Western Energy Markets Stuggle Along

below is an article on California for your review - Eric

++++++++++++++++++++++

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

=09webmaster@cera.com
=0901/26/2001 02:48 PM
=09=09=20
=09=09 To: insights@cera.com
=09=09 cc:=20
=09=09 Subject: Western Energy Markets Stuggle Along - CERA Monthly Briefin=
g

Title: Western Energy Markets Stuggle Along
URL: http://www20.cera.com/eprofile?u=3D35&;m=3D2220

Western Market Overview

As the California power crisis remains unresolved and blackouts in Californ=
ia
have gone from threat to reality, the western gas and power markets grow
increasingly distorted by the perceived risk of selling energy to Californi=
a=01,s
two largest utilities. Normal power plant operations and power pricing=20
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 me=
et
current demand such that, in the absence of increased precipitation through=
out
the West, suppliers will be unable to depend heavily on hydroelectric outpu=
t=20
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=01,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 Decem=
ber
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 bas=
ins
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 th=
e
shift to warmer weather. However, there is growing unease in the power mark=
ets
with the dry precipitation season to date. A significantly lower-than-avera=
ge
hydroelectric season would permeate through the power markets for all of 20=
01,
placing gas-fired generation on the margin virtually the entire year. CERA =
has
incorporated a lower-that-average view of hydroelectric generation into its=
=20
gas
and power analyses. February on-peak power prices are expected to average=
=20
$140=01)
$166 per megawatt-hour (MWh) in February, depending on location, but tempor=
ary
price spikes are likely as California reserves reach critically low levels =
and
the independent system operator (ISO) struggles to secure enough power to k=
eep
the lights on. Off-peak power prices are also expected to remaining strong,
averaging $94=01)$135 per MWh in February, depending on location.

Regional Power Market Drivers: Low Precipitation Threatens Already Difficul=
t
2001

Disappointing levels of precipitation have raised the specter that the 2001
power markets will be plagued by a below-average hydroelectric year.=20
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 Colum=
bia
River Basin, and 50 percent of normal for California. January hydroelectric
output westwide has been higher than normal, as operators have run faciliti=
es
hard to supply energy during December and January energy shortages. In comi=
ng
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 drawdo=
wn.
CERA has incorporated an outlook for hydroelectric production in 2001 that =
is
approximately 88 percent of CERA=01,s estimate for an average western hydro=
year
(see Table 1).

Concerns over low precipitation levels and the high drawdown rate of Pacifi=
c
Northwest hydroelectric facilities leave the Pacific Northwest particularly
vulnerable to higher prices in February, as winter weather=01)driven demand=
=20
spikes
challenge regional supplies and California demand prevents a significant le=
vel
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 th=
e=20
39
percent average level of the first quarter 2000. (see Table 2) The combine=
d
effects of the early drawdown of hydroelectric facilities, a disappointing
precipitation season, and demand growth will push these utilization rates t=
o
nearly 60 percent in the first quarter 2001. This will cause markets to cl=
ear
at or above the production cost of gas-fired generation even more often tha=
n=20
in
2000.

Pacific Northwest

Hydroelectric generators in the Pacific Northwest have drawn down the regio=
n=01,s
hydroelectric reservoirs to well below average historical levels. Grand=20
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 Janu=
ary
and reflects the general condition of the major reservoirs in the region. I=
n
the event that precipitation remains low, the drawdown of these facilities =
in
early winter to meet load spikes in the Pacific Northwest and California ha=
s
hurt the region=01,s ability to supply power throughout 2001 and will maint=
ain
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 grow=
th
for the first quarter near 5 percent is expected, however, owing to economi=
c
growth and a return to normal weather from last year=01,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 win=
ter
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=01,s averag=
e 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 fo=
r a
monthly average of $141 per MWh on peak and $135 per MWh off peak. Continue=
d
drops in hydroelectric reservoirs and weather-related events would push pri=
ces
periodically to December=01,s high levels.

California

Although California has had a December and early January that were nearly 1=
0
percent warmer than usual, January prices have reflected 5 percent demand
growth over 2000 owing to economic and other growth factors that have pushe=
d
gas-fired generators onto the margin more often, with higher gas prices at
Topock by $7 MMBtu, low hydroelectric availability westwide, and the degrad=
ed
condition of the California power market. Northern California snowpacks hav=
e
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 betwee=
n=20
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=01,s largest
hydroelectric facilities.

As California=01,s largest investor-owned utilities (IOUs) continue to stru=
ggle=20
to
obtain gas and power supplies in the face of financial insolvency, Californ=
ia
power prices have reflected a premium associated with the higher risk of
supplying the state. January differentials with western prices have grown a=
s
high as $40 per MWh, owing in part to temporary supply shortages as nuclear=
=20
and
other thermal plant outages at times have totaled over 15,000 MW. Northern
California=01,s import constraints make it particularly susceptible to thes=
e
temporary shortages, suggesting that continued low hydroelectric supplies w=
ill
increase the risk of repeated localized blackouts in the event of extensive
future outages.

The agreements reached through negotiations between suppliers, the IOUs, an=
d
state and federal officials in recent weeks will calm some of the price-
inflating uncertainty in the market, but California will be the premium mar=
ket
through the first quarter of 2001 and most of the coming year owing to
persistent supply tightness. For February in California CERA expects sustai=
ned
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 firs=
t
half of January but have not been completely insulated from the price run-u=
ps
in other parts of the West. Demand growth in the region is expected to be n=
ear
3 percent for the first quarter, with February experiencing moderate 2 perc=
ent
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 duri=
ng
the winter and=01*as an isolated subregion=01*would exceed 15 percent at th=
is time.

Compared with California prices, prices in the Southwest and Rockies region=
s
will reflect the relatively low cost of gas supply and the prevalence of co=
al-
fired generation (16,000 MW, or 48 percent of the installed base in the
region). CERA=01,s outlook for on-peak average price for February is $150 p=
er=20
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=20
influence
on the Southwest than on the Rockies.

Western Gas Markets

Although gas prices at Topock have come down from lofty December levels,=20
winter
is far from over in the West; indeed, the pressure is intensifying. The cre=
dit
crisis precipitated by the power market crisis is spilling over into gas
markets; storage levels within California are again at critically low level=
s.
The mild weather during December and early January allowed some improvement=
in
the positions, but when PG&E=01,s suppliers began refusing to serve because=
of=20
the
utility=01,s credit problems, the utility responded by drawing heavily on s=
torage
inventories, and a spell of wintry weather compounded increased demand in t=
he
face of limited supplies. As a result, overall inventory levels are again
falling quickly.

CERA estimates that inventory levels in California are approximately 50=20
billion
cubic feet (Bcf). A continued heavy draw on gas for power generation will k=
eep
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 a=
nd
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=
=20
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=
=20
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=01*particularly in California=01*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,=20
plants
outside of California do have some backup capability. Arizona Public Servic=
e
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 us=
ers
to limit gas burns in the state in the face of extremely high gas prices, C=
ERA
expects demand during January in the state is up by 650 MMcf per day on a=
=20
year-
over-year basis. In February, loads should start to decline as residential =
and
commercial demand declines through the month. However, power loads will rem=
ain
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 dra=
ws
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 fo=
r
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, th=
e
return of colder winter weather after moderate temperatures during late
December and early January is increasing heating loads and power loads.=20
Second,
lower-than-normal hydroelectric generation is increasing the draw on gas fo=
r
power generation during a season when the pull is normally low. Third, the
California power shortage is drawing on all regional supplies and supportin=
g
the demand for gas for power generation.

Pacific Northwest demand is expected to hold flat relative to January level=
s
during February with slight increases in gas demand for power generation
offsetting declines in residential and commercial demand. The sustained hig=
h
demand levels=01*despite relatively healthy Northwest storage inventory lev=
els=01*
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 powe=
r
generation. However, prices at Malin will likely remain unusually strong th=
is
spring. Part of the shortfall in hydroelectric generation continues to be=
=20
made=20
up by draining reservoirs. That early drawdown will limit the availability =
of
hydroelectric generation through the spring and early summer months. Both l=
ow
hydroelectric generation and a challenging storage refill season in Norther=
n
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 support=
s
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. Duri=
ng
February, demand should drop off in the region. Although declines in heatin=
g
loads in neighboring western regions will be offset by increases in gas dem=
and
for power generation, the Rockies remain primarily coal based. As a result,=
=20
the
lower expected hydroelectric output will do little to support loads within =
the
region. Increases in supply=01*CERA expects supply increases of 300 MMcf pe=
r day
during 2001 relative to 2000=01*will overwhelm available pipeline capacity =
out of
the region.

Demand during February in the Rockies is expected to remain flat at 2.9 Bcf=
=20
per
day; however, within the month demand loads will drop substantially. This w=
ill
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 a=
nd
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=20
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 an=
d
March, prices in the San Juan will reflect ample supply. CERA expects decli=
nes
in San Juan production during 2001, but declines will be limited by the
strongest drilling activity for conventional supplies in the basin in a=20
decade.
However, pressure on Rocky Mountain supplies will mean increased exports fr=
om
the north into the San Juan, and those increased exports will more than off=
set
the declines in local production. Pipeline capacity constraints out of the =
San
Juan will again mean wide San Juan-to-Henry Hub differentials, with pressur=
e=20
on
prices developing during the spring and intensifying through the summer=20
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 $0.6=
0=20
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 seas=
on,
and exports should decline relative to first quarter levels as injection=20
season
begins in the spring. CERA expects differentials to Henry Hub prices to nar=
row
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 evide=
nt.
After flat production levels for 2000 relative to 1999, increases for the y=
ear
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=
=20
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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