The state's utility companies have managed to co-opt the CPUC which allows them to do anything. PG&E rates have increased by more than 100% in the past 5 years and now they are going to implement a base fee for every customer regardless of usage.

These utilities are behind the NEM 3.0 effort to kill private solar generation in California (as the utilities have done in Nevada and Arizona). The utilities own the PUC and own governor Newsom.

Their anti-solar actions are being supported by the NRDC which shows how the good guys of the past are now the bad guys doing anything for a buck.

Charlie:

I've got info that might be helpful to you but it'll be a day/two before I can update it - stuff I've posted about before dealing with the value of array generation per installed STC kW as f(array orientation).

What the proposal outline you've included looks like will involve changing the 10 A.M. - 2 P.M. super off peak rate now in effect for T.O.U. rates for March and April only so that it's effective year-round.

In the meantime, it might be useful to remember that this notice is about a preliminary hearing, and for such things it's usually a long time before a change is in and when it takes effect (which usually happens). I've also noticed that the final form is usually quite different that what's been talked about - often not good, but usually not as bad as initially proposed.

I forgot and I'm too lazy to root around and find what your array orientations are. Can you post them back ?
If so, I can give you a pretty good first approximation of what such a change as is being considered in the T.O.U. timetable will mean for you in terms of lost revenue per year in units of ($ of lost system bill offset revenue/installed STC kW) using current DR-SES rates per the SDG & E rate sheets 36986 et seq. dated 01/01/2023.

Yes, that is exactly the proposed change but one should note that on weekends and the SDGE "holiday" days that 10 AM - 2 PM is already super off peak rated, so we are really talking about non March and April non holiday weekdays affected.

I actually went and put together my actual 2023 export to the grid that would have been affected if this change existed in 2023 - results below:

Proposed 2024 Change Effect.png


As noted in my initial post, with my NEM credit for this same timeframe being slightly more than a -$900 credit, I will be unaffected financially wise.

However, it does once again shows that as Time of Day rate adjustments and time of day periods are adjusted, one's financial benefit of solar can shift.

Having said all this, at least logically the proposed shift of these hours to super off peak does make sense as with the rise of solar adaption indeed these hours have shifted to a less electric company generation on sunny days. This is more palatable to me than the other current fixed month charge based on income level proposal also under consideration.

Orientation is shown below (I'm too lazy too as rather than go find the degree figure, easier to post the picture):



396688867_3644310355822741_5751427111003451550_n.jpg

As to calculating lost revenue, I am on TOU-2 (solar with car) and per initial post I've got actual revenue loss calculated for this year if the proposal was in effect. Note, that since I use some of that generation, the loss to the NET metering balance is less than the revenue generation credit.

It's still all good - for now, lol.

Charlie: Understood.

I'll probably get about the same $$ figure but in a slightly different format. I'll be interested to see how our #'s differ.

What's the roof pitch ?

Thank you.

J.P.M.

4 in 12

Thank you.

Charlie:

I started working on a number for lost NEM revenue per installed STC kW using PVWatts for our location and data before/if/after 10 A.M. to 2 P.M. super off peak SDG & E DR-SES proposed change(s) but had to go to my other home in La Quinta for few days.

Will be working on response for you and my Escondido neighbors this weekend.

Film @ 11 with the late new/sports/weather.

J.P.M.

Charlie:

Using my spreadsheets that calculate estimated annual revenue production (that is, potential bill offset), I estimate that your 8.68 STC kW system will generate $404.18 less revenue per year.
The possible (modeled) revenue per installed STC kW using the current tariff DR-SES is $757.17.
The possible (modeled) revenue per installed STC kW using the proposed tariff change with increased days of super off-peak rate between 10 A.M. and 2 P.M. year-round is $710.39 per installed STC kW.

So, approx. total annual lost revenue from the proposed change :

($757.17/yr.*installed STC kW - $710.39/yr. per installed STC kW) = $46.78/yr. reduction in revenue per installed STC kW.
The modeled system generation per installed STC kW = 1,729kWh/yr.
The modeled average value of a generated kWh using the current DR-SES tariff is therefore = (($757.39/(yr.*installed STC kW))/ (1,729 kWh/yr.*installed STC kW) = $0.43805/kWh.
The modeled average value of a generated kWh using the proposed rate change = $710.39/1,729 kWh = $0.41087/kWh.

Your array and mine are very close to the same orientation and maybe about 5 or 6 miles apart.
My 10 yr. average measured annual output per installed STC kW == (after 1st yr. burn in) 1,728 kWh/installed STC kW.

That's close to the modeled estimate that's based on the following:

1.) For this set of calcs/model for the value of generated array income I use the PVWatts model for my HOA location which, as I wrote, is about maybe 5 or 6 miles from your arrray mostly due south of your location.
The usual PVWatts caveats and model limitations apply.
2.) I estimated your array's orientation at 20 deg. tilt and 210 deg. azimuth. The orientations that spreadsheet has are from 90 to 270 deg. azimuth in 10 deg. increments and 20, 30 and 40 deg. tilts. Other orientations can be added as needed but that covers most of the applications in my HOA.
3.) SDG & E tariff schedule DR-SES is used for the rates and times of use for those rates per current CPUC sheet # 36986 - E, et seq.
Other tariff schedules can easily be added to the spreadsheet.
4.) "Revenue" is considered as the retail value of a kWh when it is used either to offset a kWh that's not imported or a kWh exported at retail value and credited for future use.
5.) Because excess generation is not compensated for at retail rates, this method is only useful for systems whose annual output is less than or equal to the annual electrical load.
However, one of the advantages of this method is that it does a good job of showing just how much the average value of a generated kWh will drop for a rather small excess generating capacity, which is another way of saying that oversizing kills system cost effectiveness quite quickly.
6.) No adjustment is made for NBC revenue reductions kWh of export revenue as it's impossible to know a priori what the reduction for those charges will amount to as each kWh of system generation may be used on site or exported.
7.) For better or worse, I adjusted the PVWatts loss parameter used in the model so that the model's output matches my array's 10 year average output just about dead nuts. That system loss parameter worked out to 9.3 % after a 3.5% reduction in annual output for late afternoon shade or a total loss parameter of 12.8%. The PVWatts modeled output also matches the SAM output, and also agrees within a fraction of a % with a model I created many years ago that is similar to SAM but does other things as well.
8.) I believe this is a useful tool for system sizing and analysis provided you keep in mind that it is still a model - particularly given the uncertainties in any model based primarily on weather data uncertainties but also other values to a lesser extent.
If actual data is available - as you have - that actual data is always better that modeled data.

A note: This method does not consider the effect(s) that any storage may have on the value of the electricity that the system generates.
Until I figue out a better method, what I've done to consider that question is to treat any storage as an add-on to the rest of the system and consider the storage, its cost and economic impact separate from the rest of the system.
Briefly, but a little more complicated, I consider any system generated electricity that goes into and comes out of storage to have an extra value applicable to the economic analysis of the storage alone that's equal to the difference in the value of when that stored electricity is withdrawn from storage and its value when put into storage. So, if a kWh gets taken out of storage and used when rates are on peak (at, say, $0.80097/kWh) but went in at a super off peak time (at, say, 11 A.M. under proposed new rules when the super off-peak rate = $0.36263/kWh), the storage system has produced a gain of ($0.80097-$0.36263) = $0.43834 for each kWh that makes the trip into and out of storage. That (summed) gain is then used in the economic analysis and decision making as the whether or not storage shold be incorporated into the system design or added to an existing system.
The practical problem there is that since energy will be going into and out of storage at varying rates and times, some way(s) need to be formulated to assign when and so the value(s)for a kWh(s) that the storage system manipulates that makes the trip into and out of storage as well as how that will affect any NBCs.
I'm working on that just now, but until I figure out a way to do it that makes some sense, is workable and understandable, I treat all the energy coming out of storage as doing so at on-peak rates and going into storage at the hourly time averaged rate calculated for when the sun is up without the on-peak rate figured in.

Thanks!

I'm a bit surprised why under a DR-SES tariff there is any difference as I thought that's a non time of day tariff.

Charlie:

DR-SES is the T.O.U. default tariff SDG & E will put most residential customers on when they get a PV system. It is indeed a schedule whose rates are time and day dependent.

Google: "SDG & E + Effective rates and tariffs" and see the sub-heading : Schedule "DR-SES..."

The differences I calc'd are an estimate of annual value of $$ revenue of PV production lost per installed STC kW for your system at its location, size and approximate array orientation (and also the change in the average value of a generated kWh on an annual basis) to offset a bill as a result of changing the 10 A.M. to 2 P.M. times of super off-peak rate from their current March and April weekday (M-F) period only to year round (365 days) using the rates currently in effect for the DR-SES schedule.

The values do not include any NBC as those charges are applied to what is sent back to the POCO and so are impossible to estimate with any accuracy on an annual (or any for that matter basis) unless either all (or none as I've assumed here) of the kWh generated are assumed to be sent to the grid.

As an aside, there are a couple of ways to game the super off-peak rate game SDG & E is suggesting to perhaps favor residential customers who use a lot of A/C, but the methods involve a lot of insulation and (probably) the addition of a lot of thermal mass so that a lot of (pre) cooling of the dwelling (and/or its thermal mass) at those lower (and earlier) rates is done with the result of lower A/C use costs (but probably a bit higher A/C usage), something like one of the principles of passive solar heating/cooling /thermal tempering dwelling design that takes advantage of a high(er) dwelling thermal time constant.
Think of it as sort of like A/C time shifting, but I doubt most folks would find it practical or understandable.