Energy Market Report
Thursday, January 3, 2002

*See attached pdf file.
__________________________________________________________
Western Pre-Scheduled Firm Electricity Prices($/MWh)
January 3, 2002 for January 4 and 5, 2002

Peak(Heavy)
                   Low      Change     High     Change
NW/N. Rockies     18.00     -4.00     19.50     -4.50
Mid-Columbia      18.00     -4.00     19.50     -4.50
COB               21.00     -2.50     24.25     -1.00
N. California     22.00     -4.00     26.50     -1.00
Midway/Sylmar       NA        NA        NA        NA
S. California     23.15     -3.35     25.00     -3.50
Mead              24.00     -2.75     24.75     -3.25
Palo Verde        22.75     -2.25     24.50     -3.00
Inland SW         22.75     -2.25     24.75     -3.25
4-Corners         21.50     -3.75     24.00     -2.50
Central Rockies   21.25     -0.75     24.50    -12.50
__________________________________________________________
Off-Peak(Light)
                   Low     Change     High      Change
NW/N. Rockies     17.00    -1.00     18.50      -1.00
Mid-Columbia      17.00    -1.00     18.50      -1.00
COB               16.00    -2.00     20.00       1.00
N. California     16.00    -3.50     21.00      -1.50
Midway/Sylmar       NA       NA        NA         NA
S. California     15.50    -4.00     19.25      -4.00
Mead              17.00    -2.00     19.50      -1.00
Palo Verde        15.25    -0.25     17.00      -2.00
Inland SW         15.25    -0.25     19.50      -1.00
4-Corners         15.50    -1.00     17.50      -0.50
Central Rockies   17.25    -1.00     22.50      -3.50
__________________________________________________________
Too Much Gas

Day-ahead peak power prices in the WSCC fell for the second session in a
row, largely on the reduced loads associated with a Friday/Saturday combo.
Several players believed that mild forecasts for much of the West and
abundant hydro supplies in the Northwest were also adding to the bearish
tenor of the marketplace.  "Prices were really bad [weak] today, and looking
at the weather forecasts, that's not going to change anytime soon," said one
marketer.  "Even with businesses and schools back in full swing next week,
the upside will be limited due to the mild weather, ample gas storage, and
abundant Northwest hydro power," he added.  Peak power prices began the day
weak, and continued to fall throughout the trading session.  Light load
goods were also on the decline, though not as significantly as peak hour
prices, in most cases, as overnight temperatures in many areas remained well
entrenched in heating demand territory.   NYMEX Henry Hub contracts were
lower midday on Thursday, then fell sharply following the release of yet
another bearish AGA inventory report.  February Hub gas shed an impressive
19.7 cents or eight percent to close at 2.268$/mmBtu, while March lost 18
cents to settle at 2.263$/mmBtu.  Thursday's AGA report showed a draw of 124
bcf in the U.S. last week, below most industry estimates that were calling
for a 140 to 150-bcf decline.  The same week saw a 209-bcf draw last year,
and an average drop of 147 bcf over the past five years.  Total U.S.
inventories of 2.856 tcf are 1.127 tcf above last year, and 615 bcf above
the five-year average.  Of the 124 bcf drawn last week, only 12 bcf were
removed from the Consuming Region West.  Western stocks stood at 82 percent
of full at 414 bcf, well above last year's level of 286 bcf.

Heavy load energy costs in the Northwest fell by an average of 4.25$/MWh for
the Friday/Saturday package, while light load goods only fell by 1$/MWh.
Lighter weekend loads and abundant hydropower were the most oft-cited
explanations for the falling dailies.  According to Weather Derivatives,
heating demand in the Northwest was only expected to average 84 percent of
normal through January 9, while the latest six-to-ten from the NWS was
predicting above-normal temperatures in the region's major load centers from
January 9 through 13.  "Given the amount of available hydropower and the
over-abundance of gas in storage, it will take some prolonged cold weather
to boost the day-ahead market, something that looks doubtful anytime soon,"
said one Northwest utility trader.  Flow forecasts for Chief Joseph remained
strong at 105 kcfs Friday, 75 kcfs Saturday, 60 kcfs Sunday, 110 kcfs
Monday, and 105 kcfs next Tuesday through Thursday.

As weaker gas prices took their toll on the highly dependent California
market, electricity prices for the Friday/Saturday package softened on
Thursday, despite more off-line megawatts than a day ago.  "The gas glut has
been a problem so far this winter, and now the plentiful rain in the north
is just adding more to the off-kilter supply dynamic.  The dailies came off
a lot late in the day, which I think will continue on Friday," commented one
Golden State guru, while another confined himself to saying, "The AGA was
not good."  Spot gas at the Southern California Border notched down another
few cents, transacting between 2.33 and 2.38$/mmBtu.  Heavy load goods at
NP15 saw action from 22 to 26.5$/MWh, with the bulk of deals done between
23.5 and 24.5$/MWh.  The light load product traded between 16 and 21$/MWh,
with the low end reached late.  In unit news, Morro Bay #3 (337 MW) was
operating at 185 MW on Thursday, while Alamitos #4 (320 MW) was derated to
100 MW.  Los Medanos (550 MW) upped its output to 150 MW.  Large gas-fired
Pittsburg #7 (682 MW) exited the grid for unplanned maintenance.  The
weather picture stayed steady (read: boring) on Thursday.  Mid-state load
centers expected highs in the mid-50s and lows in the mid-40s on Friday,
while Southern cities anticipated temperatures about 10 degrees warmer.
Little change was forecast through the first day of the new week, and the
latest six-to-ten called for continued above-normal temperatures from
January 9 to 13.

Despite some ongoing outages, day-ahead electricity prices in the Southwest
fell for the weekend combo.  Peak power at Palo Verde traded anywhere from
24.75$/MWh early, to 22.75$/MWh, and possibly lower, in late trade.  Most
players did not anticipate much strength in the days to come, as was
evidenced by balance-of-the-month contracts that were heard selling between
24 and 25$/MWh on Thursday.  In unit news, Cholla #4 (375 MW) was still
off-line with no available ETR as of this writing.  Coronado #1 (365 MW) was
expected to return on January 8, while Mohave #2 (790 MW) was sporting an
ETR of 14:00 MST on January 6, but players familiar with the unit said the
ETR has been getting pushed further back on a daily basis.  There were
reports that San Juan #1 (350 MW) was off line, but no confirmation was
obtainable.  The latest six-to-ten from the NWS was calling for above-normal
temperatures in Arizona and normal temperatures in New Mexico from January 9
through 13, while weather derivatives pegged heating demand in the desert
region at 90 percent of normal through January 13.


Patrick O'Neill and Jessie Norris
_________________________________________________________

Western Generating Unit Outages

Current                            Begins          Ends          Reason
CAISO units <250/6054 total          NA             NA
planned/unplanned*
Alamitos #3/320/gas               04-Dec-01         ?            planned
Big Creek Project/1020/hydro      09-Dec-01         ?         @752MW,
planned
Cholla #4/375/coal                01-Jan-02         ?           unplanned
Coronado #1/365/coal              22-Dec-01     08-Jan-02    main
transformer*
Etiwanda #3/320/gas               22-Dec-01         ?            planned
Etiwanda #4/320/gas               22-Dec-01         ?            planned
Grand Coulee #19/600/hydro        10-Dec-01       March          repairs
Helms PGP #2/407/hydro            01-Oct-01         ?            planned
Hyatt/Thermalito/933/hydro        02-Oct-01         ?      @607 MW,
unplanned
Los Medanos/550/gas               25-Dec-01         ?      @150 MW,
unplanned*
Mohave #2/790/coal                29-Dec-01     06-Jan-02        unplanned*
Moss Landing #7/739               29-Dec-01         ?            planned
Ormond Beach #1/725/gas           28-Dec-01         ?            planned
Ormond Beach #2/750/gas           05-Oct-01         ?      @350 MW,
unplanned
Pittsburg #6/317/gas              22-Nov-01         ?            planned
Pittsburg #7/682/gas              03-Jan-02         ?            unplanned*
Redondo #8/480/gas                09-Dec-01         ?            planned

For unit owners refer to pdf version.
*Indicates a change from previous EMR.
______________________________________________________________________

Eastern Markets Pre-Scheduled Firm Power Prices ($/MWh)

January 3, 2002 for January 4, 2002

Peak (Heavy) in $/MWh
                 Low     Change   High      Change
Into Cinergy    25.00     1.00    29.50     -1.00
Western PJM     26.95    -1.90    28.25     -2.75
Into Entergy    24.50     1.25    28.25      3.00
Into TVA        26.00     2.00    30.75      4.75
___________________________________________________________
As regional differences made their presence felt in the market, peak power
prices posted mixed results across the Eastern Interconnect on Thursday.
Propelled by a snowstorm and unseasonably cold temperatures, day-ahead
electricity prices strengthened at the southeastern hubs, while spot prices
at northern hubs weakened slightly, but still maintained Wednesday's robust
levels.  With warming in the extended forecast, traders were not optimistic
that prices would stay high into the new week.  On another down note, the
AGA listed last week's national draw at 124 bcf, below most industry
estimates.  Traders said they were expecting a draw of around 140, and were
hoping for a number closer to 160.  NYMEX Henry Hub natural gas futures
plunged on the news, with the front-month losing 19.7 cents to settle at
2.268$/mmBtu.  March shed 18 cents to close at 2.263$/mmBtu.

With the return of a key unit to the grid and a break in the below-normal
temperatures expected by Saturday at the latest, heavy load electricity
prices softened on Thursday.  Big nuke Salem #2 (1,106 MW) was back in
service on Thursday, along with approximately 1600 additional MW of power.
Western PJM goods changed hands between 26.95 and 28.25$/MWh, skidding down
almost 3$/MWh on the high and 2$/MWh on the low.  From a high of 55.83$/MWh
at 09:15 EST, LMPs declined steadily as the day progressed, averaging
22.59$/MWh through 15:00 EST.  Forecasts for Friday predicted highs in the
low-40s and overnight lows in the mid-20s across PJM.  Temperatures were
expected to remain within 3 degrees of normal through Sunday, and the latest
six-to-ten from the NWS called for mostly normal temperatures from January 9
to 13.

Amid forecasts calling for slightly warmer weather and rumors of a unit
outage, day-ahead energy costs fell in the Midwest on Thursday.  According
to Reuters, Illinois-based Cordova (537 MW) was off-line for much of
Thursday, but returned to the grid in the late afternoon, however, traders
were unable to confirm the outage.  Into Cinergy peak products were bought
and sold between 25 and 29.5$/MWh.  Daytime high temperatures were expected
in the 34 to 39 degree range in ECAR on Friday, with the corresponding lows
expected in the high-teens.  Lows were predicted to be well out of the teens
by Saturday, and the most current six-to-ten called for mostly normal
temperatures, with above-normal conditions at the northwestern edges of the
region, from January 9 to 13.

As very cold weather kept electricity demand high and despite much weaker
natural gas prices, peak power prices for Friday delivery firmed up in the
Southeast on Thursday.  Into Entergy deals were done between 24.5 and
28.25$/MWh, while Into TVA heavy load goods transacted from 26 to
30.75$/MWh.  The bulk of deals were heard above 29$/MWh.  Friday lows were
expected to drop into the frigid teens, while highs were expected to climb
into the upper-30s.  The latest six-to-ten called for below-normal
temperatures from January 9 to 13.
___________________________________________________________
California ISO Congestion Index in $/MWh

                         Path                 Peak   Off-peak
for 04-Jan-02         NW1 to NP15             0.31     0.00
                      NW3 to SP15             0.00     0.00
                      AZ3 to SP15             0.00     0.00
                      LC1 to SP15             0.00     0.00
                      SP15 to NP15            0.00     0.00


OTC Forward Peak Electricity Contracts in $/MWh

                    Mid-C              PV              SP-15
                Bid      Ask      Bid      Ask      Bid      Ask
BOM            21.00    22.50    23.50    24.50    25.00    26.00
February       19.00    20.50    23.50    24.50    24.00    25.00
March          16.50    18.00    22.50    23.50    23.50    24.50
April          16.50    18.00    22.00    23.00    22.50    23.50
Q2 '02         16.25    17.75    26.00    27.00    26.00    27.00
Q3 '02         30.25    31.75    40.50    41.50    39.00    40.00
Q4 '02         25.00    26.50    26.50    27.50    29.00    30.00
Q1 '03         26.00    27.50    26.00    27.00    28.00    29.00
Cal '03        26.00    27.50    31.50    32.50    33.00    34.00

Represents the most recent bid/ask spread obtainable
by the Energy Market Report.



Alberta Power Pool Index (C$/MWh)

                    Peak(14)   Peak(16)   Off-Peak    Flat     Change
for  02-Jan-02       44.89      44.08      21.77      37.31     9.29



BPA's Offer for 1/06/02 through 1/07/02.

Hours        Amount          NW delivered        COB/NOB delivered

1-6,23,24    100MW           Market Price*          Market Price*
7-22         100MW           Market Price*          Market Price*

*Market price will be determined at time of request.



NYMEX Henry Hub Gas Futures in $/mmBtu

                 Close        Change
        Feb      2.268        -0.197
        Mar      2.263        -0.180



Natural Gas Spot Prices in $/mmBtu

                  Low          High
Sumas             2.09         2.14
So. Cal Border    2.33         2.38
San Juan          2.15         2.20
__________________________________________________________

Economic Insight, Inc. - 3004 SW First, Portland, Oregon 97201,
Telephone (503) 222-2425, Internet e-mail emr@econ.com -
Copyright, Economic Insight, Inc. 2002.