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Posted by T. Keating on July 20, 2008, 8:23 am
 
On Sat, 19 Jul 2008 19:01:06 -0400, "daestrom"


No.. During the peak of the day.. the Energy Co had to generate 1.2
kWh for every 1 kWh sold.    Not so for the locally bought and sold
kWh.


Again there is the extra  0.2 kWh the utility didn't have to generate
to produce the same 1kWH delivered revenue to the paying customer.

Meanwhile the PV owner will consume energy during nighttime & cloudy
days when grid and I^2R losses are minimal.  One can never count the
energy that would have been consumed by the PV owner as lost revenue.


With local generation the "normal" usage is reduced..
   Thus the equipment lasts longer.

snip.. the rest..

Posted by daestrom on July 20, 2008, 4:49 pm
 
T. Keating wrote:

<snip>

So, before they billed for 1 kWh and had to pay for 1.2 kWh of energy
produced along with the maintenance of equipment (and make a modest profit).

For locally bought and sold they bill for 0 kWh (actually, they bill
customer 'A' for 1 kWh that they use, but they must pay customer 'B' for 1
kWh that they produced, net zero).  They don't have to pay for generating
any kWh (0.0 used), but they still have to pay for maintenance of equipment.

Want to explain how they do that?


So during the night, the utility has two 'normal' customers and revenue.
But during the day they have effectively zero billable kWh (all revenue
collected from customer 'A' gets credited to customer B's account).

Total billable kWh have dropped and maintenance costs haven't.  Don't you
see this as a problem??  The amortized costs of maintenance must now be
distributed over fewer billable kWh so they must raise the rate.  The
non-producers are subsidizing the maintenance costs to the local producer
that never pays a utility bill.


Not enough of a difference to matter.  Trees still grow the same amount
under the lines, poles still need replacing just as often.  About the only
thing that 'lasts longer' would be some equipment that is running near rated
capacity now.

daestrom


Posted by T. Keating on July 20, 2008, 7:26 pm
 On Sun, 20 Jul 2008 12:49:46 -0400, "daestrom"


Incorrest assumption.. .
   Assumes B provides all of A's demand...
   An unlikely outcome..

If A needed extra daytime energy from Grid..  Energy co would need to
produce 1.2x kWh.   But if B produce 1.0 kWh, then Energy Co would
have not needed to produce that extra 1.2 kWh, and energy losses
occuring in the transformer & grid would be slightly lower for all of
Energy Co's customers.    I.E. Energy Co more efficient with lighter
net demand.


Peakers while not that expensive to build, are very costly operate
(higher Maint per kWh, fuelcost, and lower  efficiency).  Peaking
periods are likely to result in a net LOSS for the Energy co anyway.
(Given average pricing for semi fixed rate billing.)  

I.E. Energy Co is likely to have a higher profit @ night & mornings,
and loose money, or just breakeven @ daytime peak.)

Any extra point of use, daytime peaking capacity is always going to
help the Energy co bottom line big time.



As pointed out in another subthread..

That said, my utility (FPL) currently uses a two tiered residential
rate tariff.  

First 1000kWh/month is priced at 9.35 cents per kWh (pretax)
  Above 1000kWh/month is priced at 11.38 cents per kWh (pretax).

So the  FPL, pays me for net PV production at the cheaper less than
1000kWh/month rate, while charging my energy hog neighbors a much
higher(ober 1000kWh/month) rate (3/4th's of the time).   Resulting in
a extra 16 to 17 percent profit margin.  Tack on reduction in energy
delivery losses and we're talking  about a  30 to 40% profit margin.
(Which is wayy more than PUC would ever allow in a non-renewable
scenario. )

Tacking  on annual wholesale net metering tariff just adds to Energy
co's gravy train.  (even higher profit margin.)  

snip..

Posted by daestrom on July 22, 2008, 1:25 am
 T. Keating wrote:

<snip>

Only during 'peak' production.  Not that unlikely at all.  Assume B's system
is sized to zero out B's monthly bill.  For that to be the case, it's
production during sunny hours *must* be more than B's consumption during
those same hours.  And is quite possibly double that amount (i.e. equal to
B's and A's consumption during sunny hours).


And for every kWh that B produces, the Energy Co losses all the revenue that
said kWh would have created.  Total billable kWh is lower, maintenance costs
must be amortized over fewer billable kWh.


Energy Co does *not* 'breakeven @ daytime peak'.  Not even close.  Look at
wholesale rates for electric during a 'daytime peak'.  On a hot day rates
can run above $20/MW-hr (or much higher depending on the spot market).
That is more than the *retail* revenue they can get for that energy.  While
some consumers pay TOU, the residential setup we've been talking about
typically doesn't.

Energy Co can only afford to provide expensive power during peaks because it
has a higher profit on 'off-peak' power.  But the average for the entire
month is what the PUC looks at.


Shave all the peaks off for the energy company and their short term profits
will rise.  Until the fuel-adjustment charges kick-in and start going
negative because the rate-base fuel estimate ends up higher than the actual
fuel costs with no peakers running.

Such a 'windfall' wouldn't even last one billing cycle.

Yet the total billable kWh is going down and the maintenance costs are not.
The fuel costs are lower (thanks to no peakers), but that ends up being
returned in fuel-adjustments.


As pointed out by *me* in this thread!


If such operations are allowed on a truly wide scale, as soon as the total
fuel costs for the month end up being much lower since the electric co isn't
running peakers, the fuel-adjustment charge gives the 'profit' back to the
rate-payers.  Despite your opinion, the PUC and utility aren't idiots about
this.  The utility recognized a long time ago that variations in fuel costs
would put them at risk, so the PUC lets them work with an average fuel
charge and fuel adjustments.  But the formulas work both ways and a
particularly 'easy' month (low total fuel costs) means it gets adjusted the
other way.  A long term trend and the 'allowable average fuel charge' is
reduced.

Bottom line is, the utility makes a fixed rate of return on total revenues.
Reduce the total revenues and the fixed rate remains the same but the
absolute value of profits are reduced.

There are good reasons why the *utility* doesn't want more than a few
percent net-metering.  And it certainly isn't because net-metering a lot of
customers makes *more* money for the utility.

daestrom
P.S.  And what about the fact that PV peak production does *not* coincide
with peak electric usage in many areas??


Posted by Mauried on July 22, 2008, 1:52 am
 On Mon, 21 Jul 2008 21:25:56 -0400, "daestrom"


The bottom line is that there are 2 components required for the
selling of electrcity.
1/ You have to have some electricity to sell.
2/You have to provide some method of transporting the electricity to
the buyer.

If you dont provide the 2nd , and use the infrastructure of someone
else, then you have to pay for your use of that infrastructure.

Current net metering regimes , ignore the 2nd component and just
assume the grid is there and you can use it for free to sell your
power, but someone has to wear the costs of maintaining that
infrastructure.

If you take Net metering to its absolute conclusion where everyone is
feeding into the grid, the power company would have no customers to
sell power too, but would still have the costs of maintaing the grid
to meet.
It just doesnt work.



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