---------------------- Forwarded by Lorna Brennan/ET&S/Enron on 12/11/2000 
12:30 PM ---------------------------


webmaster@cera.com on 12/08/2000 09:33:35 PM
To: Lorna.Brennan@enron.com
cc:  

Subject: Western Market Crisis: Gas Joins Power - CERA Alert




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CERA Alert: Sent Fri, December 08, 2000
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Title: Western Market Crisis: Gas Joins Power
Author: CERA
E-Mail Category: Alert
Product Line: Western Energy , North American Gas ,

URL:
Western Energy Members: 
http://www.cera.com/client/ce/alt/120800_18/ce_alt_120800_18_ab.html
N. American Gas Memeber:
http://www.cera.com/client/nag/alt/120800_18/nag_alt_120800_18_ab.html
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Western Markets Disconnect
The western energy markets are currently in a pricing
crisis. Power supply shortages and threats of system
blackouts have resurfaced this winter in California, and
spiking natural gas prices have become the latest energy
headache for the West. Gas prices along the Pacific
corridor from Kingsgate in the North to Topock in the
South have jumped to over $40.00 per MMBtu during
December after averaging over $15.00 per MMBtu through
the second half of November. Extreme weather, strong
power demand for gas, and unusually low gas storage
levels have combined to intensify the demand for
pipeline gas and have exposed a latent capacity
bottleneck in bringing gas to this far western corridor.
The result is prices that dramatically "disconnected"
from the rest of the North American gas market in a way
that is more typical of Northeast markets during the
winter.

The vulnerability to additional spikes will endure as
the demand drivers combined with weakened storage
inventories will maintain price pressure on western
price points throughout the winter. However, the recent
jumps in western gas market differentials-to more than a
$10 per MMBtu premium to the Henry Hub-should ease
somewhat with a break in the weather. Under any weather
scenario, spikes up into the $15.00-$20.00 per MMBtu
range will be a feature of winter markets along the West
Coast. On balance, we expect West Coast price
differentials to average at a $4.00-$8.00 per MMBtu
premium through winter. The spring hydroelectric runoff
season should offer the first opportunity for a break in
differentials that could drop back to more typical
levels of less than $1.00 per MMBtu.

Over the long term, increased pipeline capacity and
additional gas supply are needed to break the
vulnerability to future West Coast price spikes.
However, significant new capacity additions are still 12
to 24 months away. In the meantime-particularly this
winter-sustained high and volatile price differentials
and extremely high absolute prices at western points are
likely to draw the increased attention of state
regulators and the FERC, as winter heating demand
exposes residential customers to the direct cost of the
crisis.

Building Up to the Price Spike
The first signs of natural gas price spikes and
disconnects emerged this summer, as sharp year-over-year
increases in demand pushed pipeline utilization rates to
new highs. As pipeline capacity constraints into
California became evident, differentials in Southern
California moved up to a $1.00 per MMBtu premium to the
Henry Hub. These extremely high prices, as well as low
forward spreads, discouraged storage injections through
the summer. As a result, a strong storage position early
in the summer deteriorated rapidly from May through
July. In August a lateral on El Paso's southern system
exploded; the accident further limited pipeline capacity
into California for a two-week period. During that time,
the market drew heavily on storage inventories and
further weakened storage positions. As hydroelectric
generation declined through the summer, the price
strength extended into Northern California. Malin, which
had been pricing near parity with the Henry hub in the
summer, began trading at a $0.50 per MMBtu premium to
the Henry Hub in September. The summer and early fall
market set the stage for continued and more intense
spikes this winter. The following factors are now
driving this market:

* Continuing surges in gas demand. Gas demand levels
have remained high since early summer, driven by higher
overall demand for electricity and lower hydroelectric
output. Demand levels for the third quarter in the US
West averaged 10.7 billion cubic feet (Bcf) per day, up
from 8.7 Bcf per day during the third quarter 1999.
Persistently strong gas-fired generation production
through the fall months diverted gas to power
production, frustrating efforts to fill storage. This
pressure will continue. The year-over-year demand
increases from the power sector will be compounded, as
evidenced in November, by swings upward in residential
and commercial heating demand of 800 million cubic feet
(MMcf) per day. Overall, CERA expects nearly 1.6 Bcf per
day of increased demand in the West this winter, with
the critical California and Pacific Northwest regions
showing 1.2 Bcf per day of increased demand. Key power
sector drivers, including the strong economy, colder
weather, and lower hydroelectric generation, will
continue to push gas-fired generation.

* Pipeline utilization nears capacity. Strong western
demand for gas has pushed utilization rates on western
pipes to high levels. Flows from British Columbia into
the Northwest pipeline have remained at high levels
since summer, while flows from the Rockies on Northwest
have remained at pipeline capacity. Flows on PGT into
Kingsgate have remained at or near capacity, although
approximately 300 MMcf per day of excess capacity exists
on PGT into California at Malin. Likewise, flows out of
the Rockies on Kern River pipeline have consistently
remained at capacity. The only slack pipeline capacity
remaining for West Coast gas markets has been on
Southwest pipes. During the past few months, these
pipelines have operated at their highest utilization
rates since the addition of capacity from Canada early
last decade. The high utilization of western pipeline
capacity-reminiscent of power plant capacity constraints
that helped propel power prices to all time highs in the
West this summer-leaves very little slack capacity to
provide a relief valve for demand spikes. And that is
exactly what has driven prices during the past few weeks
(see Figure 1). Given the level of storage inventories
and expected gas demand, flows on the El Paso and
Transwestern pipelines will have to reach even higher
flow levels from December through March than they have
averaged through November.

* Deteriorating storage position. At the start of
November California storage inventories held at 154 Bcf,
a full 32 Bcf below the five-year average inventory
level. The strong in-state withdrawals during November
weakened that position to 128 Bcf; the deficit swelled
to 62 Bcf. Inventories in California have never fallen
below 60 Bcf, so deliverability through the end of
winter is likely less than 700 MMcf per day. Storage
inventories in California are so low that utilities'
ability to balance withdrawals from storage with
purchases from demand-sensitive price points is severely
limited. If the cold weather blast anticipated for mid-
December materializes, this effort at balance will be
even further compromised for the remainder of winter
(see Figure 2).

* Short-term contracting. A significant amount of
western gas is purchased or indexed to the spot market.
A shift from term contracts for both gas and pipeline
capacity to spot transactions-in many cases in response
to gas and power industry deregulation-has left the West
much more exposed to spot market volatility. In other
areas of the country, utilities have significant firm
pipeline capacity extending from supply regions to the
citygate and/or have forward purchased gas (at previous
and lower prices) for at least some portion of their
winter supplies. As a result, unlike in eastern markets,
a much larger proportion of the supply portfolio of
California utilities will be exposed to the current
price spikes.

* No alternatives. A lack of fuel-switching capability
prevents a meaningful demand response to higher gas
prices. Power prices continue to move in lockstep with
the increase in gas prices. Not surprisingly, gas prices
pushed the cost of gas-fired generation beyond the
Federal Energy Regulatory Commission's (FERC's) proposed
price cap of $150 per megawatt-hour, setting the stage
for a reassessment of this price limit. A small and
declining portion of power generators are liquid fuel
capable. Significantly, air emissions restrictions-
already plaguing power markets with much higher
emissions credit costs this year-will make any further
switching to liquid fuels in the crucial California
market highly unlikely this winter. A recent meeting of
the South Coast Air Quality Management District, which
has jurisdiction over the Los Angeles area, concluded
with no relief granted to generators running short of
emissions credits.

Market Forces Unite for Price Spikes During November
The first cold weather-related demand spike demonstrated
the combined power of these forces and the vulnerability
of the western markets. A cold weather system in mid-
November brought temperatures averaging 47 percent
colder than normal-the temperatures actually averaged 14
percent colder than a normal January week-and provided
the additional demand boost that taxed the gas delivery
systems on the West Coast. Capacity constraints on
moving gas into California that appeared during the
summer extended north into the Pacific Northwest as
heating loads climbed. This core demand compounded the
effects of continued strong demand for gas for power
generation.

The high power demand was the result of the intersection
of the annual low point for hydroelectric generation and
a series of planned and unplanned nuclear and coal power
plant outages. Gas demand in the US West during the last
two weeks of November was boosted to approximately 15.5
Bcf per day, driven by heating demand increases of 2.8
Bcf per day above normal levels and power plant outage-
related demand increases of 1.0 Bcf per day.

These demand spikes caused buyers-already dependent on
the spot market-to bid citygate prices to record high
levels through the last two weeks of November and into
December. Since demand outstripped supply, prices rose
dramatically at all western price points, and flows of
natural gas to western markets increased over high
summer levels. Citygate prices surged beyond $40.00 per
MMBtu on daily spot markets and averaged nearly $15.00
per MMBtu for December bidweek at Topock. Daily spot gas
prices have reflected imbalance penalty prices in many
western market regions.

West Coast to Remain Disconnected Through the Winter
Although the week of November 13 could prove to be the
peak demand week in the West this winter, CERA does not
expect any significant retreat in gas prices on the West
Coast any time soon. Storage inventories are so low that
the ability to beat back demand spikes with high storage
withdrawals is not an option for gas utilities.
Generators, which already rely heavily on the spot
market for supplies, are faced with a bidding war for
scarce supplies. Colder-than-normal weather would likely
keep West Coast prices in the $20.00-$40.00 per MMBtu
range. More normal weather would allow a slow decline
from current levels of over $20.00 per MMBtu down into
the $15.00-$20.00 per MMBtu range. However, the storage
situation and underlying demand strength mean that any
return to a lower pricing range is unlikely until early
January.

This winter will prove a critical test for western gas
markets, and the end of the heating season will likely
provide the first opportunity for lower price levels in
the West Coast market. As heating loads diminish
significantly in March and storage deliverability is no
longer a critical issue, premiums should retreat back
into the $1.00-$2.00 per MMBtu range. As hydroelectric
generation begins to increase, the pressure could
subside even further, but storage injections during the
spring shoulder season will likely limit price declines
even during the spring.

The Unique Vulnerability of the Pacific Northwest
The West Coast price pressure is not limited to
California. High demand in the Pacific Northwest (and
more indirectly in California) will keep upward pressure
on prices from Sumas to Stanfield. Northwest pipeline
capacity from the Rockies was already fully utilized at
the onset of the cold weather and even so can only
provide gas so far into the Pacific Northwest. The
combined California and Pacific Northwest demand pushed
Stanfield up in spite of the limited volumes that are
bidirectional there. The only supply source for the load
centers in southern British Columbia and even more so in
northern Pacific Northwest (such as Seattle) are from
Westcoast at Sumas. The Westcoast mainline from the
producing fields in Northeast British Columbia has also
been operating at capacity. The same bidding forces felt
in California have been evident at these western
Canadian price points, pushing Sumas prices into the
$20s per MMBtu. These forces will persist, keeping Sumas
at a premium to AECO over the winter-and in much closer
relationship to California prices.

Customer Response:  Another Log on the Backlash Bonfire
With power plants and gas utilities paying the current
high spot prices, consumers' bills from Vancouver to San
Diego will ultimately reflect these high commodity
prices. The gas industry has been preparing for rate
shock this winter, warning regulators and customers
alike. However, the price spikes in the West and the
sustained premiums in western markets move beyond
alarming. Capacity holders are reaping significant
rewards for their investments in capacity positions,
resulting in a substantial transfer of wealth from
consumers to capacity holders. Market power and market
gaming accusations that have hit the power markets will
find easy application in their gas market counterpart
(no matter what their merits). Some level of
investigation into the natural gas markets during or
following this challenging winter should be expected. As
has occurred in the power markets, this will now turn
attention to gas purchasing practices, particularly in
California. The likely outcome of this process will be a
shift away from the heavy reliance on spot purchases
toward a more flexible portfolio approach.

**end**

Follow URL for PDF version of this Alert with associated graphics.

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