secure enough power to keep
the lights on. Off-peak power prices are also expected to remaining strong,
averaging $94)$135 per MWh in February, depending on location.

Regional Power Market Drivers: Low Precipitation Threatens Already Difficult
2001

Disappointing levels of precipitation have raised the specter that the 2001
power markets will be plagued by a below-average hydroelectric year. 
Season-to-
date precipitation is currently 55 percent of normal in the upper Columbia
River Basin in British Columbia, 50 to 75 percent of normal in the US Columbia
River Basin, and 50 percent of normal for California. January hydroelectric
output westwide has been higher than normal, as operators have run facilities
hard to supply energy during December and January energy shortages. In coming
months, however, output will be down roughly 2,275 average megawatts (aMW)
compared with the first quarter of 2000, owing in part to this early drawdown.
CERA has incorporated an outlook for hydroelectric production in 2001 that is
approximately 88 percent of CERA,s estimate for an average western hydro year
(see Table 1).

Concerns over low precipitation levels and the high drawdown rate of Pacific
Northwest hydroelectric facilities leave the Pacific Northwest particularly
vulnerable to higher prices in February, as winter weather)driven demand 
spikes
challenge regional supplies and California demand prevents a significant level
of exports from California to the Pacific Northwest.

Even under normal hydroelectric conditions, demand growth in early 2001 was
expected to push the utilization rates of US Western Systems Coordinating
Council (WSCC) gas-fired generation facilities to 50 percent, well above the 
39
percent average level of the first quarter  2000. (see Table 2) The combined
effects of the early drawdown of hydroelectric facilities, a disappointing
precipitation season, and demand growth will push these utilization rates to
nearly 60 percent in the first quarter  2001. This will cause markets to clear
at or above the production cost of gas-fired generation even more often than 
in
2000.

Pacific Northwest

Hydroelectric generators in the Pacific Northwest have drawn down the region,s
hydroelectric reservoirs to well below average historical levels. Grand 
Coulee,
the largest hydroelectric facility in the West, with over 6,000 megawatts (MW)
of capacity, was near 75 percent of the historical average as of early January
and reflects the general condition of the major reservoirs in the region. In
the event that precipitation remains low, the drawdown of these facilities in
early winter to meet load spikes in the Pacific Northwest and California has
hurt the region,s ability to supply power throughout 2001 and will maintain
upward pressure on power prices.

Above-average temperatures in early January have helped to mask some of the
underlying strong fundamentals in the Pacific Northwest. Strong demand growth
for the first quarter near 5 percent is expected, however, owing to economic
growth and a return to normal weather from last year,s mild winter (see Table
3). Low hydroelectric availability and persistent gas prices in the $6 to $8
per MMBtu range at Sumas have the potential during the remainder of the winter
to cause price spikes well above the $226 per MWh on-peak levels so far in
January, although average prices should be much lower. December,s average of
$570 per MWh demonstrated this potential clearly (see Table 4). Along with
demand growth near 5.5 percent year-over-year in February, cold snaps will
again bring price run-ups, particularly in the event that persistent low
precipitation in the region reduces the ability of hydroelectric operators to
draw down facilities past already-low levels.

CERA expects Mid-Columbia prices to stay near January levels in February for a
monthly average of $141 per MWh on peak and $135 per MWh off peak. Continued
drops in hydroelectric reservoirs and weather-related events would push prices
periodically to December,s high levels.

California

Although California has had a December and early January that were nearly 10
percent warmer than usual, January prices have reflected 5 percent demand
growth over 2000 owing to economic and other growth factors that have pushed
gas-fired generators onto the margin more often, with higher gas prices at
Topock by $7 MMBtu, low hydroelectric availability westwide, and the degraded
condition of the California power market. Northern California snowpacks have
been higher than in other parts of the state but hover near 55 percent of
normal in spite of recent storms. Reservoir levels for the state are between 
50
and 100 percent of average, depending on location, but are in the 70 to 80
percent-of-average range for reservoirs affecting the state,s largest
hydroelectric facilities.

As California,s largest investor-owned utilities (IOUs) continue to struggle 
to
obtain gas and power supplies in the face of financial insolvency, California
power prices have reflected a premium associated with the higher risk of
supplying the state. January differentials with western prices have grown as
high as $40 per MWh, owing in part to temporary supply shortages as nuclear 
and
other thermal plant outages at times have totaled over 15,000 MW. Northern
California,s import constraints make it particularly susceptible to these
temporary shortages, suggesting that continued low hydroelectric supplies will
increase the risk of repeated localized blackouts in the event of extensive
future outages.

The agreements reached through negotiations between suppliers, the IOUs, and
state and federal officials in recent weeks will calm some of the price-
inflating uncertainty in the market, but California will be the premium market
through the first quarter of 2001 and most of the coming year owing to
persistent supply tightness. For February in California CERA expects sustained
price strength of $152 per MWh on peak and $126 per MWh off peak.

Rockies and the Southwest

The Southwest and Rockies regions had warm weather in December and the first
half of January but have not been completely insulated from the price run-ups
in other parts of the West. Demand growth in the region is expected to be near
3 percent for the first quarter, with February experiencing moderate 2 percent
growth, suggesting that most of the price strength will be attributed to
interconnections with the hydro-deprived California and Pacific Northwest
markets. Capacity margins in the Southwest are at their highest levels during
the winter and*as an isolated subregion*would exceed 15 percent at this time.

Compared with California prices, prices in the Southwest and Rockies regions
will reflect the relatively low cost of gas supply and the prevalence of coal-
fired generation (16,000 MW, or 48 percent of the installed base in the
region). CERA,s outlook for on-peak average price for February is $150 per 
MWh.
Off-peak prices in the Rockies will drop nearly $25 per MWh below the
Southwest, reflecting the ability of California markets to exert more 
influence
on the Southwest than on the Rockies.

Western Gas Markets

Although gas prices at Topock have come down from lofty December levels, 
winter
is far from over in the West; indeed, the pressure is intensifying. The credit
crisis precipitated by the power market crisis is spilling over into gas
markets; storage levels within California are again at critically low levels.
The mild weather during December and early January allowed some improvement in
the positions, but when PG&E,s suppliers began refusing to serve because of 
the
utility,s credit problems, the utility responded by drawing heavily on storage
inventories, and a spell of wintry weather compounded increased demand in the
face of limited supplies. As a result, overall inventory levels are again
falling quickly.

CERA estimates that inventory levels in California are approximately 50 
billion
cubic feet (Bcf). A continued heavy draw on gas for power generation will keep
demand levels high (see Table 5), and the inability to manage demand spikes by
drawing on storage inventories leaves the market exposed to price spikes.
Normal weather during February would probably allow prices at both Topock and
Malin to settle back into the $0.50 to $3.00 premium to the Henry Hub, but
extreme weather could push basis differentials as high as $6.00 per MMBtu.

In the Rockies and San Juan Basins, differentials will depend critically on 
the
weather. Because supply levels and storage inventories in the Rockies are
healthy, the impact of swings in regional demand can cause wide swings in
differentials. CERA expects the swings to continue through February, with
differentials generally maintaining wider discounts to the Henry Hub by the 
end
of the month.

As high absolute gas prices continue, more and more effects of these prices
will emerge. CERA estimates that 200 MMcf per day of base industrial demand in
the West*particularly in California*has switched off of gas. Some end users
have turned to diesel fuel for industrial boilers; some plants have simply
curtailed operations in response to the higher prices.

On the power side, plants within California are extremely limited in their
ability to burn alternative fuels because of emissions credits. However, 
plants
outside of California do have some backup capability. Arizona Public Service
has purchased 400,000 barrels of 1% sulfur residual fuel oil to burn as an
alternative to gas. Given the intense pressure on gas, oil will absorb some of
growth in power loads.

California

In November an early strong draw on storage in California raised questions
about winter deliverability within the state. A combination of low storage
inventories, high gas demand for power generation, and continued high
utilization rates on import pipelines into the state will keep pressure on
California prices through February (see Table 6). Despite efforts by end users
to limit gas burns in the state in the face of extremely high gas prices, CERA
expects demand during January in the state is up by 650 MMcf per day on a 
year-
over-year basis. In February, loads should start to decline as residential and
commercial demand declines through the month. However, power loads will remain
strong and actually climb from January into February as hydroelectric
generation falls.

This demand support, continued strong capacity utilization rates in import
pipelines into California, and critically low storage inventories will keep
intense pressure on gas prices within the state through February. During
periods of high demand, prices will likely reach back up into the $15.00 to
$20.00 per MMBtu range. Eventually, as heating loads settle and storage draws
slow toward the end of February, differentials should ease back into the $1.00
to $3.00 per MMBtu range. On balance, CERA expects a Topock differential for
February of $3.00 per MMBtu (see Table 7).

Pacific Northwest

Three factors have combined to strengthen Malin prices over the past week, and
these forces should extend price strength at Malin into February. First, the
return of colder winter weather after moderate temperatures during late
December and early January is increasing heating loads and power loads. 
Second,
lower-than-normal hydroelectric generation is increasing the draw on gas for
power generation during a season when the pull is normally low. Third, the
California power shortage is drawing on all regional supplies and supporting
the demand for gas for power generation.

Pacific Northwest demand is expected to hold flat relative to January levels
during February with slight increases in gas demand for power generation
offsetting declines in residential and commercial demand. The sustained high
demand levels*despite relatively healthy Northwest storage inventory levels*
will keep Malin prices well above Henry Hub prices. CERA expects a Malin to
Henry Hub differential of $1.00 per MMBtu during February.

A drop-off in demand of 200 MMcf per day is expected in March, as steep
declines in heating loads offset continued increases in gas demand for power
generation. However, prices at Malin will likely remain unusually strong this
spring. Part of the shortfall in hydroelectric generation continues to be 
made 
up by draining reservoirs. That early drawdown will limit the availability of
hydroelectric generation through the spring and early summer months. Both low
hydroelectric generation and a challenging storage refill season in Northern
California should sustain the Malin premium to the Henry Hub even into the
spring.

Rocky Mountains

The volatility in Rocky Mountain differentials continues. Differentials
continue to depend primarily on local heating loads; cooler weather supports
loads and prices within the region, but periods of warm weather drive steep
declines in Rocky Mountain prices relative to prices at the Henry Hub. During
February, demand should drop off in the region. Although declines in heating
loads in neighboring western regions will be offset by increases in gas demand
for power generation, the Rockies remain primarily coal based. As a result, 
the
lower expected hydroelectric output will do little to support loads within the
region. Increases in supply*CERA expects supply increases of 300 MMcf per day
during 2001 relative to 2000*will overwhelm available pipeline capacity out of
the region.

Demand during February in the Rockies is expected to remain flat at 2.9 Bcf 
per
day; however, within the month demand loads will drop substantially. This will
put pressure on differentials toward the end of the month, and CERA expects
average basis differentials to the Henry Hub during February of $0.75 per
MMBtu. That widening trend should continue during March, with differentials to
the Henry Hub eventually reaching $2.00 per MMBtu this summer.

Southwest

Prices in the San Juan Basin have been following Rocky Mountain prices up and
down with regional demand loads. That dynamic will likely continue through
February. CERA expects relatively flat demand during February within the
Southwest. As in the West as a whole, a significant drop-off is expected 
during
March as residential and commercial heating demand wanes. For February,
continued strong demand loads within the Rockies and Southwest will support
prices in the San Juan, barring unusually warm weather. CERA expects a
differential to the Henry Hub of $0.65 per MMBtu.

As residential and commercial loads decline sharply during late February and
March, prices in the San Juan will reflect ample supply. CERA expects declines
in San Juan production during 2001, but declines will be limited by the
strongest drilling activity for conventional supplies in the basin in a 
decade.
However, pressure on Rocky Mountain supplies will mean increased exports from
the north into the San Juan, and those increased exports will more than offset
the declines in local production. Pipeline capacity constraints out of the San
Juan will again mean wide San Juan-to-Henry Hub differentials, with pressure 
on
prices developing during the spring and intensifying through the summer 
months.

Western Canada: Increasing Supply

AECO differentials to the Henry Hub have ranged between $0.60 per MMBtu and
over $1.00 per MMBtu. Given strong demand in the United States, export
pipelines have been running near capacity all winter. Even the 1.3 Bcf per day
Alliance pipeline has been running full; through the end of the winter,
continued strong US demand should keep export pipeline flows near capacity.
Given these flow levels, CERA expects differentials to remain near the $0.60 
to
$1.00 per MMBtu level, reflecting the cost of transport on TransCanada, the
only available export capacity out of Alberta. For February, CERA expects a
differential between AECO and the Henry Hub of $0.65 per MMBtu.

Storage inventories in western Canada are running below historical average
levels, but the refill season should be manageable; inventories are nowhere
near as low as US inventory levels. Inventories in the West are expected to
fall slightly below historical average levels by the end of withdrawal season,
and exports should decline relative to first quarter levels as injection 
season
begins in the spring. CERA expects differentials to Henry Hub prices to narrow
sometime in the late spring as the focus in Alberta turns from filling US
winter demand to refilling Canadian storage.

On the supply side, production has turned the corner in western Canada, and
year-over-year increases in supply of nearly 300 MMcf per day are now evident.
After flat production levels for 2000 relative to 1999, increases for the year
2001 should reach 350 MMcf per day. Given strong expected demand from
California and the West Coast, CERA expects no declines in year-over-year 
flows
into the West on PGE GT NW. Overall flows should reach 2.4 Bcf per day for
2001, an increase of 85 MMcf per day from 2000 levels.

**end**

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