Cal-ISO is a non-profit organization that controls
75% of the state's power grid.
During the winter from October through March, peak
statewide Cal-ISO (California Independent System Operator) controlled demand
is around 30-31,000 megawatts.
In the summer of June, July and August, the peak
ISO controlled demand has been 37-38,000 megawatts.
At peak, Cal-ISO controls 45,000 megawatts.
It is the second largest grid in the U.S. and the 5th largest in the world.
The ISO control areas exclude the LADWP control area
resources of 8,200 megawatts and others of 1,200 megawatts peak.
California only has 1800 megawatts on contract for
the Pacific Northwest for this summer, instead of the usual 3,000
to 5,000 megawatts.
The state has the capacity, with all plants operating,
to generate 55,000 megawatts, according to the L.A. Times. (The most
recent official database lists plants with a gross capacity of 54,175 megawatts
and an online capacity of 52,600 megawatts).
The April 16 editorial claims that the state could
fall short of this by 3,000 to 7,000 megawatts.
This will of course depend on the temperature and
conservation measures.
Forecasted Summer 2001 peak demand statewide ( 1 in 10 temperature
probability, + 7% reserve, in megawatts) is 61,000. This will be
met by existing resources of 45,000 ISO, plus LADWP of 8,200, plus others
of 1,200, plus 4,800 net imports including Pacific Northwest, minus average
expected outages of -3,000, plus new resources. The new resources
are 1,300 approved, 1,300 restarted thermal and renewable, 1,100 ISO peaking
facilities, and 1,000 emergency peaking facilities. (Why a 4,000
reserve? Source document no longer where I found it.)
On June 4, San Onofre's second reactor returned to full 1100 megawatt service.
The total of inoperative power is down to 7,200 megawatts, from earlier
days where 13,000 megawatts was unavailable. About half of the downtime
is planned, and half is unplanned.
About half of curtailed power is planned and half is unplanned outages.
(According to the Washington Post quoting state officials,
the summer load peaks at 50,000 megawatts, exceeding the states' maximum
generating capacity of 45,000 megawatts, with the rest coming from out
of state. These are consistent taking ISO control areas
alone, excluding LADWP and others.)
About one third of the potential energy in fuel emerges
as usable electrical energy. That is divided nationally into about
equal thirds in residential, commercial, and industrial uses.
The average home uses 700 to 1,000 kwh per month
(Edison).
PG&E serves 13 million people from 14,000 to
22,000 megawatts. It has 131,000 miles of electric lines, and 43,000 miles
of natural gas pipeline.
Offline power in 1999 was about 5,000 megawatts in
the winter (Feb.,M,A) and declined to 1,000 during the summer (J, J, A,
S).
Offline power in 2000 was about 3,000 megawatts in
the winter and 2,000 in the summer, but rose sharply in (O, N, D) to 8,000
to 10,000.
Offline power in 2001 has risen from 10,000 to 14,000
megawatts (J, F, M, A). (LA Times, May 12). The large offline amount
has coincided with the high price rises.
The North American Electric Reliability Council (NERC)
estimates up to 260 hours or blackouts this summer, whose average size
will be 2150 megawatts. (Reuters, May 15)
NERC estimates the shortages may be 4500 to 5500
megawatts, as opposed to the state's projection of 2000 to 4000 megawatts.
On June 7, the unavailable power dropped to a new
low of 4800 megawatts, about half planned and half unplanned.
Also on June 6, the highest cost of power on the
Automated Power Exchange (below) was only $70 per megawatt hour, with a
daily average of $58 per megawatt hour.
As of June 1, only 600 megawatts of qualifying facility
was out.
The Department of Water Resources purchases about 10,000 megawatts for
CA which are not covered by utility contracts, called "net short energy".
In their May 31 report, they give the future long-term average contract
prices in $/megawatt hours: May-Dec. 2001, $138; 2002, $106; 2003, $89;
2004, $75; 2005, $64; 2006, $61; 2007-2010; $60.
Compare to the acutal Jan.-April 2001 average of $284/megawatt hour.
Long term purchases cover about 65% in 2002, rising to 100% in 2004, and
declining to 70% n 2010.
Average annual capacity under contract for 2001-2010 is about 11,000 megawatts.
While the 2001 second quarter peak has 68% of net short purchased on the
spot market, that falls to 23% for third quarter peak.
Off peak, about 90% is bought on the spot market.
New 900 megawatt gas-fired generating plants cost $550 million. They
can be profitable if the natural gas costs only $5.50 per million BTU.
Nationally the price has dropped below $4 per million BTU.
Combined-cycle plants have a first generator driven by natural gas combustion.
The turbines pressurize and superheat incoming air before combustion, and
are driven by the burning fuel on the other side. The driven rotation then
drives an electric generator. The exhaust heat is used to convert
water to superheated steam, which runs a steam turbine connected to a second
generator (LA Times June 7, with diagram). The residual steam is cooled
in a cooling tower and recirculated.
These plant are 60% fuel efficient. 90% of new US generators will
be natural gas.
Sources of California's Electrical Generating Capacity