-: All right.
Welcome back folks.
We are at our next panel
on DR ERS energy efficiency
products and providers starting off with Reliant.
-: Good afternoon.
I'm Derek Mauzy with Reliant Energy
and wanted to talk a little bit about what we're doing
and what we've found about our experiences,
what works and what doesn't.
So we've got a couple of times of DR that we execute.
We've got device DR in our cases specifically thermostats.
Where we can control that smart thermostat.
I send a signal and reduce the air conditioning usage
for some period of time.
It is very effective but it is limited to customers
who have that kind of device
and the customer do have the option and of course,
want to retain that option to override it.
And they can always walk over to the thermostat
and turn it back down to a lower setting
if it's summertime, if they wish.
The other kind we use it as we call it behavioral DR.
It's where we send out an email a day before
and give the customer and incentive to
shift or reduce their usage for some time the next day.
This one depends on the customers proactively taking action
and it can be used by a wider range of customers.
So with the thermostat DR,
you've got to have the right kind of thermostat
with this behavioral DR you could do anything.
You could you could shift your laundry to later in the day,
you could decide that you're going to go over
and raise your thermostat yourself.
You could shift some other things that you're going to do
to another time.
This kind of of behavioral DR
from kind of the rep's perspective,
it does benefit from times of high market prices.
That is we see that load reduction and we get that benefit.
But this kind of Dr is not really eligible
for the TDU programs or ERS
because it's not dispatchable in a short period of time.
With either kind of this,
we've seen the participating customers
give us load reductions of around 20 to 25% of their load
or around 1KW per customer in in the summertime.
And with the thermostat DR,
that means you're gonna get
a very high percentage of customers who do that.
With the behavioral DR,
again, the customer has to take the action.
So there's somewhat lower participation in that.
Some people will just kind of ignore the email or say,
today's not the right time for me,
but others will do it.
An the, like, kind of on the flip side,
some things that we've found are not as effective,
at least in our market with regard to
shifting load is detailed time of use rates.
Many markets have kind of a low medium high
kind of pricing for time of use.
What we have seen is that customers
see that high price and they back off.
I was watching a focus group
where we showed a time that you saw option to some folks.
And I saw a peak price of 30 cents a kilowatt hour.
And they're like,
"Ooh, I'm gonna have to think about that."
Well, if you're trying to enroll somebody and they say,
"Ooh, I gotta think about that,"
you know that you haven't made a sale.
So in our market where the goal is you,
you give the customer something that they're interested in,
time of use has not been a particularly successful tool
at least the kind of traditional time of use rates.
And really critical piece pricing where you have something,
we've seen those in California and several other places
where at times of critical peak,
the price goes over a dollar, a kilowatt hour,
those have not been well received by customers here.
I thought I would show you a little bit about how
the smart thermostat DR works.
So this is an average of the participating customers
in an event we had in 2020.
So the load on here on the left axis, the KW,
is actually just the air conditioning load ,
is not the entire house load.
The entire house load will probably
be closer to four or five KW at peak.
But what you see is we started this event
at three o'clock in the afternoon, 15:00,
pretty strong drop-off.
And then as the event went on, the drop-off decreased a bit,
but it was still a solid reduction
throughout that period of time we control the thermostat.
When the event ends and the thermostats are kind of
allowed to go back to their original set point,
then you see a kind of a kick up in usage
as the house works to cool itself down.
The other thing I just wanted to point out was
the bottom chart shows kind of the participants
interval by interval during that event.
So we started off with 96% of customers
were participating in this event, the other 4%,
there was probably a internet connection
or something like that,
just a communication problem with the thermostat.
And then as the event wore on,
we had people dropping out,
but somebody would walk over
and change the thermostat back
to a more comfortable setting.
So main point here is that thermostat DR
can't really be used forever.
It's a limited duration.
It works very well, but for a limited period of time.
So in this admittedly crude drawing
wanted to just kind of show kind of overlay
that load reduction with some illustrative market prices.
So in that kind of green scenario,
if you had wholesale prices that were kind of low
and then went fairly high for say a couple of hours,
and then came back down,
that lends itself very well to to this kind of DR event.
This is the kind of situation where
the market signal and the available resource
kind of lines up pretty well.
What is not as effective for incentivizing DR
is if the high price last for a really long time
because at the end of the event,
we're gonna start using more power again.
Well, okay, that you've just shifted power
from a high price interval to another high price interval.
So that's just one of the considerations
that goes into kind of the market structure
or what incentivizes REP behavior
or any DR Manufacturer's behavior.
McAdams: What is that magic amount of time?
In terms of your focus groups,
in terms of your practical experience,
where do you see the most effect
of price responsiveness,
and then when does it start tailing off?
Derek: So it seems to us that it starts tailing off
around two hours into the end of the event.
And in my experience,
if you try to carry on thermostat DR event
more than four hours,
you're really not getting anything in that last part.
And it's not necessarily just that consumers
are going to turn down the thermostat.
They could leave the thermostat at the higher setting,
but if it's hot outside and the temperature
in the house gets up,
then the air conditioner is gonna kick on again.
It may not run at quite as high a load factor
if you've got the thermostat set higher,
but eventually that air conditioner is gonna run.
Peter: Which of these price curves is the most indicative
of our current market,
or is it just circumstances dependent?
Derek: In the in the summertime,
the green one is reasonably close.
-: Okay, so that's pretty good.
Current market structure and performance
shows a price signal that correlates well
with effective DR.
Derek: Yes.
-: Okay.
Derek: I will say that kind of before ORDC came along,
that what you saw was extremely spiky prices
that were very hard to predict.
And they might last for only 15 minutes
or something like that,
or maybe they lasted four for 30,
but still it was a quick up and down.
And if you had not an advanced kind of predicted
exactly when that was gonna happen-
-: Presumably, effective DR would have an impact
on the price.
Derek: Yeah.
-: Hopefully.
Derek: Yes, it should.
The amount of DR on the system right now,
or at least of I'll say residential DR,
is not enough that it has made a huge difference
in where prices go, but it could down the road.
-: So if you can go back to that prior slide real quick
in orange, your statement about stretching high prices
over several hours is not useful for most DR,
is we're looking at market design changes
in this forum and especially specifically ORDC,
and there's been a lot of stakeholder comments
that have recommended stretching out the curve
and lowering the price curve,
but essentially producing more hours of higher prices.
How does that coincide with your statement?
-: So if that happens,
it does not help the economics
of implementing a residential DR.
Or what would tend to happen then is that
it would only make sense for someone who's got
a resource that only lasts two or three hours,
they would have to wait until halfway through
what they think is the high price period,
and try to catch the tail end of it.
Because what's happening is that we aren't completely
eliminating load,
we're really shifting it to a later time.
You're saying, okay, I'll let the house get hotter now,
but I'm gonna to want it cooler later.
And so
what a DR executer wants to do is
I wanna lower the load when prices are high
and let it go up when prices are low.
If prices stay high for a really long time,
then there's not that market price,
it's not a useful market price signal for us.
Peter: When you also, I mean,
the DR doesn't exist in a vacuum, right?
Like it should be competing with other resources.
So even a elongated flattened ORDC,
would just mean that it's competing
with different resources, different heat rights sooner,
right?
-: Yeah.
Presumably what you would expect would be
that generation resources or other resources
that can run for a longer period of time
would definitely try to catch the front end
of that high price period for DR.
If we caught the front end of that price period
it just doesn't give us an economic benefit.
Peter: So I guess it's, I mean,
we wanna bring resources with the ORDC you're talking about
hypothetically we'd would wanna bring more resources
sooner rather than waiting for such a small reserve margin.
And this is one of those resources that can compete
with, and that could change depending on price of gas,
for example, right now would be those heat rates
are changing we would be very different
than they were two years ago,
compared to a product like this.
I think we want this to be another market resource
and its economics could change,
but what we wanna be agnostic to those resources,
we just want,
I think we want the market to be able
to provide the most efficient resource sooner,
I guess, sooner, rather than later.
-: And then I get that.
And so I guess it sounds like it could get difficult
for residential Dr because you're gonna come on
and you're only going to be able to produce
for up to two hours.
So if you come on and you prevent a reliability risk
or event, but what if it continues to occur
when were in an emergency then residential VR
that's responding in this way will not be available
because they can only be part of this curve for two hours.
-: Well, I think it will be available just a little bit
later a little bit higher price.
-: They may respond to you.
Derek: Maybe just another way to state it as that,
if you think of the market prices as being a signal
as to when you need to take action,
a market price thing though the last eight hours
I'm being maybe a little extreme
I don't think anyone is talking about stretching out
that long, but a market signal the last a long time
is something that a resource
that can only last for three hours
is gonna have to kind of figure out how to work with them.
And I've been,
it probably wouldn't make as much sense
for residential DR To try to catch the front end of that
eight hour period.
It would make more sense for the residential DR
To try to catch the later part of that eight hour period.
-: But if the event happens more often,
that's really where Dr makes its money.
If you're talking about price signals
that reoccur and more often at the efficiency of the market,
and that is kind of what energy only was predicated upon.
I mean, is that everything is subject to price signals.
Behavior is influenced by price signals.
Does that add to your ability as a rep
to sort of negotiate around that with these new
and unique offerings?
Derek: With with regard to the energy only market
and price signals,
I guess when the energy only market didn't have ORDC,
the price signals were unfortunately unpredictable.
You would have some of those really high price times,
but it was hard to tell when they were gonna occur
and you had to be extremely good at guessing
that in order to actually make money or even breakeven
at something like residential DR
By using the ORDC to give them a market
to tie that signal to available reserves,
I think the market did a really good job
of combining reliability signal
with a price signal.
And that I think has enhanced the ability
of something like residential DR
or any kind of resource that can come on
for some period of time,
but it doesn't have like unlimited capabilities.
It makes it much more viable for those kinds of resources
to participate in the market.
To your point about products that we can offer
and can develop,
that's an interesting point that I think
one of the great strengths of the competitive market
is that the companies involved are always working
to find value propositions that appeal to consumers,
and that produce at least some kind of return
for that company.
And so while some structures will work better
than others for us,
I do think that kind of whatever structure
you end up coming up with in terms of how market prices
are gonna work REPs undoubtedly find ways
to look at that and say, okay,
well, how can we work within that framework
to provide value to our customers?
Peter: Okay, keep going.
-: So I think this is my last one.
A few things that that we've thought of that could help
expand DR,
making participation in the program simple
and through a trusted resource that is reachable
for questions and concerns.
When the conservation event happened
that they got a lot of publicity earlier this year,
it was a program that the REPs were not involved with.
Customers are used to coming to the REP
as that's who I deal with for power and electricity.
And we were kind of scrambling because,
well, that wasn't us, we didn't do that to your thermostat.
So that kind of creates some confusion in the market.
Reliant does in fact have a program
as I've been describing where we can control the thermostat.
For a company like Reliant
because we are very concerned with retaining customers
and not just acquiring them in the first place,
we are pretty careful about making sure that people
who enroll in this program
understand what they're enrolling at.
We don't actually like bundle our thermostat DR program
in with some other offer.
It's okay, here's our program,
if you enroll, you get this benefit.
And so people understand what they're getting into.
All right.
So enough on that one.
We think that incentives that could help reduce
the customer's cost of smart thermostats
or other devices what would help.
And perhaps that could happen through
some of the energy efficiency dollars ECRF
that was being discussed earlier
as a way of subsidizing
or somehow reducing the cost of the thermostat.
And if you do that through an REP program,
then it is something that you can clearly kind of tie
the results to the fact that you spent these dollars.
So work it through an REP program that is designed
to improve reliability.
And then final thing is as an administrative hurdle
that we sort of observed is that in the TDU programs
and ERS, we have participated in both of those in the past.
They are pretty inflexible when it comes to
adding new customers or taking out existing customers.
So in other words when we have to kind of set a few months
in advance, this is the list of customers
who are gonna be participating in this program.
REPs are continually gaining customers
and honestly losing them as well.
But the customers leave for various reasons.
We would like to be able to, okay, well,
we've lost some of these customers,
but we've added a new one since then.
We'd like some flexibility there.
So far, that's not really...
that's been something that has been lacking
that would make it a little bit easier for us to participate
in some of those some of those programs.
So I think that's all I had.
Peter: Thank you.
Quick to your incentive question and broader question,
isn't the incentive to the REP to the DR Program
to be able to provide the next marginal megawatt
through demand response
rather than a very expensive megawatt
in the real-time market?
Derek: Yes.
I guess to be clear,
there are two main sources of value that we see,
and that is one of them.
The other one is that if we participate in ERS,
so we could aggregate our customers and put them in ERS
or in a TDU program,
you can't do both the cause that would be double counting,
but you could do one or the other.
So you can get a benefit from,
a dollar benefit from the TDSB let's say for participating.
And you get the incremental cost benefit
that you were describing of replacing a high cost
supply dollar with a low cost supply dollar later on.
Peter: Sure.
So I will get some second part of my question,
if customers can override this at any time
and they can override it over the longer the event goes on,
as we saw on one of your graphs,
then how can you provide reliable
demand response to the ERCOT,
whether in the form of ERS or whatever future
kind of ancillary service?
Well, we heard earlier that you can,
these programs are eligible for ancillary services, right?
But I mean, if they can override,
if customers can override it,
they can reduce participation.
How can you guarantee that demand response
is there from a reliability perspective?
Derek: So once you get to there is
kind of the law of averages thing of
since we're aggregating a large group of customers
we can gain that experience of all right,
over this period of time, over four hours,
we'll have on average 70% of the customers.
So we will commit to providing an amount
that's equal to 70% of the-
-: We learned about averages in June and expectations.
And that's a dangerous game.
Derek: I guess the key is that,
with experience on on implementing the demand response,
what we've seen is under the right temperature conditions,
which are basically summertime temperature conditions.
We see a pretty consistent KW of reduction per customer.
And yes, again, some customers will drop out in that,
but our experience has been
that it's been pretty consistent.
Lori: So I think you touched on a point earlier,
and also, I think I've engagement with your company.
I've heard a little bit about your support for aggregation
to participate in ERS and more residential DR TDU programs,
et cetera.
But one challenge is that, especially as a big rep,
you have a lot of customers coming and going,
even within that aggregation.
So would you rely on historical averages as well
to try to, I mean, cause you as a rep,
you're gaining and losing customers.
And if you're going to proffer in aggregation
to participate in ERs, for example,
that aggregation customer irrigation number can change.
So how do you mitigate against that risk?
-: Yeah, it's a case where we...
It's actually not dissimilar
to how we go about buying supply.
We understand that when we sign up 1000 customers
that at some period of time later we'll have 950 customers
or 900 customers.
And so it would be similar here.
We understand that at the beginning of the summer,
we've got a thousand at the end of the summer,
we might have 900.
And so what we will do is we will bid into ERS
something that's at that minimum level.
We wouldn't say,
"Oh, we're gonna have a thousand the whole summer."
'Cause we wouldn't expect that.
Peter: Is there anything preventing your company
from expanding this effort and expanding this program
right now, other than just customer engagement,
preferences, et cetera?
Is there anything that we need to do
on this side of the table?
The incentives noted and admit the administrative,
that seems like a very marginal change.
Is there anything structural we need to do?
Or is there anything on our side and the PUC side,
the market side, preventing this program from expanding,
however broadly your customers and price signals
would want?
-: I wouldn't say there's anything preventing it.
I think that through incentives we could make it go faster.
McAdams: So you don't think $50 million
is an impediment right now on ERS.
'Cause that's a hard cap.
-: It is a hard cap.
And I would say that if that, if ERS is,
if the $50 million is raised,
that I would love to see that incremental part be dedicated,
allocated towards residential DR.
Peter: Yeah, but I mean, at the same time,
if that's of your sources,
one of your two sources of value,
like I said, skydiving on averages don't work
when it comes to reliability and scarcity events
hoping that 65% of my DR thermostat show up.
It does not put their car control room in a reliable spot
and does not put Texas in her reliable spot.
But at the same time,
you get 100% of the customers who show up in real time.
So there may be a business argument
for passing by the ERS 50 million,
because you don't know how big the benefit is in real time.
It could be bigger than whatever your cost is
or opportunity cost is on the 50 million on ERS.
And you get to count 100% of the people
that are actually doing it that day, right?
100% of the people that participate in the program that day.
Derek: We would get the market price benefit
of 100% of the people that participate that day,
that's right.
I guess I just, I would just reiterate
that we have seen that that reduction amount
is pretty consistent.
So in other words, again,
I wouldn't bid 100% into ERS,
I would bid 70% into ERS because I have seen
consistently that we get that 70% benefit.
-: One more question from a REP point of view,
ancillary service charges and costs.
How does that factor into your demand response,
calculus and programs?
How does that work in today's market design for you?
Derek: So there are some ancillary service concepts
had been discussed that would basically require
in order for residential DR to participate
would require real-time telemetry
at the individual customer level.
So at every resource.
So and that kind of, that idea of telemetry
real-time telemetry signals being sent to caught
it's just not really not really viable.
So I would agree with Mr omens point earlier that ERS,
weather sensor ERS is the best vehicle right now.
There have been ideas floated around
of how ancillary service structures could be changed
and there may still be some idea that someone
comes up with that that would work better,
but at this point I'm doing residential DR
or some sort of a residential aggregation
in an ancillary service doesn't really work
just because of the telemetry requirements
that would be needed.
-: What about future products?
Again and you're speaking to it from the carrot side,
but on the stick side if,
if there were more ancillary services imposed on the market,
which we're having to take a bit of out of
market action these days right now to stabilize
the system and operate it in a more conservative approach,
if more of those or different ancillary services
were imposed in the future to meet
various performance metrics for the operator
to better reliably administer the system
but DR was included as a offset measure
that would obviously incent heavy participation
in an a DR program, I would assume.
Derek: Yes, it would.
-: Okay.
-: All right, thank you, sir.
Welcome to step on the panel and answer follow-up questions
if you are with the other members.
I think next up is Oncor or so.
-: Good afternoon chairman, Commissioners,
I'm Liz Jones,
vice president of regulatory affairs for Oncor.
I am here specifically to talk with you
about the Oncor residential demand response program,
but through the morning you pose several questions
that you deferred for TDUs
and I can speak to at least some of those, if you wish.
Yes?
Peter: Sure.
-: Okay.
Peter: If you want to handle it
at the end of your presentation, that's fine as well.
Liz: Okay.
So Commissioner Cobos,
you in particular were concerned about realizing
the value of distribution resources
during a load shed event
and wanted to address that because it is something
that we have struggled with for over a decade at ERCOT.
And the problem is much like our discussion
a month ago or so about critical load,
distributed resources are sprinkled throughout
our distribution feeders,
and we account for them in the sense of recognizing
what the net load is on a particular feeder.
So let's say, we had a feeder that had one megawatt,
and had in turn or three megawatts,
and it turns out there was a one megawatt
distributed generator that was active.
That feeder would look to us for load shed purposes
like it had two megawatts of load.
So we can manage shallow load shed events,
say 500 megawatts rather than 20,000 megawatts
in a way that can maximize
the value of the distributed generation.
But we can't necessarily do that in every short event.
And the tagline on that is
distributed generation resources,
which Canon Gilman spoke about this morning,
those are able to offer ancillary services
and are in turn required to be on theaters
that will not be shed.
And so there is a category of distributed generation
that can be protected from load shed.
And that is an option that is available
to distributed generators.
It costs more because you're essentially reserving
your own feeder, but it also provides greater reliability.
I would urge you not to
immediately exclude distributed generation
based on hurricane, sorry,
not hurricane Winter Storm Uri.
Because I think if you were to do so,
you would also decline benefits that they offer
during other times when we don't actually get
to from load shed.
The second issue is
the notion of weatherization and whether TDU programs
should engage in more weatherization
and less demand response.
One of the obligations that each of us has
and Lark spoke to it earlier
is our programs must be demonstrably cost-effective
and weatherization presents a tremendous benefit
to the individual customer,
but it is extremely expensive relative to the number
of KW or KWH that are saved.
And so while the low income and hard to reach programs
are principally focused on that,
we do not have broader weatherization programs
and that's the principle reason why.
Finally there is an argument that demand response
is not real energy efficiency, and I respect that argument,
but I will tell you that,
it is relatively low cost.
So we aren't engaged in helping folks buy
new air conditioners or heat pumps
or any of the other kinds of appliances
for lighting or refrigeration.
So we are not making as large a capital expenditure
of our energy efficiency dollars.
So in fact, while we do have to spend them year after year,
if it's demand response, and we would only spend them once,
if it was real energy efficiency,
I think you have to balance what you expect
from the programs.
And once you do,
we will develop the programs that you want us to.
Because TDU energy efficiency since its inception incentive
bill seven has been designed to bridge if you will,
the current state of events and equipment
to some future market state where the 12 sear
air conditioner is common so we're gonna go to 14.
The 14 becomes common, so we're gonna go to 16.
There are all sorts of ways in that vein
that the energy efficiency programs are continuing
to move forward and push the envelope.
So and then the last piece, and I'm sorry,
I can't remember who asked the question originally,
if we did demand response right,
would we need to have a TDU program?
Maybe not.
And that's certainly been a healthy topic of conversation
with your staff.
The issue is that for customers who see average pricing,
and there are a lot of them in the residential
and commercial sectors,
the sort of cost-based price-based programs
that we talk about in the market
don't have any effect on those retail customers.
And so you have to think about another way
of trying to reach them.
And this is the mechanism
that is least in impartial use right now.
Peter: Thank you, Liz.
-: So I have...
my initial slider is full of things
that you've already heard from everyone else
with the exception that ERCOT TDUs presently
can offer our DR
only through our energy efficiency programs.
And we, the TDUs are not allowed to provide
energy efficiency dollars directly to customers.
We must review and sponsor programs that the vendors offer.
And then we pay the vendors
and the vendors have a contract with the customer.
And in some cases that's visible to us,
but that's not within our control.
We've talked earlier today about the summer peak period
as the demand response window for TDU programs.
I think Lark's correct when she says
we could do that as a winter program.
I don't think it takes into account year round occasions,
and it may be worth thinking about year round occasions,
because some of the short supply events that have occurred
across my time here have been in April or October
and not in February or August.
The other question that you all have wrestled with
is at what point do you want to deploy demand response?
Because right now the TDU programs are designed
to be implemented in a EEA2
so short affirm load shed, but not by much.
I think Derek said it well when he said you know,
DR has a shelf life,
particularly when all these customers can override it.
And so the more often you call on it,
I believe the less effective it will turn out to be
particularly at the residential level.
And so I think you need to balance that.
And I think that is a limitation
in the way residential demand response works
relative to large commercial and industrial.
Costco condemn it's lights all day long,
houses need air conditioning back at some point.
The other piece is
we actually do test sometime during May and June
to make sure that the bid in for these TDU programs
are accurate and justified.
And so I will tell you that this year's test
occurred on June 17th and we had 40.7,
this is Oncor only,
we had 40.7 megawatts in the residential,
and we actually had a total of 103.2 megawatts
in the commercial.
But because of the program design,
the commercial was limited to 78.1.
So we paid for 78.1 and we got 103.
So we could talk about irrespective of who is offering
the residential demand response program,
the number and type of devices that are available in a home
to be controlled is fairly limited.
I mean, the conventional wisdom
is you got AC/ heat pump, water heater if it's electric,
pool pump.
And that's pretty much all the bang for the buck
that you can get in a single house.
There's also a question of how much
we should aggregate or dis-aggregate
residential demand response,
because of course any one house is not valuable,
but 10,000 houses is a lot.
We have talked at ERCOT and I expect we will continue
to talk here.
Canon mentioned it that depending on what kind of service
residential demand response is used for
it either is very important that we're very specific
about what settlement node
those customers reside are electrically connected to,
for others, if there's an overall reduction
in energy demand,
we're grateful for it for wherever it comes.
Average pricing on residential plans.
Again,
the retailer or the third-party provider
sees a lot of upside or downside from the wholesale price.
The residential customer typically does not.
And in fact, you all are engaged in a rulemaking
that is expressly designed to limit that exposure, right?
So that makes a difference.
The other piece is, I'm sorry.
Peter: Well, you've mentioned that several times
and especially after recent legislation
a lot like the legislature and as a result of
our rulemaking is designed to limit,
very specifically limit individual residential customers,
exposures to variable rates, right?
So if you've mentioned this several times as a challenge
to getting customer,
to helping that customer feel the incentive of demand,
that would prompt demand response.
How would you suggest we address that in the fact pattern
that we cannot move away from average pricing
or we will not be implementing variable pricing
on residential homes?
Liz: Well, to the extent that we're talking
about market based programs for residential demand response,
you can't use the stick of price exposure.
So you're gonna have to use the carrot,
which is how much money are we as market construct
prepared to pay to individual residential customers
for changing their behavior.
-: Or is there enough sticking carrot at the REP level that,
I mean, like Mr Mauzy said,
there's nothing preventing them other than price signals
from expanding this program and customer intent, right?
I mean, there's a lot of stick in a lot of care
at the REP level.
Liz: Well, and to the extent that average retail prices
were wholesale prices were consistently higher
as they are in, for instance, California,
I think that the demand response economic equation
would change meaningfully.
I can't speak to what it is or is not here,
but I suspect it is a lot less, most days,
most parts of the year
-: Let's hope so.
Mr. Barnes at one point said that reps
in many ways are financial risk providers,
the risk and reward of all the tools that their disposal,
including demand response resides
at the retail electric provider.
And that benefits the customer,
the individual household in many ways is
in that household is not exposed to the risk
of variable rates,
but at the same time, they don't reap the rewards
like they do, as a retail electric provider would.
Liz: Well, you and Brad Jones have spoken throughout
these past months about the value of conservation
and conservation is an unpaid demand response.
And I frankly think there is,
sort of back to your behavioral program modification.
I think there's a lot of opportunity there
that isn't about changing hand.
-: When you say it's unpaid, unpaid to who?
If Derek's able to get conserve
through smart thermostats and he doesn't have to go out
and buy a $1,500 megawatt, that's a huge benefit.
That's whole a whole point.
That's a big value driver of the program, right?
Liz: And when I say- -: That a tremendous payment.
-: No, that's right.
I'm talking about unpaid to the retail customer.
So I, in my home have a programmable thermostat
and I use it aggressively to manage my energy,
but I'm not part of Austin Energy's RDR.
I mean,
that's something that I would prefer to exercise
personal control over and I suspect that that is true
of many customers,
particularly having undertaken an advanced meter
deployment customers are very uncomfortable
with having external control in their homes.
Peter: Understandably.
But I hear this a lot and this is not you,
but that residential customers
don't get paid for conserving.
And I wanna make sure that folks understand
and correct me if I'm wrong,
but they're electric providers get paid a lot
for incentivizing them through time of day or rebates
or whatever mechanism I mean,
but there's substantial rewards for conservation
in the current market construct.
That's just allocated to the retail electric provider
who then chooses how to allocate that reward to the customer
on a company by company basis.
And that reward under our current framework
is only allocated that hill provider
'cause they're also taking on the risk.
Is that fair?
Liz: Yes.
And it doesn't even need to be a rep.
It can be a third party competitive service provider.
-: Okay.
So, I mean, there is payment for conservation.
Liz: There is.
And so if within the market construct,
even the TDU program,
we write checks to REPs or competitive service providers
for their participation in this program
and they demonstrate that they can perform in this program.
But as people talk about a way to incent greater number
or kind of residential demand response,
I guess what I'm is the current model doesn't assume
that the economic benefit is necessarily flowing directly
to that residential customer.
It is instead one step up the food chain
Peter: And I suspect we'll hear from some
very clever REPs in our next panel
about how they're competing to deliver
those rewards to customers.
-: That's right.
So I've listed a couple other things
that customers can override of a signal.
They can sign up for multiple programs
and then they can also sign up for a benefit
and then opt out of the obligation.
We again,
the paradigm is to offer a lot of control
for these residential customers.
And then finally we have device automation
and customer awareness.
And Derek spoke to the test that happened to occur
that it wasn't a TDU test and it wasn't a REP test
and it freaked a lot of people out.
And some of 'em called the news station
or talked to the journalist.
The next page, I have talked about a couple of things,
the limitation to summer peak periods
and the system wide nature of the TDU programs.
Those are potential areas for refinement
in order to expand the RDR usage throughout the year.
The next to last bullet on the page
is the most significant and probably the most obvious
given what we've already talked about.
And that is the TDU residential demand response programs
are unlikely to fully fund the program opportunities
that exist in ERCOT.
And so depending on your objectives for load management,
we probably need to talk about a layered or tiered approach
that specifies in some detail,
what are your expectations for a short term
two hour turnaround versus every day from three to five,
for instance.
And the other thing that we would note,
and we're not wed to this concept,
but we wanted to go ahead and identify for you is
it may be that a direct TDU program
could be more beneficial to the extent that the customers
trust the TDU and are more familiar with the TDU.
We're not interested in being a market participant,
but we are interested in helping
if you all believe that would be beneficial.
Peter: All right.
Thank you, Ma'am.
Liz: The last page is the punchline.
The first issue is customer value.
The customers have to find value in the program
whether that's qualitative or quantitative or economic
market impact.
I mean, we don't wanna diminish the fact that
demand response programs in size and scope
can have an impact on wholesale market prices.
And in the past couple years
we've had a healthy discussion about whether
that kind of price impact should be reflected in the ORDC
and power balance from the curve.
All the other market mechanisms you here.
We feel very strongly about real time deliverability,
and I'm sure you all do as well.
And Derek talked about,
I'm not sure I can get 100% so therefore I'm gonna
discount the available amount by what I think
I can actually deliver.
That's perfect.
I will tell you that historically,
the Commission has been extremely aggressive against
large load resources who underperform
or don't perform at all consistent with their obligations.
The penalties are significantly less for ERS
and the TDU programs.
And in fact, there's no penalty in the TDU program,
they just don't get paid.
McAdams: Is that why you don't count it in emergencies?
I mean, as per the winter event,
you have 300 all in the ERCOT system
and we didn't count that.
That wasn't a realized in your load shed numbers
or anything like that.
Because it's not controllable?
Liz: Well, so the TDU did not have a program in February.
No TDU had a program in February.
Ours are summer only which is a fair topic, right?
But that's why-
McAdams: But if we were to go to winter,
I mean, that would be one of those instances
where someone would override their switch.
(Peter laughing)
I'm freezing to death, I'm turning on.
Peter: Averages per pants might not apply in that case.
McAdams: Maybe.
Liz: And there's also a notion
that it doesn't necessarily get turned off,
it gets adjusted by four degrees or six degrees
or something so that somebody who had it said at 75
might be looking at 69.
And that's a little bit of a different issue.
Accountability and compliance.
I mean, it's part of that same exercise.
And there have been some discussions
a little bit today from Cyrus and certainly other days
about what can the advancement meters do here.
And the situation is we cannot provide real time data,
but we can verify on a next day basis
what the consumption was at a particular household.
And then finally coordination of programs.
Lori: So, Liz,
I wanna ask you a couple of clarifying questions.
As you noted,
we know the TDU load management programs
are limited to the summer,
and I just wanna clarify,
so you're saying if we wanted to extend the benefits
of those programs into the winter,
we'd wanna do it through a residential DR program
effort, or can we modify the TDU load management program
to cover summer and winter?
Liz: I think you have the existing authority
to modify it.
And I think the TDU would certainly respond
to some direction from you on that point.
I think the winter program would be different
because we would be talking more about heat pumps
and electric resistance heating
and less about the conventional pattern of AC
'cause almost everybody uses electric AC
and depending on the area,
there can be a pretty sharp divide
between gas fire heating and electric heating.
Lori: The other question that I ask Canon
and I'll ask you is,
is there an opportunity that we can gain
more reliability benefits by moving the use of TDU
load management programs from EEA2 to EEA1 or earlier?
Liz: So I'm gonna go back to the how often
do you wanna use it?
What is the customer tolerance for the use?
How invasive is it to their daily lives?
And I think that is a different answer
for commercial versus residential.
I think there's probably more tolerance
in our commercial management programs.
The other thing that I will say is in my experience
and not necessarily a predictor of the future,
there has been a hesitation to call an alert,
to call an EEA1 to call an EEA2.
I mean, all of those,
although they are permitted under both the Commission rules
and the NERC reliability standards,
there is an obvious stigma associated with them.
And so if you are thinking about moving them,
I think it's important to understand that is doing
for the customers in the system
relative to the risk that they face.
I am not taking issue at all with the desire
to take a step back from the physical scarcity as the driver
of how we deploy programs.
But I do think that it's going to have to be
well understood in order for the market
to work around those signals.
So if you wanna have a price signal before you have
a physical scarcity signal, that's fine.
We just all need to understand what that is
and know when it's coming.
Lori: So you talking about tier TDU load
management programs,
I think SB3 has some language in there about allowing
the TDU to design and operate a TDU load management program
for non residential customers.
McAdams: It's not allowing, it's a shall.
Lori: Yeah, shall allow, sorry.
Missed a word in my reading.
Shall allow,
so is that what you're talking about when you mean tiered
with respect to residential and CNI,
'cause we're gonna have to put this in role I believe.
It's an SB3 it's a pretty direct that's not this
in our rule, thought it wouldn't be in legislation.
Liz: So that's an area of concern I would say
among the TDUs in the sense of it's not clear whether
this other SB3 sanction commercial load management
would be integrated into energy efficiency
or whether it would be independent from energy efficiency.
It's just simply not clear there.
And additionally,
there's a desire to make sure that we are responsive
to the legislature and the tools that they have given us.
But we have not previously designed off peak
in terms of the year commercial load management programs.
And I think all of us have an interest in
making sure that we understand
what would be most effective programmatically.
So we're all signed up,
we're just not sure where to start
and would appreciate your direction.
McAdams: Well, on this one,
a constraining factor is we can't advance this program.
I mean, we can't pull that out and advance it ahead of EEA,
it's at EEA2 statutorily.
Yes, so I mean,
that's a last resort break the glass plan
on your part or program.
Liz: Yes.
Lori: So that's what I was sort of thinking
and maybe tiered is not the right word.
Maybe it's phased because if you have
this CNI TDU load management program or whatever
it ends up being as part of this legislation
that's has to be implemented in EEA2,
then perhaps the other aspect of the program
being used in EEA1, you have sort of
two buckets of customers you can call on
in an emergency as opposed to calling on them all at once.
At an EEA2, you can go EEA1, EEA2,
and have reliability benefits from both.
Liz: I think that's certainly an option.
The other thing is that it may be
that for residential programs,
which we think have a finite tolerance
on the part of the customers,
that we have different tranches
of residential demand response,
such that if we're an event,
I won't label it,
but if we are in a condition in which
we want to call on demand response,
maybe we make it available in a way
that is hours, one through two,
then hours three and four, then hours five and six,
so that you have a longer caution
than what Derek was describing is ordinarily the case.
-: Yeah.
I'll just add that that there are definitely
residential demand response programs
that cycle through groups of customers
as a way of spreading the reduction
over a longer period of time,
the reduction is gonna be shallow,
'cause you're doing only a few customers at a time,
but you can,
that is a solution if you're looking for a longer span.
-: Yeah, good point.
Well thank you Liz.
And while CPS comes up for the next presentation,
Canon can gimme a, just a quick data point.
We've talked a lot about EEA1, EEA2, EEA3,
exactly how many megawatts are between moving
from EEA1 to 2 and EEA3,
the most severe emergency level is load shed
which we always wanna avoid.
It's I think it starts at 2,700 and moves down to...
Yeah, go ahead.
Canon: So the difference between EEA 1 and EEA2,
it's not a necessarily absolute
quantity of reserves anymore.
It is a frequency based,
but there are also reserve references.
-: What are the reserve reference points?
Canon: So as I recall it's the watches start at 3,200,
I think EEA1 is that 23,
and then EEA2 1750.
-: 1750, and then EEA3 is?
Canon: EEA3 is not really defined at that point
by a quantity of reserves.
There is a no trigger in EEA3, it's based on reserves.
-: So it's for me like based on reserves EEA1,
EEA2 is about 500, 450.
Canon: That's correct.
-: 450 megawatts, which we have is one unit tripping?
Very easily.
That's one unit tripping in one moment at a time.
And then next step from there is load shed,
turning out the lights.
Canon: That is correct.
-: Okay.
And this is a broader, thank you.
It's a broader reference point.
We've referenced EEA1 and 2 a lot.
And I think it's important for the general public
to know how fast that can go is a very steep slope.
Canon: And the only other thing I would add
is there is an additional move from
one to two that could be driven by frequency issues.
So that's the other reference point
that the operators would -
-: The point being like, when you said,
in case of emergency brake glass,
this can happen so fast you don't have time
to grab the hammer to break the glass.
And so I think the broader point in our new direction
from legislature is don't even get close.
Liz: The other thing I would note
is that those values have changed over time
and are not mandated by any external standard.
And so the way you calibrate and how many megawatts
differentiate a watch from an emergency condition
is I think within your discretion and ERCOT discretion.
-: Very good point is something we need to-
-: Yeah, just for clarification.
So an EEA standard is NERC required,
but the numbers that are baked into the EEA thresholds
are ISO set.
Is that accurate?
Liz: Yes.
-: But,
and this will come up in later conversation,
but EEA1 was certainly it,
I think because it ties in with the minimum contingency
level of the ORDC was set in 2014 June 30th,
something like that.
So Canon, if you wanna talk about that now,
but bottom line is everything's predicated
on that 2300 number.
I mean the whole band starts playing let's.
-: Let's keep this moving.
We'll keep the presentation moving, but thank you Canon.
But the point is it's a very steep slope.
-: Yes, sir.
-: Once things start going wrong,
they can go wrong very quickly
and we get,
doesn't take long to be a fatal problem.
Mr. Luna, thank you for joining.
-: Thank you.
Commissioners good afternoon.
My name is Rick Luna.
I'm director of technology and product innovation
for CPS Energy.
And certainly appreciate the opportunity
to tell you about our demand response programs at CPS.
And so let me start by telling you
that our demand response program
is part of our energy efficiency program.
We started this back in 2009 after our board
and our city council approved the creation
of what we call the safer for tomorrow energy plan.
So under step we had a goal man reduction goal
of 771 megawatts,
and we also had a funding stream that was approved
that we recover from our customers
through our fuel adjustment.
And and so we set the target.
We put in place the incentives and the funding for that.
And we launched a variety of program offerings
for our customers.
We've now achieved the goal of that plan.
We achieved it a year early
and actually under budget and have continued those programs
with approval from our city council.
And so we continue to offer this today.
If we go to the next slide.
I should mention that we started down path
in part of course energy efficiency was important to us
conservation but also community value
and the desire in the community to reduce
our reliance on fossil generation,
as well as develop programs that would support
our customers and help save energy and save money,
which they tell us is a big priority.
So we've developed a roster of programs.
This is everything that we fund in our step programs
to the tune of about 70 million a year.
So weatherization in low income homes,
residential, commercial energy efficiency programs,
we have solar rebate programs that we offer
and most recently electric vehicle charging incentives
that we've created.
Of course,
I'm here to talk about the demand response program,
and we've got a variety of flavor of programs
that we offer.
And what we've done here is break this down
just to be able to speak to the different types of programs
that we offer.
Maybe I'll start on the right, the far right,
actually, as I look at this now because historically,
that's where we started was with our large commercial
and industrial customers who were interested
in having incentives and had the ability to reduce
load with with some instructions in advance.
We've grown that program over time.
We've got about 110 megawatts of load
that's committed to us every summer.
And we've got pretty much all of our large school districts,
all of our universities manufacturing cement plants
and so forth.
They're available to us for reductions in anywhere
from 30 minutes to two hours,
depending on the option of program that they choose.
And we pay them a rebate for reducing load
and being available to reduce load
on those peak days when we call on them.
In the middle is our third thermostat programs.
So we've got 150,000 devices and customer homes.
About half of those,
we installed through partnership with Honeywell,
where we were going out and installing one way
paging thermostats with the evolution
to wifi connected smart devices.
We began and to do more of a model
where the customer purchases the device,
and then we offer them an incentive to enroll
in our DR program.
of course,
customer and it's been talked about customer always
has the option to opt out of any single event.
But we find that opt outs are low
or they're acceptable levels.
And of course customers can also leave the program.
So they get an upfront incentive of $85 for enrolling.
And then if they stay with the program every year,
we give them an additional $30 that we pay out
in October or November.
And we do that every year.
So that program's worked well for us.
And then the last one is behavioral.
This is the newest program.
So we've got about a 15% adoption rate on thermostats.
And so we were looking for
how do we reach the 85% of customers?
And so we partnered up with Oracle
and launched a behavioral DR Program
where we sent peak day alert two customers,
320,000 customers.
These are customers that they did not enroll in the program.
We send them a notification to say,
Hey you're gonna get these alerts from us.
We deliver them the phone call or email.
And they have the right to opt out
and not receive the messages
but otherwise we're gonna send them
any time that we forecast a conservation day
for the next day, we will initiate those call-outs.
And we also support that with awareness
through social media.
We have digital billboards that we can change
on a daily basis.
And we also have a partnerships with the news stations
to run the promos for the program
during the weather portion of the news.
Critical to this is, of course, this is informational.
We're not paying the customer to do this.
So we're simply asking them to conserve.
So include some tips for them on how to trim energy use
but really the key piece of this is we give them feedback
after we call for it.
So if we call for it tomorrow,
the following day or the day after,
they'll get another phone call at our email
with a ranking of how they performed
relative to similar homes.
And what we find is absolutely what drives the engagement
is the ranking sort of triggers a competitive aspect.
So we have measurable savings from this program.
We have smart meters in all of these customers,
so we measure the impact
and we get about 30 megawatts through this program.
If we go to the next one.
So our perspective on demand response, again,
we've been doing this for a long time.
We think it's a valuable tool,
we think it's an active tool that can be used
to support greater reliability.
It helps us manage our native peak load.
It helps reduce our exposure to high prices
and the real time market.
And so it's actively used,
I'll get into some statistics on that in a minute.
But that's critical because we want customers to anticipate
and to know that most likely on 100 degree day,
you're gonna get a call from us.
And once we build sort of that behavior
and then that anticipation customers generally
go along with it.
And we don't get a lot of resistance
or pushback from customers.
And so we have seen customers willing to participate
for the right incentive.
Of course we've gotta build in flexibility.
So even though I showed you three categories of programs,
I mean, there sub categories under each of the categories
to try to meet a customer need.
And that's that point about,
you gotta have multiple paths to be able to participate.
To the point that was made earlier,
DR performance is consistent.
We've had over 200 events we've done
MNV on every one of them.
We know it's consistent,
we know it's reliable within a certain bandwidth.
Of course it's not always 100%
but it depends by the program.
But for the most part,
we have seen it to be very consistent.
And it's a case of diversity is our friend, right?
You've got 150,000 thermostats on any given day.
Some percentage of them will not be available,
but we know that going in.
And so we can accurately forecast.
Given the temperature on a given day,
we know what we have available to in our portfolio.
To the point about back to back DR events,
we have run up to 10 consecutive days of events
in some August back in time.
And we have found that customers will stick with us.
There is a little bit of a drop off.
We do complaints, we do get phone calls,
but the vast majority of customers will stay with us
and will not drop off the program.
So partly I think that's the incentive,
the effect of the $30 incentive.
And part of it is the community messaging we put around this
doing your part helping the community
that seems to really resonate with customers.
So DR in action, this is for summer of 2020,
we had 19 event days.
Again, the point I made was that we call this actively
and we think about it every day and whether
it should be a DR day or not.
And of course that's weather dependent.
We've had seasons where we've had as few as 10 or 11 events
and some years we've had up to 30.
So it's just gonna depend.
And our average duration for an event
is about two and a half hours.
That varies a little bit by program.
And again, we've got different groups of customers,
so we don't call all of it
for the exact two and a half hours.
We will stagger some of the programs behave differently.
So we know residential has a lot of impact
right out of the gate.
So we'll tend to call that a little later.
Whereas maybe our commercial programs
are more solid for a longer duration,
so we can stretch those a little more.
And so we evaluate that when we dispatch.
We dispatch if we forecast a CP day,
we will dispatch the programs for of that.
And then there, you can see our performance.
So across all of the programs about 270 megawatts last year
again, we don't call everything at the same time.
So the second number we provide you is a day
where was the CP's peak, and then you can see there,
we had that 231 megawatts of impact.
So my last slide is just to talk a little bit
about winter storm.
Of course that was that was a unique challenge
for our DR Programs.
We of course have been summer focused
like every other DR program.
so we were challenged with what could we contribute
through our thermostat fleet.
And so we worked with the thermostat vendors,
and we were able to get out a a signal
to electric customers who had electric heat.
And so about 93% of our thermostats
were able to be dispatched with a two degree differential.
Of course the impact isn't anywhere near
as you get with air conditioning.
But it did have some incremental value for us.
And then on top of that,
we had some of our large customers
who had backup generators,
who voluntarily agreed to curtail.
And an important point to here is
of course that was for 100 hours continuous time.
Our typical DR Summer is 60 hours across four months.
And so it was a whole different situation
than anything we'd encountered before.
-: So just to drill down, this is a great object lesson,
and you went through it.
So in terms of what you were able to negotiate
with those customers in February,
basically you were trying to squeeze an extra two degrees
out of their homes.
Is that kind of what they... -: Correct.
What we did, and you see the screen there,
actually that's my thermostat at home ,
is we notified customers that we were
in an energy saving and we used two degrees
as our benchmark.
And so if the customer had electric heat,
then that differential was beneficial.
And we saw customers did participate
and did stay with us.
Now you had the challenge of they might lose power.
And so you the home got really cold.
And so it was definitely a unique situation.
And we've MEVed the event.
I think we have a lot to learn still,
but on the fly, we were able to pull it off.
McAdams: Great.
-: Okay, that was my last slide.
Peter: Thank you, Mr. Luna,
any other questions or comments for him?
All right.
Appreciate you being here.
Next up is in Enchanted Rock.
(laughing)
We'll stick around for you.
-: Okay, I appreciate that.
-: My name is Corey Amthor.
I'm the president of Enchanted Rock.
-: Speak into the microphone, of course.
-: Okay, sorry.
My name's Corey Amthor, president of Enchanted Rock.
Appreciate the time to talk today.
Thought I'd give you guys just,
if you wanna go to the next slide,
just a little base of what we do.
We provide resiliency microgrids to commercial
and industrial customers.
We do that through using natural gas generators,
and a lot of our customers are what I'd call
critical customers to the population,
grocery stores hospitals, senior living facilities,
universities, others.
And what we do different than most backup
generation companies is we continue to maintain
the ownership and operate the generators.
And then we parallel with the grid whenever
the grid's available and provides services back to the grid.
So when the grid's not available,
we're providing backup service to the customer,
when it is available,
then we're providing services back to the grid.
And what that does is,
that's what we call a dual purpose microgrid.
And the benefit of the revenue streams from the grid
helps subsidize the cost for the end use customer
to get cheaper backup generation or discount,
reliability power for them.
And it's been a big help for a lot of our customers,
I believe.
I wanted to spend a few minutes talking about
the winter storm,
and then just the hurricane that went in through
just a few days ago.
And I think one of the things that we've spent
a lot of time talking about over
the last five, six months is about how the winter storm
and rolling blackouts affected critical loads.
But I just wanna, and I know most of you already know this,
but just wanna keep it up front and with everyone that,
most of the blackouts that happen
are most of the outages that happen on the grid
are not due to rolling blackouts.
It's due to the storms burbs flying into transformers,
different things like that.
And so,
we provide a service during the storm Winter Storm Uri
but also during the hurricane,
and have had we had 465 out outage hours at 42 site
and providing them great resiliency.
I think it's important that our units provide
a great service to the grid,
but it's also important for those revenue streams
to continue to let critical loads,
install backup generation.
If they don't do that, then,
we'll just talk about critical loads and providing them
circuits that protect them during rolling blackouts.
That does nothing for them the rest of the time
when they're having outages.
McAdams: Wait,
can I ask you a question on the hurricane Nicholas?
-: Yeah.
McAdams: Does that mean that at 42 sites
where you have backup generation,
there were 465 hours that you all supplied-
-: Correct.
McAdams: That would have been grid supplied,
if not for the hurricane,
-: It should have been grid supplied,
but there was no grid available.
McAdams: That's right, okay.
So you all came on and did your job 99.7% of the time
at those 42 sites?
-: Correct.
McAdams: Can you come to my house?
(laughing)
Corey: So yeah, if you wanna go to the next page.
One of the things is right now we're settlement
only distributed generation providing those services.
And in that we can pro provide ERS and participate in that,
but in the future,
what we'd like to be able to look at also
is participating as a distributed generation resource.
And right now that's under moratorium where you can apply,
but it looks like that's gonna open up in January,
February of next year.
But part of that,
that I think is important when that happens
is that we need to look at distributed generation
different than the big combined cycle turbines
or turbines.
We have 200 sites,
over 200 sites with about 450 megawatts of generation.
So the distribution of that and the diversification of that
is much more resilient and reliable
than just one generator at one site.
But if we're not allowed to aggregate those facilities
in to a larger facility,
into an aggregation the operating plans
operating as a generation resource,
there would be a ton of information that we have to pass
back and forth on an individual side basis
that I don't think is really necessary for ERCOT to have
on a hour to hour basis,
we can aggregate all that and give them the information.
And like our customers like to have many times
as they want a button to push,
but they don't wanna see what happens in the background.
We can provide that to ERCOT too.
And I think that's important.
The other component is that,
with a large portfolio of generation,
I'm not sure we need to worry about having circuits
that are, you know, right now to be a DGR,
you have to have a non curtailable circuit
to a transmission grid, but do we really need that?
I don't think so because you're gonna have such
a large array of generations spread out
across the distribution grid all across Texas,
that if it's a service that is bought on a bulk basis,
not by a specific point basis,
like ancillary services are,
then that distribution,
even if there is some sort of outage on a certain circuit
shouldn't affect the overall portfolio
and should be allowed for the operator
or the queasy to manage that.
McAdams: Mr. Amthor,
may I ask you a technical question about Enchanted Rock?
So does your system,
are you telemetric dispatched?
Can you be?
Corey: Yes.
McAdams: So you fit that profile in terms of
grid operators need.
Corey: We're working with ERCOT now and that, yeah.
McAdams: Okay.
So you're, you're working through the details of that,
or you have been dispatch-
-: We have a 24/7 knock that we dispatch
all of our assets from that knock.
And we have the ability to take the telemetry,
all the measurements from that and send that
and share that with ERCOT on a real time basis
or a TDSP all those things.
And we're fine doing that.
-: Now, if we have a regional event maybe not Uri,
but something significant to where it impacts
the greater Houston area, or north Texas,
say an ice event.
And again, it knocks out of your 450 megawatts,
a lot of that because Oncor has to start rolling outage.
We are in out rolling outages at that point.
And when we're counting on you as an ancillary service,
and you're advocating to be modeled
on this aggregated basis,
how do you explain our reliability concern in that scenario?
-: Well, there's a couple things with that.
First, because the number sites,
that gives us enough sites across the whole state
that you're gonna be already distributed pretty well
And keep you at a fairly high level.
And then as you go into rolling blackouts
in a specific area, that's even gonna be less.
So, I mean, I think-
-: So you're saying you wouldn't bid your entire-
Corey: We would never bid our entire,
we prepare for that.
I think it's important to remember that the blackouts
that we had during this storm
where we were dropping 20,000 megawatts of load,
if we try to design everything in the system
preparing for that,
that is going to eliminate a lot of opportunities
for things that we could do with the grid to prevent us
from ever getting there again.
So if we just worry about that and say nothing else matters,
then we'll take a lot of resources
that are dispatchable like ours and maybe not get
the true use out of them.
And I think what we're trying to do
is to prevent ourselves from ever getting back there again.
And so we don't wanna take the chance of
not using assets that are out there that can perform
and provide services to the grid.
-: So I guess what you're saying
is that day to day reliability,
these microgrid systems can provide reliability benefits,
like you said,
to prevent us from getting into those emergency events.
So if you do have,
what I believe you're saying is geographic diversity
of your microgrids,
that if you have one system go out in the Dallas area,
you still have one going on in Houston,
you're still gonna provide a benefit to the system
to help with reliability that day.
-: Correct.
I think, we've already got 225, 230 sites across Texas.
So that's huge diversification,
but then if you take that to the extreme,
not just us,
but we're gonna continue to add more distributed generation
on the grid and it's gonna be everywhere.
And so there's gonna be so much diversification
that did you be worried about having a circuit
that is direct to a transmission grid
that can be protected especially when you have,
you get to these smaller DG sites,
that maybe one megawatt size,
and we have a lot of those at grocery stores.
And if they're one megawatt size, they cannot,
there's no way that TDSP is gonna be economically
make that a direct circuit and keep that energized
during a rolling blackout.
But the diversification,
I believe both geographically
and just what the diversification
of the actual rolling blackouts
is gonna keep that at a very high level
of availability and reliability
-: So if we were to get to a rolling blackout load shed event
we would be relying on other tools to bring the system back
or keep us from going to an EEA3.
But with respect to those microgrids,
if depending on the level of the load shed event,
it provide benefits though, but it may not,
depending on the size is the-
Corey: I don't know if what I described
is any really different
than what we just went through in a hurricane
and you have transmission lines that get knocked out
that can take generation plants out too.
Are we gonna say that every, I'm not trying to be,
but are we gonna say every generator
can't participate in ancillary services too
because a transmission system might...
part of the transmission grid could get taken out by
a hurricane or something like that.
I'm just saying that I think the reliability
of a distributed system is just as good or better
than the generators that we have currently operating,
so can provide similar services.
We go to the next page.
I wanna talk about a little about ERS because
we are a participant in ERS.
Wanna just kind of talk a little about what Canon said
about generators participating in ERS.
Once again, we had,
two years ago in 2019,
and two events that we had,
we had 99.4% availability in the eight 13 event.
And then eight 15 event,
we were at 100% availability on ERS.
During this winter event,
up until we went to EEA level three,
we were at greater than 90% performance.
Once we went a day, level three,
when frequency dropped down so low,
it did trip off many of our generators.
And that wasn't just necessarily distribution circuits,
but it was because the frequency dropping so low.
But then after that,
we did have quite a few rolling brown that did impact
our performance somewhat, but it did affect us,
but we were still providing the service
that we were supposed to be providing
and trying to prevent us going to an EEA level three,
up until that happens.
And somewhat when that happens,
that does change the system some point.
So wanted to talk a little bit about that.
The other thing is on the,
we've talked about the budget cap.
I think a lot of people have mentioned that we also think
it should be raised.
It's been a $50 million since I think 2008,
we've had about a 30% increase in load since then,
peak load.
So we think that's something that should be looked at.
Another component that I'd like to talk about is
that we talked about how ERS is dispatched.
And right now the 30 minute ERS is dispatched
on an EEA level one.
And then EEA level two is when the 10 minute is dispatched.
We've talked quite a bit,
or for the fast past few years that we think
anytime as you approach zero in response time,
that resource should be worth more
than a slower responding resource.
And so what's happened in ERS is everyone has went
to the 30 minute product because it's priced the exact same.
And we're gonna go to the 30 minute
because it gives us more time to make sure
everything's up and running properly whatnot.
But what we would suggest is this let's take everything
to an EEA level one startup time instead of EEA level two.
And during the storm, I saw that we were,
1215 was when EEA level one happened,
107 was when two happened.
And then 120, we were at EEA level three.
So 52 minutes between one and two,
13 minutes between two and three.
So between two and three went, like you said,
extremely quick.
If we move those all up to level one,
I think that helps somewhat.
But then I think also if we're gonna increase the budget,
why not incent more people to go to the 10 minute response
and make that a dual bidding system
where if you can do the 10 minute,
maybe then you can get paid more for that, right?
Because you're providing a better service to the grid.
And if you had a 10 minute response time in EEA level one,
I think that's very helpful to the grid.
I guess that's probably my primary comment on that.
Last within,
setting up distributed generation,
one of the things that we've noticed,
and I think a lot of people see is that the difference
between a large generator and distributed generation
is any one thing can cause it to be uneconomic, right?
And so interconnects become very important to us, right?
The cost of interconnect.
And two things really affect that, one is metering.
If we become a distributed generation resource,
we have to put in EPS metering,
there is a wide array of pricing between TSPs
on putting in an EPS metering.
We have one TDS P that we're working with right now
that we'll do it for $0.
And another one that's $450,000 for an EPS meter.
I think a lot of these rules are based on old rules
many years ago, put in place with AMS metering.
I think metering is a lot more dependable now
than it used to be in the past.
But when you're talking about a one megawatt site
and you say all of a sudden that could be $450,000,
that could be 40 to 50% of the cost of the entire project.
So that's very expensive.
There's also a lot of things I'd like to talk about
on interconnect with the protection that's required on TPS.
It used to be basically if you went to two megawatts,
you know, you didn't have to pin in transfer trip.
And if above two megawatts generally then transfer
trip could be required.
That has changed a lot.
And so some utilities are requiring transfer trip
for basically every facility that's put in place.
Those can range anywhere from 150 to $250,000.
And once again,
that's a very costly component for putting
in distributed generation.
And one part that I'd like to really point out is that,
the main cost of that is put the equipment
into the substation,
that it's the first mover that pays for the entire
cost of putting that system into the substation.
And once it's set of up on the substation,
then others can come in and get do it much cheaper.
So should that be a subsidized cost across
the grid somehow to incent more
distributed generation being put on the grid?
That is all I have.
-: Before you move on, if I could,
I certainly wanted to...
Saw your comments consistency on interconnection processes.
Is there...
what's the inconsistency other than these price
in terms of these augmentations to their system
in order to get you interconnected?
Is there a timeline inconsistency as well
in terms of process, or what do you see out there,
you're operating in every system?
Corey: Yeah, there is,
I mean once you go into a transfer trip,
that can increase the timeline by 10 months,
well, for doing something like that.
So that gets to, have transfer trip facilities
that'll take over a year to get interconnected.
-: It seems like some DG interconnection standards
is where you can use some assistance from us
and working with the TDU and coming up with consistency
in their tariffs for charging distributed generation.
Corey: Yes, I agree.
-: If possible.
And I think one thing that SB3 includes in
it is that ERCOT has to require an owner of DG
to register with ERCOT and also with the TDU.
So I think that's gonna provide a lot more visibility
into the distribution system.
That's been something I know,
or kind of struggled with for years.
And so as we look to integrate distribute generation
into a variety of programs
and use those facilities for reliability,
I think that's gonna also of help
with respect to (indistinct)
Corey: I agree, appreciate that.
-: Well one quick question.
I know we're trying to watch the clock.
You spoke about your reliability in various
across the presentation,
and I believe you said you run natural gas generators.
Corey: We do.
-: How do y'all ensure farm fuel supply?
Corey: That's a great question.
First of all,
is that we are providing resiliency as a service
to our customers, right?
So us being there during whatever weather
is extremely important.
So we always buy firm, no notice, natural gas.
So we pay large premium and price to get our gas.
We're not buying non-farm gas.
So that's the first thing.
The second thing that we saw during the storm
is that our operating pressures
that we can down can run down to five PSIG.
Whereas a lot of turbines have to run somewhere
between 400, 700 PSIG.
So where they might be affected by drop in pressure
that doesn't affect us at all.
But the primary reason is that we pay up to make sure
that we get,
we're willing to pay the higher price to make sure
we're available over there for our customers.
Peter: Is there any particular, is it just any farm?
What, I mean,
there's lots of flavors of contracts there,
any specific standards that y'all so set as minimum?
-: We're behind LDCs because we're not as large,
we're not on the intrastate or interstate pipelines.
So we're behind the LDCs, we're buying service from them,
which is a more firm service right
in the first place.
Yeah, but that's primarily where we're operating.
Peter: All right, thank you, sir.
Lori: Got one more question
with respect to weatherization and any lesson learned
from the winter storm.
I thought I heard in passing that there were some
maybe natural gas diesel BG facilities
that weren't able to function during storm cause they froze.
And is there anything there?
Corey: We definitely had lessons learned.
We were taking notes during the entire week.
Seeing things were happen.
We had certain breakers that may have froze up
that we've looked at inside ATS.
And our inside of our ATSs that we're adding heaters
to changing the heater settings, stuff like that.
But nothing with freezing up that happened to us,
but we've spent a lot of time on that
and I've already started making changes to
just like you do.
That's just what we do.
Anytime we have an operation,
we're always looking at what happened,
how should we look at it?
What could we do better?
What could we change?
Stuff like that.
So I think we've already made or in the process of making
a lot of changes that will increase reliability
further than the whole we had.
-: All right.
Thank you very much.
Corey: Thank you all.
Appreciate you being here, Mr. Amthor.
Before we bring up our next panel,
two minute break
and we'll reconvene at 2:30.
Reconvene this work session.
-: Trees and stuff-
-: For our final panel screen on products and technology
and emphasis on technology,
we will start with Ms. Hart from SunRun.
Amy: Thank you so much.
Thank you, chair.
Thank you, Commissioners.
Thanks for having me here today.
Part of the conversation and including SunRun.
Just by way of introduction, My name's Amy Hart,
I'm a senior director Republic policy at SunRun.
I Have been with SunRun since 2014,
have worked on solar policy here in Texas since 2015.
Happy to be here in person with all of you.
So just a little background about SunRun.
SunRun is a residential solar and storage provider
started in 2007 by our co-founders
Ed Fenster and Lynn Jurich.
We have grown to become the largest residential
solar battery storage and energy services provider
in the country by a significant margin.
So we focus on that residential sector.
We have more than 600 down and customers across the US.
We are the one of the top three owners of solar in the US.
So if you think about just who owns solar farms
who owns solar,
we have 4.2 gigawatts of networked solar capacity
in the country.
We are in 23 states, Texas being one of them,
including Puerto Rico and DC.
Texas has served SunRun customers since 2017.
And we started offering battery backup since 2019.
So overall,
part of this conversation will be about
demand response and those resources.
We don't participate in those programs currently,
I'll explain some of our, you know,
Hey, here are the opportunities,
but really number one, we're fairly new to the Texas market.
Since 2019, we have branches and service in Houston
and Dallas or worth area. And most recently adding solar
and storage service in San Antonio and Austin.
We have nearly 500 employees
working at all those different branches in it,
out on rooftops, on any given day here in Texas.
And before we get into the sort of the opportunities
and challenges within demand response,
since it's my first opportunity getting to chat
with a couple of you just about the experience
this past February during the winter storms
really just wanted to share with you what happened
for our customers and our SunRun family here in Texas.
We had hundreds of customers that had solar
and battery backup systems.
They were able to power through those outages.
And so what that means is they have solar on their rooftops.
They have a battery system that's backing up their power.
The next day, the sun came out, recharged the batteries,
we had hundreds of customers with thousands of hours,
an aggregate of backup capacity.
Some of those outages ranged for 15 minutes
that happened on and off.
Some were a couple of days long.
We, even this past week,
I called our tech team yesterday just to see
how our systems perform during the Storm Nicholas.
And we did have a number of our customers
about a third of our storage customers
in the Houston area that did have power outages,
but were able to have backup power
through their battery backup systems.
We actually saw those systems kind of around
the entire Houston area.
So it's been interesting just to see
where the outages occurred,
but happy to see that all of the customers were able to see,
have that backup power.
Some again, ranging from in the Storm Nicholas
ranging from one hour to 26 hours in some cases.
So that's sort of what our experience has been.
We do know that when there are the weather events,
they're outages, it is felt close to home, as you all know.
And also whether it makes us all feel better
or worse, we are part of these conversations
and we're experiencing these types of situations
and conversations about how to build a more resilient grid
in lots of other states
and in lots of other wholesale markets across the country.
So anywhere from Michigan, California,
the Northeast New Orleans.
And so what we've seen in our approach is thinking
about that home solar and battery system.
How can we leverage that to not only provide
that peace of mind for customers,
but how do you build that resilient grid
and demand response can be part of that.
We're working with utilities
and Commissions in a number of different areas
to use these re sources in a variety of ways,
depending on what the need is
and demand response can certainly play an important role.
So we, as a member of,
we have a member of a number of trade associations,
so that's how we've provided comments
on the demand response docket work session.
We're members of TABA
of the Texas Solar Power Association and CS.
So that's how our comments have been provided.
But thanks for inviting me here today
to talk a little bit about some considerations.
So as I said, DERs distributed generation
in our respect, solar plus storage,
really leveraging all of the different values
that can bring becomes really important.
We also do support, which was mentioned earlier,
making sure that those rules,
those can provide guardrails that's technology neutral.
So we do solar and storage.
We think it's a really powerful resource,
but we also know there's smart thermostats.
We also know there's heat pumps.
We also know that there's going to be the ability
for electric vehicles to play into that.
I'd be remise if I didn't mention we have a partnership
with Ford,
that's rolling out with their all electric
Ford F150 lightning,
where we'll be able to provide some backup.
I'm just gonna get some water if that's okay.
I'll take a quick break.
I should have brought it with me.
Thank you all.
So with the Ford F-150 the electric
that would be the first electric vehicle that's going to,
instead of just having your home or the grid charge
to the vehicle,
the vehicle can provide backup power to the home.
So that's where things begin to change.
We also had, excuse me,
a partnership in South Carolina
with Duke Energy
and they have used their energy efficiency program
to develop a program for solar coupled
with smart thermostats.
So using kind of looking at all those
different technologies, how to encourage that in the home.
(coughs) excuse me.
Peter: We can be a tough audience.
-: I know, I apologize.
I was doing so, and I'm fine.
It's just a little tickle that I realize.
I think I realized- (laughing)
I should have started with that.
I should note this photo is from the winter storm
in Houston, one of our customers.
And I think one of the pieces of my remarks
is really thinking about this as seamless for the customer.
They went out to walk their dog in the morning,
and kind of what's going on,
it did not know that there had been a power outage
because of that seamless switch to a battery backup.
And so that was one of the families that was able
to power through our goal of course,
is to expand that to as many folks as possible
and expand those solutions.
McAdams: So what did look like for that family?
I mean, was this just a brief interlude to where
they bought themselves some time or did they make it?
Amy: Oh, little bit both.
So we did not have any experiences where
the battery was drained so low,
where they were not able to make it.
And that could be a combination of
they had an outage of 20 minutes or an outage of an hour.
If you get into a multi-day outage,
we did not have a number of days without sun, right?
So the next day there was enough,
maybe it was a little bit of cloudy
for a couple of hours still as the storms rolled through.
But that was able to recharge the battery.
And so they were able to power through.
Now we do have some customers
just to get into that experience,
we will design the system for their need
and also their financial situation.
So we have enough of different offerings.
We have it offer the LG Chem battery,
and also the Tesla Power Wall battery.
We were the first solar company to install
a Tesla Power Wall for backup back in 2016, I believe.
So we have a lot of experience.
The Tesla Power Wall provides a whole home backup solution.
So if you're like, Hey, I want everything on,
I want my coffee maker on.
I want my, all the appliances, that's your backup.
If you say, okay, I can handle my critical loads.
What's my heating, what's my refrigeration?
What do I need for my critical loads?
Then you can size your batteries system a different way.
So some customers said, okay, we want the LG Chem,
we want a smaller battery.
well, now your loads are going to adjust a little bit
when you go to that outage,
but they knew that ahead of time
that they didn't need that whole home back up.
So that's kind of the conversation we have
at the kitchen table with the customer.
So one of the other,
so the next bullet is the aggregate load reduction.
And I think,
so I think this is something that's been interesting
as we've done a few bidding into wholesale markets
or demand response of being able to aggregate
these small systems,
but still have trans into what's happening.
So we fully support transparency.
I think when we get in to talk about costs
for participation,
does the requirement of telemetry down to a home
with a five kilowatt system make sense?
That's just not economically feasible for that customer
to be able to do that.
And we've seen in other RTOs,
like in the CaISO market,
they said we don't need to see it down to the home,
but we'd like to see it aggregated at the 100 KW level,
which is about 20 homes.
So that's pretty darn small,
that's smaller than most commercial.
McAdams: So what does that look like?
Does that, do you install a feeder or?
What does that look like?
-: No.
So they just want to be able to know
that's what's going to respond where,
and whether it's some sort of meter of some sort,
not a separate line by any means.
McAdams: So you install a separate meter that everybody
into all those power flows,
that then goes on to the distribution system
that goes to wholesale.
-: That's right.
So I think there's...
I guess what I love about it is the power of
aggregating these systems that makes it powerful,
but you can still have the ability to see
down to that noble level.
If you're talking about the switch from a whole zone
down to vocational price,
well, now you can see where those aggregated systems are.
So there's I think different conversations
about aggregated DG, and what does that mean?
From our perspective,
aggregated DG can be anything from 100 KW
up to the multiple megawatts.
But being able to use demand response
as a way to aggregate those systems.
We also support having REPs be able to aggregate
those system or finding a market for customer
cited solar and storage and demand response,
but also would encourage the Commission to think about
the rules around allowing third party aggregators
to do that.
It might be a company like SunRun,
but there's also a lot of really good solar companies
and solar and storage installers
that have no interest or experience in being aggregators.
So set up market rules,
which would allow those types of third party aggregators
and providers to be on the hook.
To be made to make sure those that shows up
when it's bid into these systems.
The other piece is yeah, enhancing the compensation look.
The two main barriers is any signals,
there's providing the economic signal for a company
like SunRun or others to find the solution
and participate, and then the other one would be technology.
And the technology kind of impacts the economics.
So providing the right signal, if you're saying,
Hey, we want more of resources to respond,
not when it becomes that EEA3 but earlier,
and maybe it's scheduled.
ISO New England, for example,
we have been into their capacity market.
So take what works for this market.
But they have scheduled four hour peak windows
in the summer, two hour peaks in the winter.
And so you're on the,
you have to show up when called on during those windows,
but then you can also in California,
in CaISO it's also day ahead.
So there might be peak programs that we would sign up for.
McAdams: So let me ask you this on aggregated basis
and ISO New England that gets a capacity payment,
and you get to bid for a capacity payment.
-: Correct.
McAdams: The cloud goes over, you're out.
How does the penalty work?
-: Well, the penalty is significant,
so we make sure that-
McAdams: and how does that-
-: We show up-
McAdams: Does it go down to the customer and then like,
oh my goodness- -: No.
Yeah, so the risk is on us.
So that a great question.
So how it works in ISO New England is it,
so for example, we successfully been in it's 20 megawatts.
Which is five to 8,000 homes,
and we under promise, and over deliver.
So do we have way more than 20 megawatts
of solar and battery systems that we can call on
to meet that requirement?
Yes, because we never want to be short and pay that penalty.
And so what we will do is, we'll,
we would get a payment to participate,
but that payment gets passed onto the customer
in a monthly incentive,
whether or not they're called on or not.
Because we know we need to use them in aggregate.
So we may have 15,000 homes that we have enrolled
in the program where we only need 5,000 of those batteries,
of the battery to show up.
And the other piece that I would note,
and I can talk a little bit more about this
is just how it works at a customer level
is that it is seamless, right?
So they get a reduction basically in their battery price.
So now they get, okay,
I get the peace of mind if the power go is out,
but it's a lot lower because we get a benefit
for participating in this capacity market.
We get called on, they never know.
Because we're just using the power that's in their battery.
-: So, but they're paying for reliability
and redundancy if the power goes out,
while at the same time you're drawing down their battery?
Amy: So if the power goes out,
we're no longer gonna be called on.
-: Well, I thought-
At that point, it's too late,
but they thought they had a full battery.
But because presumably
that capacity was called on the way-
-: Like the day before, yeah.
Six hours before.
Great question.
Peter: So not only has the customer given up
control of their battery,
they've also don't have a full battery
when they think they do.
-: So we always reserve 20 to 50%
depending on what the customer wants of that battery
for backup use.
So we never say we're going to your battery is 100%.
Peter: I thought I had 100% battery
and the lights go out and I've only got 50%,
as a customer,
I'd have some pretty strong negative opinions about that.
McAdams: With the size of your house.
I mean, You can light of one room, right?
(laughing)
-: Well, I'm not gonna- Peter: The whole house.
-: But it's yeah.
I won't get into your electrical needs.
So what will happen though,
that's part of the conversation in the contract
of what are you going to use it for?
What are your expectations?
If you say, I want whole home, no matter what,
I don't just want to use critical loads while charges
back up, fine, that's not the program for you.
There's that understanding,
but you're exactly right.
But that's why we have 15,000 homes participate
instead of 5,000 homes, because you're not using---
Peter: Sure, thinking about the customer.
I can see how it works from your company's level
and from the so it's level by aggregating me homes,
but for the individual customer who paid for
a pretty substantial infrastructure in their home,
there's an upfront,
I guess, subscription package they get to choose-
-: That's right.
Peter: Silver or gold package,
but there's, depending on the fine print,
they may think they've got a battery for a backup
that's gonna be 100% charge when they need it the most,
but they can, when the lights go out,
they may find out they've only got 50% of what they thought.
Amy: Well, and with a battery, the look,
the lights are out for 10 hours.
Like it is, but there is generation.
That's why we always tie it to solar
because there's always generation coming into that battery.
So you have that battery has to get you through an evening.
Unless you're on that critical load,
now you're going to have down to your critical loads
to get you through that evening.
So you design that system,
so you know, you've got that generation coming.
-: Very tricky customer experience to manage.
Amy: Yeah, yes it is.
Other questions?
-: No, keep going.
Amy: Okay, great.
And so the other piece I would just mention
is the compensation ensuring the technology
can respond data head signals for the technology today
makes the most sense that's sort of what we've done
in other wholesale markets where you could we program
basically all of the batteries to dispatch a day ahead.
If it needs to be closer to those emergency response
events then the compensation would need to be more
because it takes a lot more response right now
for the technology that we have today.
But I did just,
I wanted to mention that ISO New England experience
is because there's the conversation about for 22,
and how is that going to,
or should apply and just that there are mechanisms
and that's already happening in some RTOs
is that there is the aggregation of DG of distribution,
a generation that can play in the wholesale market.
You can go to the final slide.
I'm happy to open this up for more questions too,
but I just wanted to make sure,
and this kind of gets to your question share,
what are all of the,
what's the expectation of the customer?
is that there always has to be at the top line
for the customer there always to be the backup power.
That's what people are calling for.
I've seen just a tremendous shift
in the past two years alone
much less my many years working in solar
of the number of folks who have called
interested about solar 50 to 75%,
want storage with it easily now
compared to the past couple of years.
And so now how do we,
in addition to just providing that backup power
for the customer, what else can we do?
So we've got a demand response bucket
where you can aggregate DERs
and that can be solar plus storage
combined with that smart thermostat.
How do you think about,
as we start thinking about the home,
that electrification of the home
and what these gentlemen will most likely talk about.
So that's one bucket,
and then we have the energy market bucket.
Whether or not there's a path there
for behind the meter distributed generation to play,
but that can provide reliable generation
affordable generation into the energy market,
but then also grid services
and working with the distribution utilities
on how to tap into some of those grid benefits,
frequency, both bar even potential,
even some of the microgrids and backup power
from levels that's where we've had
some real great success with...
bring your own device type programs with utilities.
So there's sort of that partnership piece there as well.
So that's how we think about it,
if you think about the battery of
all the different values it can bring.
So certainly wanted to leave you
that this isn't the only pathway to consider,
but having different ways where the market
can respond and create that reliable grid.
-: I guess Amy, I have one question.
So we've been exploring
how to incent dispatchable generation and in one hand,
and then looking at the supply side in the other.
And on the dispatchable generation investment side,
we've often said in many workshops
that it's just not the generation,
it's also renewable generation,
like solar that compare with the storage.
However, in the air hop market,
we haven't seen a lot of proliferation of solar
and storage from a utility scale perspective,
but there's an economic component to that aspect
of solar development,
but on the solar distributed generation side,
it sounds like your business model
is definitely got a lot of subscription.
What are the economic, what are the,
is it just because the solar smaller,
I mean, I'm sorry, well, the solar is smaller,
but also the storage facilities are just smaller
and it's just more economic on the deep solar DG side?
Amy: Why would people make that (laughs)
I mean, we, (laughing)
-: Yes and no,
I'm just kind of trying to understand cause it seems like
I mean it might be expensive too on the solar DG side
but it seems like there's a lot more growth
on the solar DG side than the utility scale here
and potentially here in Texas.
Is that true?
-: Yeah.
When Lynn and Ed founded the company back in 2007,
the concept was two things,
there are a lot of are rooftops, right?
There's a lot of built environment,
how can we use that space for generation?
And then that you can use right where the load is.
That's a very efficient concept.
And then the second aspect was families and homeowners
and small businesses need the ability,
what's the ability they have to control
and manage their electricity though.
And that's why I think in Texas,
we have found a very a more interested market
because customers are engaged in electricity choices,
more so than any other state that I cover.
And I cover, and work a lot of different types of states
across the country,
but the fact that there's the experience of well,
what type of REP is right for me,
what is the electricity bill that fits
the needs in my family?
Is it that average bill?
Do I wanna participate in a free nights
and weekends program?
What does that look like?
We have a very very educated customers in Texas.
And so the notion of creating my own generation,
storing it and being prepared and using that onsite
is almost second nature in my experience,
as far as working with customers here in Texas.
And I think that's become more of an interest of,
okay, that does seem to make natural sense.
There's solar, I'm gonna turn the light switch on
that's where it's generated.
But now the idea of having that piece of mind
of backup power really has been front and center
to most of our conversations.
Lori: Have, have you seen an increase in the interest
in your solar battery package since Winter Storm Uri?
-: Yeah, considerably .
In specific we don't usually talk about
the state level of information,
but yeah, like I said,
easily 50 to 75% of our systems that are being installed
now are that customers are asking about
have storage attached where before maybe it was 15,
maybe it was 20%.
And that was Texas,
even at that point still leading the country
in many other states, they just haven't gotten there yet.
They haven't had that acute experience.
That's still in their minds, so it's absolutely an interest.
And I think we're not the only solar company
that's seeing that,
I think probably if you talk to Oncor and CPS,
they probably have seen lots of interconnection
requests coming in for those solar and storage systems.
And so how,
what are the programs then to use all of that technology?
Because there's a lot of value there behind the meter
and can we create a demand response program
or other programs that can use that for neighbors
fo the grid?
-: Like our job is to move from individual home peace of mind
to utility-scale peace of mind.
Thank you very much, Mrs. Hart.
Amy: Absolutely, thank you.
-: Next up, Octopus Energy.
-: Hi everyone.
My name is Michael Lee representing Octopus Energy.
I am the CEO of the US business.
Thank you for having me Commissioners and chairman.
So I'm gonna start my slides today kind of outlining
who we are at Octopus because that frames what we do.
We've only been around for five years
and in those short five years, globally,
we've acquired over two and a half million
individual meter customers.
And that's simply on two principles;
one giving customers an incredible experience
that's extremely fair, and two, as low price as possible.
And I think both of those elements tied very directly
into demand response.
And I think we have a huge opportunity
to unlock massive amounts of demand response
here in Texas and in the ERCOT market in general.
Next slide.
So just to kind of keep it a little light,
I know it's the afternoon,
we've seen a lot of different presentations.
This kind of ties into the prior example
by growing so quickly by doing the right thing,
we've been able to create value, not just for our customers,
but also for our shareholders.
We think that these things are highly aligned.
We've gotten to
a Unicorn status multi-billion dollar company
and just these handful of years.
So I like to say that we're a tech company
that happens to do energy.
At its core,
we have a software platform that we built
internally called Kraken,
that enables us to have a 50% lower cost of sale of service
than our competitors.
And that allows us to do a lot of interesting things.
So it's not just meter reading and managing customers,
but it's helping integrate into vehicles,
batteries, thermostats, you name it, we can control it.
And that is what we do every single day.
We wake up doing this stuff.
This is not a side team that thinks about this.
This is the very nature of what we do
in our day-to-day jobs, next.
So a couple of products,
when we think about demand response,
we think about two way participation in the energy markets.
And what we've designed several years ago in the UK,
is the world's first index based rate.
I understand that with HB 16,
that's no longer a product that we offer here
for the real-time product but just kind of qualifying
as far as what we can do to link prices, to devices,
to allow customers,
to get the benefits of really low prices,
as well as shutting load when the grid needs it.
And I think these things kind of come hand in hand
and there's different ways
that we can creatively think about the Texas market
as we kind of move forward.
Next.
We've done a couple of things as well
with regards to balancing the grid.
We've had some opportunities
where we've seen a surplus generation come online.
And so demand response is not just about shedding load
when we see a critical time period,
but it's actually about moving that load to a time
where we see excess supply on the grid.
I think I like to talk a lot about the hotel industry
and the airline industry.
These are fixed asset industries,
and it's about creating efficiency about how,
and when you use the product
and they've gotten really good at doing that.
I don't think we've gotten as good as we can
here in the electricity industry to maximize the opportunity
of this fixed asset called the grid and generation
that we have available to us.
Next slide.
So in this example, what we call the big switch
and there's a "New York Times" article about it,
we've been able to incentivize our customers
and it's not a large payment.
I'm talking about just maybe 5 cents, 10 cents,
20 cents per kilowatt hour,
that we've been able to pay customers.
And we've been able to move 75 megawatt hours.
Sorry, I didn't mean since fractions of a penny.
So we can (all laughing).
Fractions of a penny.
We were able to move a lot of generation demand.
And this example,
we've moved about 75 megawatt hours with no investment,
no cap ex no batteries, no costs to bill payers,
simply just informing them when is the cheaper time
for them to use energy and passing on
that financial benefit to them, even as modest as it was.
I think the compound that second piece I'll make,
is that every single night, again,
our core market right now is the UK.
We are excited about rapidly scaling here in Texas,
but our core market in the UK,
we engage in a demand response every single day,
we, every single night,
we have an V tariff and we've shift more megawatt hours,
50%, more megawatt hours, then the largest
installed utility scale battery and the grid.
So we are actively able to move load.
And as we electrify transportation in the state,
that's gonna be more and more of a real concern.
We're able to move load in a very material way
without a single cost to us or to our customers
or to the broader grid,
but simply actually saving everyone money
because the less that they use
during those on peak rates
and the more that they use during the off-peak rates,
the cheaper it is for everyone else,
even those who aren't participating.
So we think about rates in this new paradigm.
So this blue line is the fixed rate that everyone's used to,
but it never accurately reflects the grid conditions.
And so time of use rates is a great way
to start thinking about getting customers
the right kind of financial incentive
to change their behavior.
But what we're talking about is that we're moving
into a very unpredictable world,
so agility and the ability to be responsive
generally in real time,
or to other signals that allow customers
to compliment the grid as the grid
is going through unique situations on a day-to-day basis.
We're talking about frameworks and technology
that honestly have been deployed in many other industries.
We think about the modern work environment.
It's a very agile work environment.
When we think about software and coding,
it's a very agile work environment.
We think that these types of concepts can very easily
be applied to the grid with some small modifications,
and I'll kind of get into that future slides.
Excellent.
So one last point, you said this may not apply to Texas,
but about a year ago,
we used to offer index rate prices to customers.
During the winter storm, we kept our customer's exposures.
We wanted to do the right thing to customers.
So we didn't give them the full cost exposure.
But in this example, you can see,
this is a chart of a Texas customer
responding in real time to conditions on the grid
in the middle of October.
You wanna think that we would have expensive prices
in October, but because of seasonal maintenance,
we often do have tightness in the shoulder months.
And so having the ability to shed load on a real-time basis,
or at least in partnership with the retailer,
is what we envisioned as a very important
part of the future that we have already created,
and that we are accelerating it too.
So I figured I'd kind of spend my time today
to kind of put you in my shoes as a retailer,
that's trying to do this.
What do we think about how do we do it?
So I like to think about demand response
into two separate categories.
One of them is economic self-interest.
As a pure play retailer,
I have a lot of incentive to do this right.
And because I'm well capitalized
and have great technology behind me, I can easily do it.
I'd say again, as a CEO, if I was a diversified retailer,
I think it would be as in Jen Taylor,
I think it would be complex to think about the dynamics
of my various P and L's and how I wanna allocate
profit across those P and L's.
And I think demand response makes this
a lot more complicated in that situation.
But as a pure play retailer,
I have very clear financial incentives
to do the right thing, not just for myself,
but more importantly to my customers.
Because the lower the prices that I can extract
in the market,
the lower the prices I can offer my customers.
And when I can do that, I can win more in the market.
So I look at demand response is not just something
that's good for me,
it's also good for my customers
and it enables me to grow as well.
So again, I think of two different demand responses.
One of them is this economic self-interest,
this is purely voluntary, is unpredictable,
but prices ensure reliability.
As high prices come, that is my stick,
or even carrot to go do something different.
Then I think of a second type of bucket command and control.
I heard a lot about dispatchability, certainty,
visibility in the comments or the questions earlier today.
Command and control is the perfect execution for that.
I think of that as a separate type of demand response.
And the way that I kind of think of it is,
if there is command and control and certainty needed,
then that means that there's a penalty for non-performance.
And if there's a penalty for non-performance,
then there probably should be an extra financial incentive
to perform.
Because if I'm only going to get hit one way
for not performing and I need to be rewarded
to actually perform above and beyond
my voluntary performance.
And then secondly,
I think that there's a lot of opportunity to actually think
it's great that it's by zone have some matters
for the nodal.
But I need to know a little bit ahead of time.
The more that I get zip code,
because my customers are in the zip code basis,
it's fine that we all think about feeders.
But the reality is that when I go acquire customers
is by zip code.
So I need to kind of sort my marketing activities
by zip code.
But the more forward value certainty that I can get
on those additional benefits,
the more that I can go aggressively market
a much lower price to those particular customers.
So that type of situation is very helpful
when it comes to command and control.
So before I kind of get into the nitty-gritty
of the things that make it difficult,
I actually want to start with the positives.
This is the perfect market for demand response.
Energy only market.
It makes it very clear that demand response
has a lot of value.
There's no wasted money in capacity payments.
It's very clear what this looks like.
I would say the fact that we settled to our customers
on actual load profiles and not
a generic load profile for a residential customer,
gives me even more incentive to go do demand response.
The fact that here in Texas,
energy is such a large proportion
of the overall energy consumer monthly spend
for anything gives me a lot of reason to help minimize that.
And then finally controllable loads
are more and more,
a larger percentage of the overall energy exposure.
First with thermostats and even more so
as we started electrifying transportation, hot water,
we are very excited about this future,
and we are very excited about having these assets
be responding to real-time grid conditions
or committed controlled grid conditions.
Next.
So limitations in the status quo
and before even getting, while we are a tech company,
before I even get to the tech side,
I think we need to actually talk about the cultural side.
Because at the end of the day demand response,
the technology is easy.
That's just ones and zeros.
What we're really talking about
is consumer behavior individuals.
How do we reach out to people and do something for them
and not the other way around.
We can't frame it as them doing something for us.
We need to do something for them.
So the current business model, unfortunately in retail,
it's kind of be frank, it's about forgetting the customer.
There's a lot of incentive for customers
do not know what they're paying.
So that way they pay very high variable rates.
And that gross margin is very lucrative
for the average retailer.
Engaging the customer,
which is a requirement of demand response
is antithetical to that variable rate product.
So what we're looking at is
that demand response equals trust.
If I'm gonna manage your asset for you,
you have to trust me that I'm doing it for your behalf
not for my behalf.
I think that unfortunately we've seen it
with some of the tweets and say, June,
a lot of people had their thermostats changed.
They're saying, "Where's my compensation.
Why is this happening?
I don't really remember this, and even if I did,
where's my personal benefit as a homeowner
or as a renter or as to some residential customer
in this state?"
So I think that we lose the link
between doing something for ourselves
versus doing something for the customer.
And at the very least engaging customers monthly,
to just say, here's your current rate,
will give a lot of awareness in the market.
And I think that awareness is the first foundation
to demand response.
I like to think of it as this analogy.
When you go to the coffee shops
say you go to Starbucks and you order a coffee,
you don't get a formula on a website
about how much the coffee is gonna cost,
how much the milk is gonna cost
and how much the barista's time is gonna cost,
and then get billed 15 or 30 days afterwards.
You know before you drink the coffee,
how much it's going to cost.
That's not how our current market is engaged or structured.
So there's no way for customers to know
that they actually got the latte and not the drip.
And demand response is the way for them to
move from the latte to the drip,
save some money because they did an action.
But there's no way to do that in this current market
because people are incentivized to not know.
So just at the very least engaging them on a monthly basis.
And there's really no excuse in the digital age
for a retailer not to engage their customer once a month
what their rate is.
That should be very easy, email, text.
You could even snail mail it.
But that is all low cost and easy,
and that is the building blocks of not just trust
and awareness, but then going to doing something
even better with that customer.
The second piece is that again, we are humans.
Feedback loops need to be really quick,
unfortunately in the way that the energy markets work,
there's some friction involved with doing an action
and getting a quick response.
I'll kind of go through
a couple of opportunities for us to move that feedback loop
really tight.
So that way, when there's a response,
there's an immediate feedback
and incentive given to that customer.
And then finally,
we have to also recognize the product
that we sell is invisible, right?
Many customers, sorry for the bad pun, feel powerless.
They feel like the bill is the bill type of mindset.
This is such a large expense for the average person.
And yet they feel very unempowered
to make a big impact in it.
Demand response is a huge way to do that.
But getting an opaque bill there 15 or 30 days
after you've done something is not the style
of encouraging real-time participation, right?
So I think there's partly a business model issue,
but I think that there's also a lack of tech centricity
that is now emerging in this market.
Next slide.
So I'm gonna get into some nitty gritty stuff
but it's all in the spirit of where some of the friction is
on the customer side.
Because again, everything I do when I wake up,
is I think about how can I make this
an incredible modern experience for my customers?
When you go to amazon.com and you order something it's easy,
why can't energy be like that?
So when I think about this,
and the things that we get tripped up on the SMT side,
I think can use a little improvement.
I think it's a step in the right direction.
The two or three things I'd like to highlight,
one is that it can only get two calls per meter per hour.
A call is a start.
And then the second one is a stock.
That's a two calls for one measurement.
What happens when I use this is that if I try
to take an action and I want to call that meter
to see if it actually worked, and it didn't work,
while I'm in the dark for the next hour.
I can't try to recall that action again
and see if it worked a few minutes later.
So I can do multiple calls a meter,
I can do multiple verifications
if that actual action worked.
Limited to 3000 calls for TDU, you can kind of do the math.
And that means kind of 1500 customers at best
in ideal Senate scenarios that I can do.
So, truly improving the API structure, modernizing it,
making it highly usable,
as well as increasing the number of interactions and calls
that I can have in real time.
I think that would be amazing.
And I think it's, the structure is already there.
It's just kind of increasing these artificial limitations.
I think there may even be an opportunity
to kind of consolidate those that are gone.
It seems like a duplicative set of data
that's above and beyond what that same type of information
that were caught using anyways.
Let's just make it more streamlined and simple.
Next slide.
So DER's, I love all the acronyms.
I love the DER's the BPPS,
we get really excited about this teacher grid.
We get really excited about enabling it.
We are actively able to manage a lot of these things.
We do vehicle to grid projects in other countries.
We could do that today, here in Texas,
it's not a regulatory issue.
It's enabling more of those vehicles on the grid
type of issue and does come in very quickly.
As we heard from SunRun.
We get very excited about all of this.
I think the thing that we would just like to highlight,
and this is actually in spirit of
broader market participation,
is that we worry about walled gardens.
We think that the best way to maximize value of DERs
on the grid is to have competition for those assets.
Meaning the customer owns them,
and then various third parties such as retailers,
aggregators, whoever,
they get to all compete to control them
on behalf of the customer.
And the more that that is competed against the more
that the value that customer ultimately gets to the house.
I worry about a world where
only one person gets to control that.
And you're kind of hoping that there's beneficial control,
there is a lot of incentive for that to be controlled
in the right way, but with open standards,
whether it's for storage or other assets,
chargers, thermostat, you name it,
the more that there's competition to control it,
the more value that individual customers get.
And then the more that they go talk about to other people
about why it's a great thing to own those assets.
And the more that you only enable one person
or one entity to control it,
the more opportunity there is for capture of value
to that entity and not the customer.
And that will slow the growth
of the broader participation of these assets on the market.
So we get really excited about solar and storage too.
We know that the traditional retail business model is ours,
is that the more mega megawatt hours
we sell to our customers, the more money we make.
That's okay.
We're actually really excited about solar and storage,
even though it conflicts
with our traditional business model.
However, there's a couple pieces of friction in here
that I just like to highlight
from a consumer-user experience.
So kind of step number one is that they work
with various solar companies to get their assets up there.
So their rooftop solar is on their solar assets on the grid.
We kind of have a multi-party coordination problem.
The solar provider will install it,
they'll go call the utility to try to get a Commissioned,
TDU will come out three weeks later or so to Commission it,
we have no heads up that that's happening.
So the customer calls us and says,
"Where's my solar?"
How come it's not on my bill?"
And I say, I don't know what you're talking about.
Besides the meter change out that we get on the EDR stream,
we actually don't have a heads up earlier than that,
that this could potentially change.
It'd be great to hear that one of our customers got
solar installed and is waiting for interconnection.
'Cause then we can work with them about designing
a great plan for them
so that way they're really happy,
but we don't have that heads up.
We don't have that visibility.
I think the other thing that creates
a lot of frustration for our customers
is that this whole process of updating new load profiles
is very slow.
So when they get a built few weeks later
for somebody to come out and Commission it,
when that PTO is authorized,
if that is the point that starts the process for ERCOT
to update a new load profile.
And that can take anywhere between one and three months
what we've seen to actually get that two-way channel
to be registered as a retailer.
You would say,
Hey, three months, one month, whatever.
Why is that such a big deal?
The problem is that somebody just spent $10,000 or more
on an asset and all of a sudden it doesn't work.
What do you mean it doesn't work?
Somebody just came up to Commissioned it.
I don't know, I can't see it because it doesn't work.
So that creates a lot of friction in that case,
because then they're not gonna go tell a friend to go spend,
I don't know, five, 10, $20,000 on solar
or solar plus storage 'cause it doesn't work right away.
That feedback loop of when they spent the money
between the multiple months of when they start
getting the benefit of it, it's too long.
And I think that there's a way that when the interconnection
request is sent,
we can start processing that through archives
almost immediately.
We can say, Hey, this is coming.
And in fact,
I think one of the TDUs actually does this by mistake
in a way that's very favorable for customers.
And we've had actually,
'cause I don't think they realize that they're doing it
out of sequence and that's the one place
where customers love it.
And then it wasn't until we started asking
about their process,
that they actually changed their process to the archives.
So I think there's actually opportunity
that's kind of low-hanging fruit to improve
end user customer experience.
So this is my closing slide.
You can read the words and that's fine.
I think what's really important here are a few things.
I think that the role of the retailer is the prime role
to do demand response.
I've heard some comments earlier today about TDUs doing it.
I think that actually creates a friction
in a way that we saw in June
where things happen for reasons that are outside
of the control,
that natural relationship between a customer
and the retailer.
And then when they call us as a retailer, we said,
we don't know, we're not part of this.
And then they feel like we don't know
what's happening on the electric grid
because there's some third-party doing something
that we're not a part of and it's,
they don't know that the average person
doesn't know the difference between a retailer and a TDU.
They just want the electricity turned off.
They don't know why things are changing.
So when things are happening outside of our control,
it really limits our ability to talk to it.
And really changes that ability to manage
that customer experience.
And I think there's ways to have
a great customer experience.
And it's about communicating often ahead of time,
set expectations,
deliver on what you just said you were gonna do
and give them real time feedback and incentives
as they went through that process.
And I think we're rapidly trying to do that
with a lot of our customers.
I think,
we talk a lot about summer
and I think we're really excited about deploying heat pumps
for the winter.
And I think that this becomes a very flexible load
for the wintertime as well.
Texas has a really great market for electric base heat
and heat pumps because of the generally more
moderate temperatures.
So I think there's a lot of opportunity
to like maximize the value of the grid
through demand response, through changing behaviors,
through doing a lot of things that are outside of the norm.
But the reality is that an attitude of let's just do
something based on the past and maybe tweak it,
is going to get you results a lot like the past.
But thinking about a more modern grid
and a more modern interaction with customers
and a more modern deployment of many,
many fragmented resources,
that's something that we specialize in.
And that's something that we kind of lock
with technology and behavioral change.
And that's ultimately what we're here for.
Thank you.
-: Thank you very much.
So it was a very thorough, thorough presentation.
And I think all of us up here appreciate the fact
that the competitive nature of the Texas retail market
is a bit of the customer,
exactly because of the ability of new companies like yours
to come disrupt the space.
We've got lots of questions,
but I think we probably want to keep moving.
Thank you very much.
All right.
Aaron: Everyone, Aaron Berndt by way of introduction.
And thanks Commissioners for having us here today.
By way of introduction is Aaron Berndt.
I'm a Google's Energy Energy Partnerships team.
I've been with Nest for about six years.
And before that,
before that was with Pacific Gas Electric
all within our demand side management programs as well.
So been running energy efficiency
and demand response programs for quite a while.
Our team focuses almost exclusively on accelerating
demand side management programs for our energy efficiency
and demand response partnerships all across the country.
We have currently over 70 different
residential demand response programs that we're supporting.
And we do that through partners.
So aggregators, et cetera, to support utility programs,
third-party programs, et cetera.
We think there is a ton of potential in Texas
for demand response right now,
we don't have perfect numbers,
but for smart thermostat penetration across all brands,
it's somewhere a little north of a million thermostats,
smart thermostats in Texas.
But with eight and a half million central ACs in Texas,
there should be significantly more
of the smart thermostats that are in market right now
where there's sub 10% participation
in demand response programs right now.
So we see a huge upside Commissioner,
like you said earlier in the day,
it's all about AC, AC, AC.
Texas should be the Superbowl of demand response,
but it's not.
Outside of some of the great programs that we have
with CPS energy and Austin Energy,
We really don't see a lot of residential
smart thermostat participation in the REP programs.
So even in the prior panel came to the conclusion
that there are no blockers for demand response.
What I would push back on that is there doesn't seem
to be enough incentives to really unlock
the benefits in the economics.
I appreciate everything that Michael just reiterated
and we would love more of those types of partners.
That's not the current status of what's in market.
Multiple parties are reiterated that there's something
like 2% of REP customers are in demand response
programs right now.
So there's a lot of room to grow.
Next slide
So I thought I would start with some of the basics
of residential demand response.
Some of this we've already heard today,
so you can either ask questions everyday.
But we launched Rochelle rewards,
which is effectively a metaphor for demand response
in 2013.
One of our earliest partners was Austin Energy.
One of our longest standing partners,
and then closely after that with CPS Energy.
Similar to Michael focusing on making energy
easy for customers,
we've always focused on having really great,
simple customer engagement through all of our products.
And particularly with Rochelle Rewards
to make demand response easy for customers.
The key thing that we do there
is we balance the potential load reduction
with customer satisfaction.
So it could just mean that we crank the thermostat
and the customer's upset.
But that also means that they wouldn't be in the program
for a very long time.
So we do have custom algorithms for each home.
And as Kim has mentioned several times during the day,
customers do always remain in control of their thermostats.
What you're looking at on the bottom there
is representative of a typical event.
So most events are our partners will run pre-cooling
out of the event,
so they they'll run the air conditioner for an hour or so,
make the home a little bit cooler.
And then during the event,
it'll offset something like three to four degrees,
depending on the home a little bit,
that'll shift 55% of that air conditioning load.
And that's why we see so much potential in the Texas market
is if we had eight and a half million customers
that realize that's the technical potential
that would be a massive amount of load
that the Commission or caught in the market
could be providing on four dispatchable,
reliable reliability standards effectively.
The bottom stat on there came from CenterPoint's comments
where they are seeing 1.2, five KW per household.
That's pretty similar to what we see across the country.
We generally see roughly about a KW per thermostat.
The other thing to keep in mind
is that smart thermostats drive both energy efficiency
and demand response.
So I mentioned that we support both EMDR programs.
Many programs are just energy, for instance ,the only,
but we're seeing significant traction, if you will,
upside potential with our utility partners
is when they're stacking the energy efficiency,
incentives and benefits with also with demand
response enrollment,
where they're effectively being able to get
a no cost thermostat for the customer,
as long as they're enrolling in those programs.
Another line of questions that have come up
a couple of times today was,
is it how reliable is his demand response?
And do customers participate in events
when it's 100 degrees.
And the short answer is, they do.
CPS mentioned it.
So we, and they actually have data that shows
that customers participate on 100 degree days,
105 degree days.
And we also have partners like APS
a solar project in Phoenix.
Texas is hot.
Phoenix is very hot
and customers continually participate in those programs
because we're doing it in a way that is okay
with the customers.
We're balancing that customer experience
with the demand response experience,
as well as paying them incentives to stay in the program.
So it really is those two things that customers
are able to are since they are partners,
that utilities are able to rely on that dispatchability
and load reduction.
And particularly in Arizona,
they are hit significantly throughout their programs
over the last 18 months.
We've had a long standing program with them,
but with some of the new clean energy standards
that they put in place on wanting to ramp up renewables
in their portfolio, they put a big stake in the ground of,
we want as much demand response as we can possibly enroll.
So we are doing everything that we can alongside APS
to get as many of their customers
in their demand response program as possible.
And what we're interested in doing is what could we be doing
in the Texas market to set up that those same incentives
for partners to want to be going as big as they can
in the demand response market.
Right now, that's just,
isn't happening outside of the big programs.
Next slide.
So the customer experience itself first of all,
just so that it's perfectly clear,
all of our programs are opt in.
None of our demand response programs
are just happen on their own.
So customers are making the decision
to go to an enrollment page.
It's pretty similar like what you see up here,
there's typically a landing page
either on the web or mobile
where they learn about the program
and learn about the incentives also agreed to
the customers terms and agreements.
And that's important because there's a fair amount
of data sharing going on between us,
the aggregator partners,
and the program evaluators that are actually
doing all the evaluation of the load reductions, et cetera.
The part of the reason that customers enroll
in these programs, as we've mentioned,
are for the incentives so they can be steep.
Think CPS's program right now is $115.
But they'll also ratchet that up from time to time
during the year end to boost incentive.
So it could be a $150.
Over this year,
we've had 30 plus programs where customers
can get free thermostats from the utilities
as long as they weren't enrolling in programs.
So the value is definitely there.
The market for smart thermostat adoption
and for demand response adoption is still relatively low.
Back when I started with the company,
I was signing thousand unit pilots
that we are well beyond that stage.
All the tools are there for the market
to really start accelerating these benefits in market.
They've had multiple years of practice
learning techniques to figure out how do they work?
What do we need to make happen to really accelerate them?
On the bottom here,
what you're looking at is a utility marketplace.
It's effectively a white labeled e-commerce website
that utilities host.
And this is how many of our partners are actually enabling,
sign up and get a free thermostat from partners
in the way that they do that for customer.
If they don't have a smart thermostat already,
as you go to ABS's website, log in,
get all the incentives upfront,
and then we ship out a thermostat that's already enrolled
in the program.
They still agree to the same terms
and conditions regardless.
So they still know that they're getting into it,
but it's the number one way
that all of our utility partners are
dramatically accelerating
their programs significantly.
During an event itself, we also have Customer UX as well.
And that's what you see on the right-hand side.
So you'll see it on the device itself,
not the head unit.
It'll display information like that.
If you just walk past the thermostat,
you'll see that little gold gear,
that little gold gear means we're doing something.
So something is going on in you can click in
and learn more about that.
But we also send notifications in their app.
And most of all of our other partners,
whether it's utilities or not
also send their own communications to customers as well,
so that they know what's happening during those events.
We see very high customer satisfaction with our programs.
And that's something that we're really proud about.
We do regular net promoter scores for our programs,
and those are consistently very high.
And when you think about it,
that shouldn't really make sense
from just the fact of it's hot out and work turning up
your air conditioner, but customers do love these programs.
It provides them a way to give back to their community,
help with climate change and earn money in rewards.
So that's the kind of the key thesis
that really makes them make these programs accelerate.
The other key question,
I get quite a bit from regulators,
reporters, et cetera, how reliable is it?
And do customers get fatigued on events?
And the short answer is no, as long as it's automated,
simple and easy in your, and you're paying,
customers or boards.
If it's a pain in the ass and it's complicated
and they're hot, no, it's not.
So a lot of the call to the call the conserve programs,
whether it's ERCOT or California with their programs,
those don't work customers don't like those.
But when they enrolled in programs
where they're getting paid, it's set it and forget it.
They don't have to worry about it.
It's just happening in the background.
We see really high customer satisfaction.
-: Short duration, that's kind of key to that, too, right?
So that temperature really,
they're not feeling the fraud border will go up
and that sustained- Aaron: Yes.
The highest impact that we see are shorter events,
whether that's an hour or less.
Many of our partners will run for our events.
And similar to the chart that Reliant showed you,
you will see some step off towards that end.
If you ran an eight hour event,
I would not expect our eight to perform as well as our one.
But very similar to what Rick from CPS energy said is,
and I hear the same thing from every one
of our other utility partners is we've run so many events.
We have such a big portfolio of customers.
We know what to expect when we hit that button.
So that's one of the key things that I wanna make sure
that the Commission is aware of.
It is reliable, it's dispatchable,
and you need to run events to know what's gonna happen
on the other side.
But once you're running events,
all of our partners know what to expect,
and they either,
they're either bidding in a portion of that load,
or they just know what to expect when they hit the button.
-: To be clear on two things,
the averages are reliable 100%.
But there's still averages
with a discount factor of total installed.
And more importantly,
I want to make sure to clarify that this Commission
does not think of demand response as boiling frogs.
(laughing)
Aaron: I didn't say that.
(laughing)
McAdams: I don't know if she wrote it down.
Peter: Clarify it,
not how we consider (indistinct) customers in such trouble.
-: Next slide.
Yeah, thank you.
So some recommendations from us and we started
out today wanting to highlight actionable change
that could be impacted now.
And that the first bullet point
is what I would consider the clearest action
will change it's in your jurisdiction
is one increase the cost cap in value paid per KW
in the TDU program in the same with the ERS program.
Increase the cap, but also importantly,
also increasing the ERS payment to be more in line
with the value delivered.
Right now, the ERS payment.
And I'll just clarify it.
Google does not participate directly in our cuts market.
So I'm not 100% experts on all this.
I've learned this through our partners.
But on average ERS will pay
for like a 30 megawatt portfolio,
something like $13 per KW for the summer.
So for that partner, it'd be $360,000.
That's not zero,
but typically when events are called,
prices are also usually high.
If in that say,
if it was a two hour event and we're at $9,000,
that's $220,000 for two hours
compared to 360 for the entire summer.
So what we consistently hear from our partners
is there just isn't enough juice to squeeze
in the Texas market to make it profitable enough
so that they can also provide decent
enough customer incentives to get the customer traction
that we need in market.
So in terms of actionable change,
that first one I would say is the most important
for the Commission to be exploring.
McAdams: And is this by nature of cause you're right,
it was in several comments,
is this by nature of the saturation of the amount
of bids that drives down that value?
Aaron: That's a great question
that I do not have an answer for (laughs)
But that is something that should be explored
to really understand that dynamic.
The second bullet point that I have here
of recommending that the Commission set a DR goal
is something that we've consistently found time
and time again, has worked for all of our partners
that want to aggressively grow their portfolios.
They put an aggressive goal out there.
I'm not an expert enough if that should be
a goal on the TDU programs, ERS programs, REP programs,
et cetera, but we should be setting a goal out there
and then figuring out the right mechanisms to hit that
and really putting, putting programs in place to do that.
The last bullet point,
I do firmly believe that the demand response
has a ton of potential in Texas.
I can also, through this discussion,
know that there's a lot of questions
on what that potential actually is.
So I think that there should be a demand response
potential study completed.
I also added with the exploration of creating additional,
an reliability ancillary services,
specifically focused on demand response.
If we're not getting exactly what we need
through the ERS in TDU programs,
let's design a new ancillary service
that does drive the reliability
benefits that the Commission is looking for.
I put that at last,
cause I realize that might not be a short term thing.
Action items, number one.
But I do think there should be some longer term studies
to really figure out what could be doing.
'Cause there is a ton of potential
and we are barely scratching the surface right now.
-: All right.
Thank you, Mr Berndt.
Aaron: Thank you. -: Appreciate it.
And to bring us home, Silver Stain.
-: Hello, thank you for having me.
So I'm an independent consultant.
My comments today are as an individual.
I'm not gonna make or lose any money
depending on how y'all decide these policy calls.
So I'm speaking solely for my position as a citizen
with decades of working on these issues
to support reliable grids in the public interest.
And so what I'm gonna,
I was thinking about what is it that the last speaker
after for really long day can say
that hasn't been said before?
And I decided that maybe the value I could offer
was kind of a summary and a cheat sheet
to wrap up everything that we've heard.
And so I was looking over through all the 40 plus comments
that we received and my first summary look kind of
like the next slide please.
And I want to tell Canon and the folks who are with him,
how much I appreciate getting me to bingo on
by 1130 this morning.
Thank you.
But Amy and Enchanted Rock,
I'm really disappointing you didn't give me (indistinct).
Let's try harder next time.
There are a few other partials in it
for if you don't know what Sneakernet is,
'cause y'all are new to that.
That is when an aggregator calls up a commercial
or industrial customer that is not yet automated.
And so they send someone around some
plea working around, running around the factory,
turning things down.
And that's what Sneakernet is
for old fashioned DR Providers.
So a lot of
what we heard today in some of the earlier stuff
and a lot of the comments
are a lot of acronyms and not a lot of content.
So I though I would back up and give you some summary.
Next slide, please.
The first two things that you should take away from this,
I think are that demand responds
and energy efficiency deliver a ton of benefits.
I'm not gonna read them all,
that's the point of a cheat sheet.
And then the second thing is that,
demand response and demand flexibility,
there are a zillion ways you can use this.
But your rules and are written around mostly T shade,
huge problem.
You could be using as many of the speakers
have talked to you about low shifting a variety
of ways for that,
bill and portfolio management for the customer,
as well as for the REP and the queasy
to present a better portfolio to the market
and hedge prices.
There are about a million different ancillary services
and reliability services that could be provided
and improvements using this.
The thing that I want to highlight here
is we've heard about demand response
and energy efficiency potential.
The first thing I wanna say is,
yes, this is the demand response work session,
but what several of the comments have told you,
and what I need to repeat is that energy efficiency
and demand response are complimentary.
The more energy efficiency you have,
the better demand response performs.
And frankly, there is so much energy in Texas,
that you could do energy efficiency all day long
for decades,
and you will not destroy the potential of demand response
to help the market work better and to help keep
the grid reliable.
So two things on energy efficiency actual potential.
Energy efficiency used to be designed
and is still often assumed
to be about saving kilowatt hours.
It is entirely possible to target
energy efficiency specifically for winter
and summer demand reduction peak reduction.
And we know that 40% of ERCOT winter load
and 50% of summer load are specifically weather driven
so that there is a massive opportunity
to use both targeted efficiency and demand response
to fix that.
One of the demand response providers I talked to
told me that at least 15% of industrial load
and ERCOT is moveable.
That's 10 gig right there.
The American Council for an Energy Efficient Economy
of which I'm on the board is doing a study
of the impact of,
potential impact of energy efficiency
and demand response measures targeted at winter
and summer peak reduction over the next five years.
In other words,
what can we get fast if we wanted to max out,
do a lot of high scalable efficiency and demand response.
A preliminary estimate is that we can get
well over 10,000 megawatts
of winter peak load reduction
and another 10 gig of summer peak load reduction.
And that's only five years.
A limited number of measures.
And that's only from residential customers.
That report will be out next month.
It is not the thorough kind of detailed technical
and economic potential study that many of these folks
are advocating you to perform in
an I too advocate that you perform.
It should give you some reassurance
that there is some massive potential out there
and you should not waste it.
And by the way, all of this is at an average cost
of about 2 cents per kilowatt hour,
which ignores does not include all of the additional savings
that you realize from not having to buy
in an incremental to 18% over that,
but for additional generation for line losses
and reserve margin, nor do you have to pay for fuel.
And you're also saving on customer bills
and health and pollution and significantly improving equity.
So that's about potential.
And you can also use it for geo targeting.
So a lot of the concerns that you have
about the lower Rio Grande Valley, for instance,
and those transmission constraints
and the equity issues associated with that,
could be addressed in ameliorated in part
by efficiency and demand response.
You will still need to build trans transmission
there sooner later,
but at least you can make the situation significantly
better and less painful in the interim
before all those lines get built
or all that generation shows up.
Next slide please.
So the other thing you've heard pieces about today
from different people is how to structure demand
risk products,
and whether they're control or pull or dispatchable.
So think of this slide as some of the design parameters
or the knobs that you can turn and mix and match
to design products that suit your reliability needs
and, or your customer and technology capabilities.
Some of these elements and iterations include time options,
like when to use it.
One of the things that I put in here that's misleading
is I wrote event lead time.
But what I really meant was more like speed of low drop,
which is a compliment to the amount of advance
notice that you need.
Like, do you get a day ahead warning that,
I hear to a day at five that I need to drop tomorrow
at five.
So lead time versus speed of response
are two different factors.
A ton of management options.
You've heard about price responsive,
aggregating, and automated,
like smart thermostats direct load control used to be
the fabulous thing.
And it's still used for stuff like pull pumps,
but much in Texas anymore because most of the equipment
broke and we have moved beyond pagers in doing dispatch.
And you know about the effectiveness of automated
relay operation for under frequency relay.
Although again, Canon, I bought was hoping,
I had money on you saying frequency response.
(finger snapping)
(laughing)
You've heard about a variety sources
of where do you get the load shift
or the load reduction from,
you have heard about who gets to be in charge of the use.
And you've heard about different issues
associated with compensation.
The thing that I didn't put on here is when it gets used,
and that includes examples like peak,
net load peak, or for valley filling
or for doing fixing the solar ramp down,
filling in behind that.
Next slide, please.
This is my summary of barriers.
It doesn't include most of well, 99% of deep,
the kind of fabulous detail that we got from Michael Lee.
But in my view,
the barriers around this are an over narrow view
of what the purpose of demand response is.
Because the capabilities of demand response
and efficiency have changed so massively,
our views of how to use it should be equally expansive.
Barriers around compensation and cost restrictions.
You've heard a ton of detail about.
Some of the most frustrating barriers
are about restrictions on participation,
what customers can do it,
what kinds of who's allowed to offer demand response,
who's allowed to be in what product, et cetera, et cetera.
The TDU efficiency goals are way too low
down and of itself is a participation restriction.
And the last set of restrictions are arise from technology.
And you heard examples about metering
and about customer access to data
and aggregator access to data.
I want to offer a couple of observations
that are sufficiently tacky, that I didn't write them down.
So instead I'm going to say them
in front of an archive livestream.
The first is that most of these barriers
reflect historical outdated assumptions
about what demand response in DR are capable of doing
or what TDU and ERCOT are capable of doing.
You guys have computers, you have the cloud,
there is no excuse for there being a limit on 3000 calls
to a TDU per per month.
That's insane.
The second is that most of these barriers
have been into rules at the PUC and ERCOT,
and a lot of those have been initiated and or promulgated
and or enforced through slogging
through the ERCOT stakeholder and governance process,
that essentially is dominated by TDUs and generators
and large industrial customers who are profiting
from the current system of high prices and scarcity
and high throughput of energy.
And if you do things like allow more demand response
and energy efficiency,
you're gonna take away some of their bread.
That doesn't mean...
so they have been very effective at freezing
out a lot of changes in rules that do not protect
their price spikes and their throughput.
You have the capability to change that.
What we have done in archive is we have created
a wonderfully effective market for competition
between suppliers.
We have ignored the fact that the most effective markets
require competition between consumers suppliers.
So this is your chance to recreate that market.
By the way,
anytime someone complains about price formation,
what they're really complaining about is that the fact
that the price formation that is working,
isn't giving them high enough prices for their taste,
but consumers are an important part of price formation.
Next, please.
This is a summary of the most common demand response
and demand flexibility recommendations.
Because it's my slides,
these are the recommendations that are both common
that I agree with,
and that I think are sound public policy.
(laughing)
So it excludes the ones that I think are not a good idea.
These are big picture and they are not super detailed
and the way that many of the other speaker have phrased them
has been much more detailed and or elegant.
So this is just sort of,
I'm not gonna read most of them
because you already have heard the mag nausea
and you're welcome.
The only one I wanna touch on briefly is number six,
rethink resource adequacy meaning in math,
nobody's really talked about this.
We designed the paradigm of resource adequacy
under the old world,
where you have generators that you control
and customers who you don't control.
And the generators,
the supply a always has to be there
because you never know what those darn customers
are gonna do.
Yet today, we have a grid that is changing,
where as our colleagues have demonstrated,
customers capabilities and willingness
to consume electricity is deeply manageable
in an incredibly sophisticated and not frustrating ways.
If you use the right technology
and treat your customers with respect.
It is supply that is becoming intermittent
and variable and risky and infirm.
And so our job today is to figure out
how to use customer capabilities,
including all this behind the meter generation
and storage and their willingness to move
around loads enabled by technology and decent treatment.
So manage customer stuff to meet variable supply.
Don't keep thinking you need to move supply to meet demand,
move them both to complement deep other.
So all of the math,
every time someone talks about every time Woody Rick
talks about you with reserve margins,
Woody is talking about a paradigm for 10, 20, 30 years ago,
and it is not relevant to where we need to be going.
Now, I can tell you that the math of how to do resource
adequacy is hard,
given things like ELCC and all of the uncertainties around
can I build transmission fast enough for generation?
What if there is a two week long reduction in PV
or what if the wind doesn't blow for this period of time?
So it is not easy,
but I am here to tell you that it's a lot easier
if you assume that customer load can be counted on
for a much more important role.
So I wanna close with a couple of ideas for you.
The first is actually, it's only one, but it's a big idea.
You asked Mr. Chairman if we attributing it
to Commissioner Glotfelty,
which I thought was really clever.
If we design, if we designed the market correctly,
it's a common political thing is blame someone else
for the question you're about to ask, but it's okay.
If we redesign the market correctly,
do we still need to fund TDU energy efficiency
and demand response?
And I want to give you four answers to that.
All of them align with yes, you do.
And you cannot afford not to.
The first reason is about luck.
Are you feeling lucky?
You guys are undertaking the world's fastest
electric market redesign.
These are incredibly complicated issues,
and no one knows how to do this,
which is why they're all taking a lot of money
to tell you how you should do it.
You cannot afford to let load keep growing
while you wait to see if all of the redesign works
and all the pieces fall into place quickly,
and load is growing wicked fast in taxes as you know.
Energy efficiency and demand response,
give you defense and depth.
They give you diversity of tools
and they will help to buffer reliability
and reduce the need for all of that addition generation
and all the folks you wanna come spend money
on capital and Texas to show up
and get through the interconnection queue,
which by the way you can't fix in the next year or two fast.
Peter: Or we can change it.
Silver: I know you can.
The question is how fast between when you
write the regulation and when the cash shows up
and the infrastructure's on the ground,
and that you can't change.
The second factor is cost.
Bear in mind,
energy efficiency and demand response are the least costly
resources available relative to all that generation
and all that storage.
So you need to save Texans money.
And the other thing is that energy efficiency
is gonna protect Texans when the grid fails
and no matter how good you do on redesign,
the grid is gonna fail.
Every hurricane,
every snowstorm tells us the grid is gonna fail.
Lightning customers are always gonna be in the dark,
energy efficiency is gonna keep 'em alive.
The third factor is equity.
Markets are not kind to low income customers,
and they don't deliver equitable outcomes.
Uri pulled a lot more low income and middle income customers
than they did well to do customers who
are now calling up Amy to buy PV and storage.
So they will be protected.
So the well to do customers are gonna to be protected
for a long time because they can afford the storage
and the distributed generation
and the food and the water in advance.
But it's the customers who are freezing in (indistinct)
whom we can deliver energy efficiency to,
and who will participate in demand response programs
to protect reliability as well as protecting themselves.
And frankly,
energy efficiency is about the only energy protection
most low income customers get out of these markets.
The last factor again, is risk reduction.
Energy efficiency almost always works.
You change the light bulb,
it's always gonna be a low efficient light bulb.
If you put in window better windows for weatherization
or a more efficient air conditioner,
it's always gonna work.
It's always gonna reduce demand.
So it's always gonna be delivering better reliability
for you and lower peak demand.
And it's not likely to break .
If it breaks,
it's not gonna have the same consequence
for the grid that a power plant breaking will,
or that loss of gas supply,
or loss of distribution lines or transmission lines.
So you need to use these measures as ways to reduce risk
and diversify the tools to operate the grid
and protect reliability for all of us as a whole,
not just put 90% of your cash bet
on the generation side to work,
cover that bet by making an even a fraction of that.
Some invested in energy efficiency
and demand response will deliver massive long term benefits
in terms of grid reliability,
and let you keep your promise to the people of Texas
and the politicians of Texas
that you're gonna keep our lights on.
Thank you.
Peter: Thank you, Mrs Silver Stain.
Can't imagine to see...
I'm both intrigued and terrified
to see the slides you pulled.
(all laughing)
And thank you to our entire panel.
Any final questions or comments for our our panel?
All right.
Well, it's certainly been a full day of demand response,
distributed generation, et cetera.
Thank you all much.
That concludes item number four.
(laughing)
And we're gonna jump straight to item number 21,
project number 52373,
review of the wholesale electric market design
Commissioner McAdams says filed a memo.
We'll turn over you.
-: Thank you, Mr. Chairman.
I wanted to take this up today and provide an opportunity
to unpack some of the concepts in the memo has stated.
I urge the Commission to consider this and these concepts
for our next open meeting for possible action.
And let me tell you why.
Because I think, and this is where I'd love feedback,
but given the conversations that we've had
over the last several workshops,
which have been incredibly productive as stated
in the memo,
there are common themes that are emerging
in terms of potential action near term action.
Among the common themes are are issues
that do have relevant rules that are already in place
that would necessitate change.
In order to engage and open up a proceeding
and follow the normal comment period
and procedural glide path would take four to five months,
if we were to do that on September 23rd,
that would put us in January or February.
Of some of the common themes that we discuss
at our workshops,
a lot of them will impact price formation
in terms of the forwards that will impact the summer of 22.
And as per the market custom of ERCOT,
that is right in the prime season when
retail electric providers non opt opportunities,
all market participants go to market and start
purchasing their hedges
and positioning their hedges for peak.
So with that in mind and as context,
that's why I chose some of the topics that I did
for action and related to the two relevant rules
that we have in the Texas Administrative Code.
And again, among those, that's why,
I'm kind of opening up some of these topics for questions,
whether we move the high cap from 9,000,
should we decouple the system wide offer cap
and the high cap?
And I have thoughts on that,
but we'll loves yours,
should we change the value of loss load,
which I believe was certainly implied
during the last session and what should be that number?
Should we change the ORDC now, again,
this is a on thread that has reoccurred
through all our proceedings.
Do we as a Commission have to adjust the curve,
or do we just look at extending
the minimum contingency level.
The MC away from 2300, which again,
is that trigger at EEA1.
Now as part of that, what numbers would we consider?
And again,
the reason I wanted to bring this up now
is because concurrent to ERCOT efforts,
they are working with groups potentially
to study significant issues that could do back cast for us.
This would be a relevant time to throw scenarios out there
for them to consider certain numbers
as a back cast model to show us the impacts.
And again,
all that lines up with the ultimate decisions
that you, Mr. Chairman, urges to make in November.
-: December, correct.
every 30 days counts.
-: That's correct.
(laughing)
I don't wanna squeeze in 'em up on you.
And then you get to the emergency pricing program.
It is certainly articulated in black letter of law
as of section 18 of Senate bill three PRA 39 160
that instructs the Commission to establish
an emergency pricing program.
And under that program it goes into effect
the high cap a has been in effect 12 out of 24 hours.
The EPP cap cannot exceed the system wide offer cap.
Also it establishes an ancillary services
cap to be in effect during the EPP,
which cannot exceed the system wide offer cap.
Now for the purpose of our system,
that's significant considering the risk
that those being into ancillary service is incur.
So if you can't exceed the system wide offer gap
we have to compute something differently.
The OCAP may not exceed under that law
the system wide offer cap.
And we've gotta review it once every five years.
And then we've already changed the way generators
are reimbursed for verifiable operating costs in our rule.
So just to kind of put a frame around this
and where I'm thinking.
Look in terms of our conservative operating doctrine
that we have embraced this summer
and looks like we'll be needed moving forward.
The MCL should be studied at the least.
And we should look at that because again
with that everything advances a whole arsenal of tools
move forward and would have to be revalued as well.
So,
we need time.
And so that's why I'd like that considered.
I am not inferring as per my memo that ORDC be captured
in a rule.
Although I believe people,
stakeholders will comment to that effect.
But the components system might offer cap
high cap that are clearly articulated and joined right now
in the rule need to be taken up and broken apart.
So while we're doing that,
we might as well take a ORDC as integral consideration.
And in terms of tack 25, 507,
the emergency response system,
whatever changes we make there, again,
concurrent with that MC decision,
if one is to be made and as ERS should it move
out of EEA one or EEA two functions should it happen,
auctions are made on ERs quarterly for quarterly contracts.
And for example, if you wanted to affect ERS for peak,
that auction would be officially closed on May 16th.
So whatever changes we make would be in time
for those financial decisions.
-: So next summer.
-: Yes, sir.
-: To impact next summer.
-: So with that, I would open it up for your thoughts.
-: A clarifying question you,
the action you were considering asking us to consider
for next meeting would be opening these two projects.
-: Yes, sir.
-: Okay.
Questions, comments for Commissioner McAdams.
-: I have some, but I will let you go first.
-: Go ahead.
-: Okay, I think it's no secret that I've been
wanting to open up world making project
for the last couple of months.
(laughs)
Showed up wanting to open up world projects.
It's what I do.
So okay.
So I'm all about starting to send price signals
as soon as possible.
And I agree that we do need to study the ORDC
with the third party independent consultant.
And in addition to the minimum minimum contingency level,
or the X factor is often referred to
by the stakeholder community industry,
I think we need to look at the curve being
shifted potentially,
and the price cap or variation of price gaps,
and have backs conducted on a variation
of already see changes, the price cap,
the curve X factor slash MCLE.
And I think as part of that evaluation that I think,
'cause I'm not sure where we are right now
with respect to what price caps we wanna look at
and whether we want to shift curves.
I know Commissioner McAdams definitely has suggested
that the MCLEs needs to be looked out an increase
so that we could start sending price signals earlier.
And so I think as a Commission,
we need to decide what we want the third party
independent consultant to look at.
Run those back analysis, arrive at a price cap,
and then plug that into the role making .
And I don't know how you're envisioning
the timing Commissioner McAdams, but it seems,
I mean, I think we could open that project,
but I think we need some analysis
before we even get going with the project done.
And I agree that we may get some recommendations
on what to do with the ORDC,
whether we put in the rule or we don't put it in
the role and you continue to operate with a framework
where we give directives and implements it.
And I think from my perspective,
and I know you're not suggesting that,
but I think that the framework we have right now,
which is the Commission giving ERCOT a directive
to make RDC changes in ERCOT,
making those changes via NPRs and then system changes,
whatever it is that they do
has been a very nimble action we've been able to take.
And I don't think that,
and I know you're not suggesting this,
but I'm just speaking to the other option,
putting that in rule is gonna help us when
push comes to shop and we need to send
or price signal relatively quickly.
But I know that we have to open the rule
because if we change the price cap,
we have to change the, we have to change it in the role.
So with that being said,
I don't disagree about opening the rule.
We have to open the rule for a variety of reason.
I'm just wondering the timing
and when we're gonna be able to take action.
And I don't know if we have anything in mind
on that necessarily.
With respect to ERS,
I think we heard a variety of comments today that I agree,
I think out of all the demand response programs
that one needs to be opened and it's an existing role.
The only thing I will say is that and I know
this probably was against what we just heard,
but we need to be looking at both sides of the equation.
No doubt.
And so what I'm about to say doesn't mean
that we shouldn't be looking at load,
what I think the legislature has made clear,
and so as the Governor is that we need
to incent dispatchable generation.
So I wanna make sure that we are sending those signals
through ORDC through giving more direction on AES products.
And I think the next workshop will probably be,
or maybe this next open meeting,
I don't know that I know we've had some discussion
about whether or not ancillary services
belong in a PUC role making home or not.
But I do believe that at least with respect to
specific AEs products,
we should consider putting at least the parameters
in a rule.
And I wouldn't want us to wait,
if we already have an idea that a certain product,
like a firm fuel holding product is necessary,
then why not open a project and start getting more
detailed information,
and then drop that information to the product project
when it's timely.
Because I do think that we need to start sending
price signals for generation investment
sooner rather than later.
And so
that's where I'm at right now.
Do you wanna speak to that?
-: Makes sense.
And I think the, over my interpretation of
these proposed project openings are one,
we need to be ready to implement.
Well, one, these is opening projects on I guess,
levers we can pull that are already in rule
that will require by definition rule change.
That does not mean it excludes other levers
that we can pull like a new as product
or changing the queue or any others.
It does not exclude that.
But my understanding,
my interpretation of what you just laid out is this
just gives us the groundwork to be ready to implement
those rules once we figure out the blueprint in December.
And that's ready.
And so those,
the things we know that we have to change and rule
to the extent we decide to change 'em,
we've got that process, that's open.
For things that may,
we may or may not TBD,
say as I think those topics and those levers,
or what we're willing to consider,
what we're not willing to consider are going to
crystallize very rapidly,
starting with our October work session.
And then as we move through November,
that's gonna get even more clear
about what's going to be part of the December blueprint
or not.
And so I would say,
let's certainly prepare for the event that a new tool,
I guess might be in
something we would do wanna put in rule.
But I would propose,
we at least wait until that October work session
and then so we can crystallize
on exactly what kind of AES we wanna do.
And if we want to
put that in rule or leave it at the level,
and also remember concurrently, we've got new governments,
that's gonna be coming on board at the same time,
which rule also inform how we approach all of these things.
-: Right.
And that's actually how I was thinking about it in timing
was that I think we still need to gather
some more information in this next October work session
to help us scope out
or refine our focus on what new products
we would be interested in moving forward
with what specific RDC changes we would want
our independent consumer to back and model.
And then also I think today we got a lot of information,
I think Commissioner McAdams laid out some points
that change in ERS,
I think those are two starting points
and probably others to look at when we open up the role.
The other existing role that we didn't discuss
was the TDU load management program.
And that's also an existing role
that we may wanna consider opening up as well.
-: You consider adding that to the topics.
-: Yes, sir.
-: And the timing,
I'm not suggesting the time and maybe one that we open
that part of the menu.
-: Sure.
And I think for October, I think we'll be
the last work session we're taking and information,
but also feel free to start preparing,
to lay out suggestions and really clarifying thoughts.
I think we all should be prepared.
We'll still be taking information for stakeholders,
but that's going to be the inflection point
where it shifts to starting to lay out
and bet amongst us and with the public
and with our stakeholders start betting very specific ideas.
-: And one also thing I would point out that I omitted,
but as per the October 14th workshop,
we have studies coming for us from generators,
as well as (indistinct), will they be there?
-: Not yet.
But at the least it kind of helps inform
their thinking on in terms of the ORDC near term,
what we are considering as a framework.
And they could come and actually OPPI
on that a little bit might help that
-: I would also like to get their opinion
or get more info on decoupling of the H cap and the qua.
That's definitely something that I think
we need some further analysis of by Brad
to see what the opportunities and cost may there.
-: Little bit while we're still on it,
a little bit of history.
And we've been bouncing around when the the old MCL
was settled on and jump in here when y'all are watching
this stuff move through.
But 2750 I think was discussed at the time.
And this was again 2014.
2750 discussed at the time
and I, that's why these studies are gonna be so important
because depending on the low level,
you're talking about real money
and the frequency of events cause dropping it down,
it increases the, the probability of ORDC being activated.
And so that a starting point,
if we go all the way back to 2014,
when at the time was 12,000, megawatts on the system
no solar, and now we're at 31,000,
it just puts it in a scale in terms of the resource mix,
how things change.
And as these generators are sitting
there watching this and as they're gonna introduce
their study, just a a poll for them to look at,
where where's the starting point?
2300, maybe inadequate, where do you go?
-: Right.
I think that makes sense.
Looking at variety of X factors above 2000.
-: Okay, so that's all
-: Dito, Dito and Dito.
-: Well put, that's always a popular response.
So I think where we're triangulating towards
is considering opening projects on levers
that are currently possible levers on market redesign
that are currently in rule, including the DR load shift,
low management program.
And then as we move on our next open meeting
in between now and our work session in October,
we'll receive the studies from our third party stakeholders
well before that October work session.
So we Commission will have a chance to digest
and then of course discussed and debated
at the October work session.
But come prepared to the October work session
to consider opening a project or projects
on other levers of market redesign
that are not currently in rule,
but that we may want to consider in rule.
And so at that point, we, we will hopefully
have a much narrower scope of what we would consider.
And then we can take up the market redesign levers,
not currently in rule that we may want to put in rule
at that time.
Does that make sense?
-: That makes sense.
-: Yes, sir.
-: Now we're not adopting anything at this time.
We're gonna vote a decision next time in spirit.
-: And I do wanna say that I did put
out the TD management rule or 25, 1801 out there.
Only because it's an existing rule,
but I guess we need to decide
if there's any general direction we're headed
to making change just that little, if any, before...
-: Well, I think it opens up and we're gonna
have the discussion anyway.
I think this is in many ways a procedural angle
of the groundwork or setting up the framework
for official action they take later.
-: Yeah, that's right.
One of those things (indistinct) TDU programs
some are only status right now.
That is low hanging if you were just provide focus.
(indistinct)
-: If I may just wanted to lay out particularly
for those who might be following on the viewers,
there's a distinction between opening a project
and opening a rule.
So when we open a project,
that's kind of a an organizational tool
to keep our thoughts about a particular topic
and let's folks know where they can participate
and give their views on that project.
And then opening a rule is an actual vote
as Commissioner McAdams mentioned
that you will take an open meeting to propose
specific changes to one of our rules.
So we can open a project at any time you would like,
and there's no deadline for us to come forward
with that rule.
We can continue discussing
the topics within the project
until you're ready to propose.
-: So on the two outline in the memo,
I would propose opening a rule making subject
to the the parameters,
the issues and the vault and out outlined in the memo.
But again, and correct me if I'm wrong Connie,
is as comments come back,
the Commission can always sort of within the parameters
and scope of the rule making go further afield,
subject to the parameters.
Connie: That's right.
You can take in comments consider those
and use that input when you draft the actual
changes or amendments to the rule.
-: Correct.
But you're still touching on those topics
which are foundational.
-: No, absolutely.
And I understood your products to be rule making proceeds.
I mean, they're existing rules.
-: So you're ready to start the clock
with opening rule making on those.
-: Yes, sir.
(indistinct)
-: Next week.
And we'll do the same,
considered the same for October,
for levers not currently enrolled.
All right.
-: Makes sense.
-: We'll look forward to any further discussion on-
-: I was just gonna say thank you for the memo.
I think we gotta get going,
and I think I think the market Commissioner club outside
the market signals need to be there.
So let's go.
-: I wore my tie.
(laughing)
-: I was thinking about moving this
to the front of the agenda,
but I wanted to make sure you kept your tie on all day.
All right, good for the day.
All right.
Now we will not meet in closed session.
So there being no further business, this meeting,
the Public utility Commission of Texas is hereby adjourned.