It's true that all does not seem to be as it should re pricing patterns- ie I heard that after lower wholesale price caps were implemented, the off peak night rates went up to compensate for the lower daily peak.
If cost of producing power increased to 15 cents per kwh, then why is the cost to the e-retailers via calpx 30cents? A 50% gross margin is typical for IPPs?
Sure- they have overhead, and may have built in a risk premium based on the dysfunctional PUC arrangement, but these higher prices are having impacts outside CA.
I listened to the ATI conf call, a specialty steel producer that has operations in Oregon. I think I heard it said that part of the OR power requirements were subject to pricing based on the day rate at the OR/CA border, currently $180+ per MWh. For this reason, their profitibility was impacted, and they planned installation of cogen facilities to reduce reliance on outside power sources. Even with this, based on higher NatGas, they expect the run rate of energy expense for that facility to double after the cogen is operating, over what they paid in 1999.
So, we have a NatGas pricing increase ripple that seems to be aggravated by a demand increase and possibly expanding gross margin demands by IPPs.
That demand increase seems most suspect to me, as I don't see power demand as a non-continous type of curve. Demand should ramp in predictable manner, barring weather related blips.
Am I supposed to believe someone woke up 9 months ago and decided they needed 30% more power from that point on? Or is there a non-linear response to marginal increase in demand? Seems like the latter- based on the traditional high cost of peaking power.
One benefit from the macro perspective, as has already been pointed out, is the more efficient use of power, and thought put on the problem of managing peak demand, ie the powering down of the water pumps for the LA basin water works. That should be considered for implementation as standard practice, IMO. |
