(gavel pounding)
-: This meeting of the Public Utility Commission
of Texas will come to order to consider matters
that have been duly posted with the secretary
of state of Texas for September 16th, 2021.
For the record, my name is Peter Lake
and with me today are Will McAdams, Laurie Cobos
and Jimmy Glotfelty.
As y'all know, this work session is primarily devoted
to the ERCOT market design features
and a proposed rule addressing continuity of service.
So unless any of my colleagues wants to discuss
any other posted items,
I don't think we will be taking up items one through three
or five through 19.
So then I know you've got a memo 21 think.
-: Yes. -: So, four, 20, and 21.
-: If I was to make a public service announcement,
would I do it now?
-: Sure.
-: So staff has nominated me, since I open the door to this,
as the public service announcer for the PUC.
-: Congratulations. -: Thank you.
And, but I would like to take a moment,
to especially recognize Kristen Abbott of Commission staff,
and her retirement.
After 10 years of public service,
she did a heck of a job for the Commission over that decade,
and she'll be sorely missed,
but I just wanted to tell the world
that we're gonna miss her and we appreciate her service.
-: Well done. Thank you from all of us.
-: So should we just let you know
all the announcements we need to--
-: No! No.
(everyone laughing)
-: But that comes with good and bad.
-: It sure does.
-: I have a couple of announcements, Will.
-: Like I said, congratulations.
-: Thank you.
-: We're gonna go out of order today on our agenda items,
we are gonna start with item number 22,
accommodate all stakeholders schedules
related to critical natural gas facilities and entities.
For this item we're joined today by Wei Wang,
Executive Director of the Texas Railroad Commission.
He and his staff have worked together
with our Commission staff in repairing rules
related to critical natural gas facilities.
So, first of all, I wanna thank you.
Good to see you.
Thank you and your staff for engaging
on such aggressively-paced rulemaking
in such a critical topic.
I know it's been a lot of, a lot of work very quickly.
So I want to thank you and commend your staff
for establishing such a good working relationship
between our agencies.
So with that, I'll turn it over to you.
-: Thank you.
Good morning, Chairman Lake and Commissioners.
For the record, I'm Wei Wang,
Executive Director of the Railroad Commission.
Glad to be with you this morning.
I think once SB3 was signed to law,
the two agencies work more cleverly, closely together
since late May, early June.
And first of all, I'd like to thank you
and your Executive Director Thomas and his staff
were working closely with our agency.
We worked very aggressively during the last few months.
Thomas and I had a weekly meeting
to make sure we're on the same page
and we're moving forward.
Our staff had to meet either weekly or twice a week
on various issues from SB3.
So on this particular rulemaking,
I think the bill is clear
that the two agency, our two agency
should collaborate on this matter.
And not just on the rulemaking,
on other sections of the bill.
I'm proud to say that we have done that
and made a really good process.
So, in closing again, I just want to express my gratitude
and appreciation of your staff and your agency
working with us on this important matter for all Texans,
and available for questions if you have any.
-: Appreciate it.
And I know we all look forward to continued
good working relationship
and productive working relationship.
Wei: Yes, sir.
-: Questions?
Thank you very much. -: Thank you.
-: Thanks buddy.
-: I know staff has proposed or prepared a proposal
for publication for a new rule related to said
critical natural gas facilities and entities.
Mr. Smelcher, Smeltzer,
could you give us some background and get us up to speed?
-: Sure. David Smeltzer, Commission staff.
The first remark I want to make is sort of
for people who are listening to contextualize this
in our larger effort.
I think this is gonna be the first of a couple of phases
when we're dealing with critical topics.
So according to statutory deadlines of HB 3648,
this is our, this is our quick action.
Let's make sure that our electric utilities
have all the information that they need
from the critical national gas facilities
to appropriately prioritize them in future,
you know, load shed events.
But this is gonna be,
there's gonna be future rule-makings on this topic,
both to revisit these natural gas topics
after we have more information
provided by these Statewide mapping exercise
that we're working on,
and also we're gonna have to do, likely,
a more comprehensive, sort of load shed
while making the things about natural gas, water entities,
and all the other different types of entities
that qualify for critical status.
So this is but the beginning.
With regard to this rulemaking specifically,
I think there are two statutory objectives
that we're trying to accomplish.
The first of which is Senate bill 1876,
which essentially just adds
end-stage renal disease facilities
to the list of medical facilities
that have to be given priority during load shed
and power restoration events.
That's a simple, we took the line from the statute,
we added it to our code in the appropriate place,
sort of implementation.
And the second one, as we've mentioned, is HB 3648,
section two, which is our half
of the critical natural gas designation process
what Wei was speaking about a few moments ago.
Procedurally speaking, I want to clarify for parties
because there's a lot going on at both agencies.
The Railroad Commission adopted their proposal
earlier this week on Tuesday,
we're adopting ours today, hopefully,
and then there are gonna be a number of opportunities
for contributions in the future.
So the Railroad Commission has their workshop
on October 5th.
Our comment deadline is gonna be on October 7th.
Theirs is on November 1st.
And then the last two open meetings
that the two agencies have to pass this before deadline,
their last currently-scheduled open meeting is November 10th
and ours is November 17th.
So I will publish, I will file something
with all the deadlines in the docket
so the parties know all the different ways
they can contribute,
but for interest to stakeholders,
you really should be following their rule-making
and our rule-making
so you can see how the pieces fit together.
With regards to the contents of this bill,
it's, or excuse me, this rulemaking,
the way that it divvies up right now
is on the Railroad Commission side,
they designate the criteria for which natural gas facilities
are the ones that have to participate in this process.
And there is a setup to where sort of, like,
everybody's all in.
If you meet these criteria,
you're one of the critical facilities
unless you fill out an exemption form
to sort of take yourself off the list.
So that is how their winnowing process works.
And then the remaining folks that are still critical,
then have to provide information to our utilities
and they do so with, currently there's a table
that the Railroad Commission has developed
that has all the different criteria
that our electric utilities need
in order to make their load shed decisions.
One area that we are still looking for feedback on
and that we need to continue to develop
is how we want the information to flow to our utilities.
So for instance, our current draft has it being emailed
to the utilities and to ERCOT separately,
but potentially, maybe it should flow first to the utilities
then to ERCOT or different areas like that.
I think there are logistical ways
as far as how the information could flow,
that we are interested in comments on,
and we want to keep working with stakeholders on
to make sure that everyone's getting information
in a usable format that they can use,
and it has everything they need to make the right decisions.
So I think that covers the basics
of what we're trying to do here today.
I'm happy to answer any questions.
Peter: Thank you, Mr. Smeltzer.
Any questions or comments?
Jimmy: Nope, I'm fine.
-: So one comment, I would like to urge or ask both agencies,
I think time is of the essence right now,
and we all know that and are feeling it.
But I do think that once this moves forward,
as Railroad has adopted their PFP and we do the same,
that over the next few weeks a collaborative meeting,
and I don't know if the workshop's the right term,
but industry and staff get together,
because these are both complex industries
and we both recognize that,
and we don't necessarily speak the same language.
But those of us who have had experience
in a bit of both industries and or policies
around both industries
understand that it is highly technical,
and we need to be able to narrow this list down
so that we meet our reliability parameters,
meaning that we can roll outages.
And that does not mean hardening all of West Texas
or South Texas.
So, I just want to put that marker down
that we do need a practical exercise
in terms of how to prioritize key infrastructure.
-: I think that's a great idea.
We've had a really great time working
with Railroad Commission staff,
and we, I think that pulling in more industry
into that discussion can only help.
Will: Okay. Great.
-: All right, if there are no other questions or comments,
is there a motion to propose amendments
to substantive rule 25.52
relating to reliability and continuity of service
for publication and public comment?
Jimmy: So moved.
-: Second.
-: All in favor, say aye.
Group: Aye.
-: Motion passes.
Thank you, Mr. Smeltzer.
Thank you, Mr. Wang.
David: Thank you.
(man clears throat)
-: That brings us to item number four,
related to electric reliability.
As I hope everyone knows at this point,
we are focused on demand response and to some extent,
distributed generation today.
I know Commissioner McAdams has done a deep dive
into these topics over the last few months.
So particularly look forward to hearing from him today.
And we have a number of panelists
that will be addressing the Commission.
Before we dive into this expansive topic
that holds lots of opportunity,
I also want to make sure that we have
a realistic set of expectations about this conversation.
One part of the purpose today is to establish
or get a sense of the existing demand response activities
that are out there now,
and level set on what is currently being achieved,
especially on the residential side,
what is already being achieved
by price signals and market forces.
If the market can accomplish it,
we certainly don't need to regulate it.
And second, as we look ahead
to identify actionable changes
to PUC and ERCOT policy
that can remove barriers to leveraging technologies
and business models for demand response,
but the key phrase there being actionable.
Certainly don't want to limit the scope of the discussion,
but we also want to be realistic
about the PUC's jurisdiction.
We can't change building codes,
we don't have local ordinance control.
So we want to keep the conversation on topic.
And I'll say it again, focus on actionable.
Current opportunities with current technologies.
And we want to, I think we all want to build
or redesign the ERCOT market
to be a well-functioning enough market,
that new technologies and business models in the future
can be adapted into that marketplace
without us having to take action.
It should be a market, but we also want to be grounded
in reality about the actions that can be taken today
to drive change today.
So with that, I'll turn it over
to our first panelist, Mr. Ogelman,
with the introduction from ERCOT.
-: Thank you.
Good morning, chairman, Commissioners.
For the record, Kenan Ogelman with ERCOT.
So I'm gonna speak to you about demand response
and a little bit about distributed energy resources as well.
Now, just to kind of set the stage,
there are kind of two main programs
that are administered by ERCOT,
and there are several programs
that are not administered by ERCOT,
but I'm gonna talk about all of these in my presentation.
So the two programs that are administered by ERCOT
are the Load Resource program
where loads can participate in ancillary services
and the Emergency Response Service.
The non-ERCOT administered programs
are the TDSP Load Management Programs,
the Four Coincident Peak Load Reduction
that we see load make.
There is also a load that just reacts to price on the system
that they face.
And then lastly,
we see distributed generation react to prices,
and oftentimes that looks to us like load going away
because it could be behind the meter or, you know,
we only have real visibility into the transmission system.
Next slide please.
Okay, so on the administered by ERCOT programs,
we have load resources
that can bid into the day ahead market
and clear ancillary services.
We referenced to these as controllable load resources
or load resources that are capable of following base points.
So they can move from one level of consumption to another
based on a price signal that they're sent.
Currently, we have six CLRs,
300 megawatts of registered capacity.
I would expect this population to grow
because a lot of these are data centers.
And as you're reading in the news,
there's lots of data centers
moving into the ERCOT footprint,
either from a Bitcoin perspective or, you know,
simple need to manage data
from all kinds of high tech usage.
This category does not include energy storage.
We treat them differently than we do
controllable load resources.
Peter: When you say controllable load
following base points, that, to be clear, is that automated?
And is there a time constraint on that?
-: There is a time constraint. It's five minutes.
They have to be able
to follow instructions every five minutes,
but they could adjust their reaction either automatically,
systematically or manually if they chose to manage that way.
Peter: Okay, but when, when SCAD issues a command
to reduce load, on a C, controllable load resource,
how quickly does the control room
expect that to be implemented?
Kenan: So, if they're in a base point following mode,
they have to meet the same requirements that resources do.
However, so that's five minutes
just to make sure I answered the question.
However, they could also, you know,
load doesn't have to follow base points,
but they could still do that behind the scenes on their own.
They have that capability as well.
They don't necessarily have to bid into these programs.
Peter: Got it, thank you.
Kenan: Then we have what is described as
non-controllable load resources.
So these are blockier loads.
They can respond relatively quickly,
but it's difficult for them to come back
and, and follow another base point.
So this would be more like a industrial process
or something along those lines,
where they can react to the price,
but, you know, when the price goes back down,
they don't necessarily bring their a load back online
or back into consumption
as rapidly as a controllable load resource would.
Will: Kenan, as you're going through this,
can you also describe those trigger points,
when this is employed, EEA, and so forth
just for the public?
-: Sure.
So it depends on the service that they've bid in on,
and currently the main area that they can participate
is responsive reserve service.
So controllable load resources are qualified
to also participate in non-spin.
Just so you know.
So ERCOT tends to deploy non-spin early and in the process,
oftentimes before we get into an EEA,
there are potential price trigger points, and so forth,
but the responsive reserve is deployed
kind of at the very end
of the responsive reserve deployments.
Now later on in this presentation,
I'm gonna reference NPR 939,
where we're working to change that
and deploy load that's providing responsive reserve
in 500 megawatt blocks.
But the current state is to deploy those
at the very end of the responsive reserve deployments.
I should be careful and also note
that the load providing responsive reserve has to be
on under frequency relays.
If the under frequency relays trip,
either for a local or system issue,
they could get deployed on their own
without any ERCOT instruction.
So that is in response to a frequency.
Will: Yep. Got it.
-: Did I, did I cover all of that?
Okay.
So in this blocky area that is on under frequency relays,
we have over 600 load resources registered
and that's around 7,000 megawatts of capacity.
But what we really see is a much lower amount than that.
And this is primarily because, I think,
a lot of these, and I'm speculating here,
but a lot of these entities registered
everything that they had,
but because you're cutting processes,
a lot of that is very unattractive at any given time.
And what they do is they register everything
behind their point of interconnect.
But really there might be only a couple of processes
that they can safely interrupt at a time,
but those might revolve around or change over time.
So we see a very large amount registered,
but what we see offered in is a smaller amount.
So the willing participation,
which we deem as folks that have offers or self arranged
ancillary services is around 3,100 megawatts.
The actual participation number is the amount that we award
plus self arrangement.
And this drops because we actually prorate,
there's a limit to how much we can allocate to load.
And so we prorate that allocation
amongst a multitude of resources.
What we've seen over time is that more and more
of these resources are going down the self-arranged path
than just openly clearing in the day ahead market.
And then the last thing was the available quantity
from willing participation is this very last number.
Next slide, please.
-: So a real quick question on the previous slide,
in the total 7,000 megawatts of registered.
So when you say there's an industrial constraint on that,
it's I guess the heavy machinery version
of dimming the lights 20%.
You can still conduct business,
the machinery can still run,
even though you registered 100%.
But if you turn the machinery completely off,
then that's a fundamental change to your business.
So while there may be 7,000 megawatts,
an industrial consumer may not want to shut down
all of that, they may want to do
the industrial equivalent of dimming the lights.
-: I think that's a very good analogy.
I would definitely encourage you to speak with the owners
of the plants, as that is not my expertise,
but the other thing is I might have six processes running
behind the meter and I can safely, like you say, dim one,
but other things I might not be able to.
So while they registered more than one,
they at any one time could only dim the one.
-: Sure, so there's, of the 7,000 registered,
there's a self-imposed constraint
on the industrial consumers, right?
Is there--
Kenan: That's my understanding, correct.
-: Is there also a constraint on the ERCOT side,
in terms of how much is accepted into different types
of ancillary services?
Kenan: So, the answer to that is yes,
there's a minimum that we always want to procure
from dispatchable resources on responsive reserve service.
And then on top of that,
there is a no more than 60% limit
coming from load resources.
So there's, there's kind of two limits.
One is we want to make sure, at least set them out,
comes from resources that we can deploy
and then no more--
-: That you can control?
Rotating them out so you can control.
Kenan: Exactly, and then also we don't want,
currently in the rules that says no more than 60%
can participate from the total, from load resources.
We're looking at potentially changing that,
but there's a lot of things that we need to work through
with our stakeholder partners,
as they try and manage these resources on the grid as well.
So there can be, for example,
on the transmission distribution side,
you might be worried if a bunch of these resources
are concentrated in one area,
that there could be frequency overshoot or undershoot
as they're deployed.
I'm sure some of the other panelists can speak more
about that, but that's,
we are looking to lower that limit on the percentage,
but we will keep the limit on what we need
from dispatchable resources.
-: Okay. Thank you for clarifying that.
-: Okay, so Emergency Response Service is a service
where we would
auction dollars off for load
to voluntarily go away before we were gonna shed firm load.
And there are several categories.
Those are non-weather sensitive 10 minute,
non-weather sensitive 30,
weather sensitive 10 and weather sensitive 30.
So the 10 and 30 references how quickly they have
to respond to an instruction to deploy.
We deploy these folks in and around EEA two,
but they have the right to go away
before we call on their deployment.
The logic for that was we don't necessarily mind
if they go away earlier
because they are in the end, allowing us
to curtail less firm load than we would otherwise.
So back in the day when this program was designed,
that was the thinking behind that optionality for them to--
Peter: Could you clarify what you mean
when you say that resource goes away?
-: So, they curtail or stop consuming electricity,
or because there are some behind the meter generators,
small scale generators that can participate.
So either the load curtails
or they turn on their backup generation
and for us, that looks like that load is consuming less.
-: So, according to these contracts,
I just wanna make sure I'm clear on this
and the public is clear.
The ERS participants are required to reduce consumption
of power at EEA two, the second emergency level.
Kenan: Correct.
-: But they can, like at that point,
according to that contract,
they can be required by ERCOT
to reduce their power consumption.
Kenan: Correct.
-: Okay. But they can volunteer to do that beforehand.
Kenan: That is also correct.
-: Okay, but before the second emergency level, EEA two,
ERCOT cannot force them to reduce that consumption.
Kenan: That is the way
it is set up. -: It is currently set. Okay.
-: Kenan, one question.
So based on the PUC's rule,
it says that ERCOT shall procure ERS,
a special Emergency Response Service
that's intended to be deployed by ERCOT
in an energy emergency alert event.
Currently, as you stated, ERCOT deploys it in EEA two?
Can you please explain how the decision was made
to deploy it EEA two,
because it sounds like there's flexibility
to deploy it earlier in EEA one,
if the Commission decided that was a good idea.
Kenan: And, I should be, I mean, if ERCOT,
ERCOT has a flexibility to deploy these earlier,
they could deploy them in EEA one.
More often than not, it is EEA two
when we actually order them to curtail.
But if frequency, the current NERC standard
is that if frequency was decaying fast enough
and we were in EEA one, we could still deploy them earlier.
But we tend to-- -: Could you deploy them
in a watch or an advisory
before we get to an emergency level?
-: That, we, my understanding is, I mean,
I think ERCOT always has that last line of,
for reliability being able to take action,
but that would, we would need to see a really rapid decay
in frequency or something to do that.
So I don't believe we've ever done that.
And the rule doesn't say that.
We would have to point to a different part of the protocols
to have taken that action.
-: So let's just say that ERCOT decides to deploy ERS
at EEA one, and as you described earlier,
some loads decide to pre deploy.
I mean, would that occur maybe, you know,
would that pre-deployment would occur before EEA one,
and so that would fall within that period
you're maybe discussing or noting.
-: I just wanna get a sense
of when these resources are available.
And it sounds like we have to get to an emergency
before these contracts allow us to deploy.
-: Yeah, I mean, we would be needing to point
to an emergency need to deploy them,
as it's currently contracted, any earlier than EEA two.
But there are some circumstances where we could.
The contracts can be changed to,
I think, answer your question.
-: Well, and I'm not saying they should be,
that ERS should be deployed before an emergency,
the rule clearly says that it's intended to be deployed
during an EEA event.
What I'm saying is that if you decide to deploy
during EEA one and you continue to see pre-deployments,
then those pre-deployments would come in
to assist with reliability
before we even get into an emergency in EEA one.
-: That, that is true.
That load has reduced its consumption.
So that means there would be less load, that firm load,
that you would have to shed in an emergency.
Laurie: Thank you.
-: So we currently--
Jimmy: Can I ask one question on your slide,
just the $50 million a year spending limit,
is that imposed by us or is that imposed by you
or is that the market?
-: That is in the substantive rule.
Jimmy: Okay, thanks.
-: And we do look at, as we contract,
there are factors we give to different time periods,
so that for time periods that are more valuable,
we spend more of those that 50 million in those time periods
than in time periods where it might not be as valuable,
but we do procure across the full day.
Will: And can I, you probably know a little more
of the history than we do, but 50 million,
how did we come up with that number?
-: So at the time that was deemed a good amount
for two reasons.
One, there was a little bit of worry
that the market might not be liquid enough
and you would be, you know, just if you increased it,
you would just be spending that money
for the same amount of dollars.
The other rationale, I think, that the Commission gave
was that seemed like a good amount of kind of
what I would describe as seed money
to help develop demand response in the ERCOT market,
because we were an energy only market
and on a lot of the other jurisdictions
demand response is paid on a capacity basis.
So this looks a little bit more like a capacity market
for a demand response.
When, so for example, in other jurisdictions like PJM,
they pay a capacity value.
So this, there was a thought
that if we put some dollars out there
that would bring development and folks thinking about this,
and then it would expand beyond just this program
and into programs that could be just slot in
to an energy only market.
That that was, I think, in the preamble to the rule,
those things were highlighted, as I recall.
-: So as per comments, I just want to hear your view.
A lot of stakeholders had pointed out
50 million isn't enough.
It's just, it doesn't make it worthwhile
to get a lot of those resources out there
and to enhance deployment of them.
So, how's the 50 million work
in terms of spreading it over the market.
-: So, I mean, if you looked at the clearing price
that they received on a capacity basis,
ERS looks like a responsive reserve kind of payment,
or, I mean, depending on the time period.
So in the more valuable time periods, or, you know,
even a reg up, reg down kind of payment.
And I mean, I think there's value
to increasing the 50 million,
if you can get more megawatts,
but what they are getting paid currently is,
has some symmetry to the ancillary service payments
that load gets.
So I mean, I think the better argument on the 50 million
is that there's more out there that we're not procuring,
than the payments being received are insufficient
in some way.
-: Okay, is it fair to say that you've got a pie
and you're having to divide up your pie
and you want to equitably divide up your pie
so that all your eggs aren't in one basket,
and is it fair to say that this was a seed money approach,
and this is just sort of how it settled out
in the division of the pie so that it just didn't get
loaded up in one particular slice?
-: Yeah, I mean, the, the pie is 50 million.
I have that to spend over a year, so it's,
and in some instances I exhaust all the bids
in certain time periods,
but I cannot make that pie any bigger.
It's just, I can slice it up differently, to your point,
but I can't make the pie any bigger.
-: Question on this because it may be,
but you may speak to it elsewhere,
of the thousand megawatts that you,
of qualified loads and generators
that make themselves available,
300 of that is provided by DG, is that accurate?
Kenan: That's my recollection, yes.
-: How do we settle on that? How does ERCOT settle on that?
The portion money?
Kenan: It's, we don't really,
as long as they qualify and perform,
we don't necessarily distinguish
between an award to DG or load.
-: It's just how the bids should have shaken out.
Kenan: That's correct, and the timing of,
or the qualifying time period of the bid.
-: Okay.
-: All right.
Kenan: This last bullet I think is important.
So on the weather sensitive ones,
we only procure those during peak time periods
because the volume is very different.
So some of the weather sensitive are air conditioning load,
it doesn't make a lot of sense to spend money on those
in the winter or off-peak.
So we do focus and discriminate a little on those
because of the types of resources that are there.
And those tend to be aggregated thermostat response,
and those types of products.
So we do look at what constitutes the bidding block.
Will: And so you look at the technical aspects
of the DG bidding into the block?
Kenan: Yes. Especially for the, this weather sensitive.
If it's, like I said, if it's air conditioner,
then the time period that we're procuring that matters
in terms of how much is really available.
Will: So I thought one of the interesting comments
that we saw was from the HVAC guys.
And they said that, look,
you really get more juice for the squeeze, paraphrasing,
when you qualify the latest inverter technology
on those AC systems.
Again the EEA, it's a long number,
but it's the latest electric model inverter for that.
So is that baked into your equation
when you qualify those systems?
-: No, it's not.
So what happens is somebody aggregates those
and they perform based on the characteristics
of the aggregation and they offer that in
and we test them to see if they can perform.
And if they do they're in the program,
but that we do test the response
and pay them for the response.
But it's up to whoever brings all of those loads together
to quantify their response accurately.
Will: Okay.
Peter: So that with the more juice for the squeeze,
we go to the aggregator?
Will: Yeah.
Peter: So that would be their opportunity, I guess.
Will: To get the most efficient devices as they can
on their system,
-: And ERCOT-- -: 'Cause it gets them
more of that pie. -: Yeah.
ERCOT's hanging out the money,
whoever can get there at the lowest cost falls
on the aggregator.
But I think that's also, I'm glad, very glad
you asked that question because it's important to highlight
that today, ERCOT is spending millions of dollars
on smart thermostat responsive air conditioning units
in summer season.
Is that accurate?
Kenan: That is accurate.
-: Okay. So that's happening today?
Kenan: Yes, if somebody can come and aggregate
and bid in--
-: There is money at ERCOT
for those aggregated smart thermostat, responsive AC units.
Okay.
Thank you, sir. -: And are they consistent
when needed?
I mean, I have--
-: They have a band in which they are allowed to perform.
So what is available is dependent on the weather conditions
on that day.
So if I had aggregated a large number, say,
in any city in Texas, and it was very cloudy and cool there,
I might get less response.
If they go below the acceptable bandwidth,
we would pay them less.
We would look at their performance and pay them less.
If it's really hot, they might have more capability
than on another day.
So that tends to drive the variance.
Jimmy: So they are pretty variable
because they're so weather sensitive.
-: Yes. -: Okay.
Peter: And that's tremendously important
because the top three consumers of power in Texas,
residential power in Texas, are AC, AC and AC, I think.
So anything you can get out of that counts for a lot.
Jimmy: And the likelihood that you're gonna get that
on a hundred plus degree day in the summertime
is, my guess, is fairly slim.
-: Well if-- -: Residential.
-: You've entered, the aggregators entered into a contract.
They owed it. They told they already took the money for it.
Jimmy: True, true.
-: Like whether you get that, whether you have customers
willing to give over control is a question I'm sure
will come up for some of our later panelists.
Jimmy: That's a question for that.
-: So I'll share, all of you know,
this is a coworker at ERCOT, and he is very conscious.
So he's on a thermostat program
where they can move up his thermostat.
You could bid that program in TRS if you so chose.
He had turned his thermostat up already,
and then they came in and still turned it up
another four degrees and next thing he knew
he was working in 88 degree temperature at home.
So, you can still get the response from this.
And, and there are override ability as well
for these programs, but just saying, you know,
unless somebody overrides it,
you would still get the response if it's really hot, or,
the only thing I would kind of caution you
on the air conditioning is on a winter event,
there's not that much there.
Laurie: That was gonna be my question.
How do you compare summer versus winter?
-: It is different.
And I think that's just important to note.
But we do get significant offers in the winter,
and we did and have in the past
employed the program in the winter.
-: Kenan, speaking of the winter,
and I don't want you to give
like a sub presentation on this,
but I know that after the winter storm
ERCOT filed and ERS report as to how ERS performed
during winter storm Uri,
are there some broad highlights that we, you know,
lessons learned that we should be taking away
from winter storm Uri based on that report that ERCOT filed?
-: Yes, I would most definitely look at, you know,
there are both generators and load that participates.
To me, the generation performance
kind of jumped out at me when I looked at that.
So that would be something I would advise
that you take a look at.
-: Okay, so when you say that, do you mean,
because currently there is some generation participates
in ERS when you say, look at it,
does that mean look at to take it out?
Or look to-- -: No, no.
I just, I would just say that that side
did not perform as well as we expected.
And we may want to, you know, spend more time
on performance requirements
or how we want to deal with that.
Now during the event, fuel was an issue.
So that I think also needs to be thought through
and not just, you know,
there's two sides to that story and I would emphasize that.
And I would also emphasize that that might play out
differently in the winter than in the summer.
Laurie: So--
Will: Oh, sorry.
Laurie: Go ahead, Will.
-: Well, just to dovetail on your point.
So if we were to consider backup storage,
ancillary service as has been contemplated in
and suggested in other workshops, that would change,
that possibly could change
some of the ERS participation, possibly?
-: So ERS is not an ancillary service.
-: You're right, you're right. -: I need to make sure
that's clear. -: I'm sorry.
-: So if they qualified for the backup fuel, you know,
however it is structured, then it would apply.
It just depends on how you would like to move that forward
from a policy standpoint.
And I am not qualified to tell you
that there is more value to back up fuel there
than a 500 megawatt plant.
There might be more bang for the buck on one end of that.
But that would be of interest to me
as I was thinking through those.
-: I want to return back to the topic
on generation resource participation in ERS.
So currently a generation resource that participates
in ERS, per our rules, a dispatchable generator
that is not registered as ERCOT, as a generation resource
or an aggregation of such generators.
So, you're saying that these generation resources
during the storm did not perform well.
Kenan: Yes, our analysis shows that their performance
was not at the level we expected.
Mark, did you have something you wanted to add?
Mark: Well, but you also realize we have a lot
of rotating-- -: Mark,
why don't you come up here?
(Mark speaks faintly)
Kenan: And for the court reporter, tell her your name.
-: Mark Patterson, manager of demand integration at ERCOT.
So you realize during the winter storm,
there were quite a few rotating outages
on the distribution system
where these resources are located.
So anytime you're gonna have outages
on the distribution system,
that energy's not gonna be able to flow.
So that contributed to a lot of the failures
of the generation providing ERS.
Peter: Once you get to load shed ERS,
you better have already shot your ERS bullet
because it won't matter at that point.
-: Well, so that's why the loads seem like they over-perform,
because again, you're adding rotating outages.
they can't consume. -: They really were going.
-: And then on the generation side,
they can't get their energy out.
So they're gonna look like they over, I mean underperformed.
-: So, these generation resources
are connected to the distribution system?
-: Yeah, and I, there's one thing I want to make very clear
is that these, to be qualified for ERS,
you do not have to be a,
what we define as a generation resource.
You just have to have either load that can curtail
or some kind of backup generation
that can make it look like you're consuming less.
Peter: You stopped consuming from ERCOT
and start consuming
from your behind the meter generating asset.
-: Exactly, but I think it's really important to note
that those are not necessarily, and I think rarely
what we would describe as a generation resource
that's qualified for ancillary services.
Laurie: Right, so I guess my whole point here
is that it sounds like, you know, there's a little,
there's a smaller number of generation resources
that participates in ERS about how many megawatts?
-: About 300 megawatts participate as ERS generators.
Laurie: Out of how many total megawatts typically?
-: About, I mean, we have about a thousand.
Let's just use that as a round number.
Laurie: But it sounds like your suggestion is to go back
and take a look at this issue with performance
because during a winter storm event,
or any event we have to take out distribution system,
there could be impacts to their ability to perform
and provide that ERS service that we've contracted them for.
-: I mean, I think you want to,
to me, your question was, sorry, what stood out?
That aspect stood out to me.
I think there's a lot to look at behind that story,
but I, to me that is the thing that on the ERS program,
that when I looked at it, I was sitting there going,
I'm not sure I'm getting the response that I was planning
after I've gone through this event of curtailing firm load.
Now this can happen on the load side also, to Mark's point.
-: So, and thank you for that background.
And I appreciate you highlighting that.
And the reason I'm asking is because we look to evaluate ERS
and make improvements for the future,
we have to do a look back and lessons learned.
And I think this is, you know, important fact to understand.
And we have had some stakeholders file comments
that state that generation resources,
those same generation resources you're noting
shouldn't be part of ERS.
So I'm just making sure that whatever we're paying for,
we're actually gonna get a reliability benefit from.
And I'm not saying-- -: Those are,
those are fantastic questions.
And I would just make sure,
as you think through that kind of caveat it
with the winter might look different than the summer.
But, I think the commenters are bringing up this issue
because it's, as we work through our market redesign,
these are important things to consider and evaluate.
Peter: Absolutely.
-: And you have this context
where they also want to grow the program.
So how you want that program to grow
from a public policy standpoint is important.
Laurie: Did anything else stand out from the winter?
-: That was, that would be the main thing.
I mean, I think there are
very individual details that stood out,
but while Mark's up here, I might as well let him also,
as manager of the program, answer that question as well.
-: Well, before I go into that,
maybe I could make one statement.
I want to make, ERS with the two different,
we have the ERS 10 and the ERS 30 product types.
The ERS 30 can get deployed in EEA level one.
The 10 minute product types, they are,
they can't be deployed any earlier than EEA level two.
So I think it's also important.
So there, you got the ERS 30 in EEA level one,
and then there's the makeup
of how much of that capacity is in ERS 10
versus ERS 30.
Over the years, there's been a significant movement
of most of the providers are now offering
into the ERS 30 product type service.
And so now the ratio is about 90% of the capacity
is in ERS 30 and only 10% is in ERS 10.
That means we're getting about nine,
if you use the 1000 megawatts, we get about 900 megawatts
that's available to us in EEA level one,
and then only about a hundred megawatts is leftover
when we get into EEA level two.
-: All in, and this is for either of you,
or I dunno if Woody's out in the audience, probably not,
but how long did it take us to go
from EEA one to EEA three during Uri?
Mark: It was very short.
Hour, hour and a half? -: It was short.
Kenan: Was about an hour or two.
-: So you got a 30 minute product,
you're making lightening fast decisions.
Mark: And that was a very fast moving
event. -: It was a fast moving.
But still, I mean, if we did a sort of historical back cast
on 2011, you know, when you kind of went through that,
it seems like that system does move fast.
I mean, when you're trying to arrest free falls
and God forbid frequency events, you know,
and this rotating mass becomes more of an issue.
So I guess, is it fair to say
that due to what we did observe,
which is a legitimate, you know, constraint on the system,
fuel, resource, or whatever,
once you start load shed protocols,
and you're even close to load shed protocols,
you need to be out front with these capabilities of ERS
because you won't be able to use them once you're in it.
-: Yes, I mean that the operators have to
really be thoughtful about when they deploy ERS.
I do want to, so 2011 was a really interesting year
because we had two cases to look at.
One is the winter event, you know,
where things may have moved a lot faster,
but there was also a day in August where it was,
we got really close to having to shed firm load,
but it moved to that point much slower.
And we actually deployed ERS.
And I actually remember the day really clearly,
'cause I was sitting there waiting to see
if the lights would go out
and ERS did make the difference that day and the time,
so again, it just kinda depends on the type of event.
But sometimes you have a little bit more time
if it is, you know, load slowly ramping up
and there's not enough generation
that might happen in the summer with no generation trip
versus a winter event could look very different.
-: So Kenan, as I stated earlier,
the role allows us flexibility
and ERCOT does use that flexibility to use ERS
in EEA one or two.
It seems like most of the sort of emergency EEA levels,
all the information I've ever seen from ERCOT,
has it being deployed in EEA two.
Kenan: So to Mark's point,
because this is the 30 minute service,
30 minutes is too long to wait for EEA two,
that is deployed in EEA one.
-: Okay, so--
Kenan: So, the lead time does matter for the product.
-: I do want to ask you one question
and it goes back to the pre-deployment.
There is a variety of stakeholders that file comments
that said that we should prohibit,
the Commission should prohibit early deployment,
pre deployments of ERS that has been contracted for.
Can you give me your thoughts on that issue?
-: I mean, so it kind of depends on your goal,
but if your goal is to have a product
that is in lieu of shedding firm load,
the way it is set up now make sense.
If you were worried about these loads
would have responded anyway, or those types of arguments,
that's where this don't let them leave early
kind of argument comes in into play,
is a lot of people will argue what they are,
you know, and, and I'm not,
I don't necessarily agree with this,
but I want to lay this out there,
is that these resources would have gone away anyway.
And you're in addition,
making an additional payment to them.
That's a lot of the argument for saying,
don't let them go away early.
That very issue was debated back in the original version,
and ultimately at that time, the Commission said,
and this doesn't need to be the case today,
but the thought was, I'd rather have them go away
whenever they're comfortable going away.
That is one less megawatt of firm load that I have to shed.
That that was the thinking.
I'm not saying that's necessarily right.
You might, if you agree with at least the commenters,
that the comments that I read,
you might get that response anyway.
So that I think that's the dynamic there.
-: Sure.
My colleagues are being very detailed in their comments,
and I understand you all were following the protocols
that you had at the time.
But I think I'll be a little more blunt
in saying that our direction from the Governor
and the legislature was to use these tools
before you even get close to the emergency,
and so we are never in a situation
where either the Commissioners, the regulators
or the operators are wondering whether or not
the lights are gonna go out.
Our jobs are to make sure
we don't get close to the lights going out.
And so I think there's plenty of comments
and thought up here,
that we don't need to cut it that close anymore.
I know Laurie's referenced this as well,
that there's a very good argument
for building a bigger margin of safety
between when we deploy these resources
and that hour between, the hour kind of downward spiral
between when we first started thinking about it
and when we started turning off people's lights.
-: Yeah, and in that context, I mean,
we talked about the 50 million.
When a load resource bids into this,
and I'm talking less about the generation
and more about the load, there is a cost to curtailing
and that is whatever they're making or the recovery,
having to come back.
So Commissioner McAdams, you had asked about the 50 million,
it's entirely reasonable to move up
that deployment time period,
but there might be a higher cost to that load
of curtailing earlier.
So that might be something to consider
when you think about the pot. -: But why?
-: The pot of money. -: Why is it more expensive?
-: Pardon?
Laurie: Why is it more expensive,
'cause in 15 minutes -: 'Cause they actually think
they're gonna get used. -: they're gonna--
Kenan: Well, I think there's two things,
they think there'll be used,
but they will be deployed more frequently
if it's a watch or an alert
rather than later in the queue, in the--
The preferred business model
is to get the 50 million
without actually having to be deployed.
-: But there is a cost to being deployed,
and that certainly would be in my calculation
if I bid into ERS.
-: The other side of that coin is getting what you paid for.
Kenan: Absolutely.
-: So, before we leave ERS, you know, I think,
thank you for all your feedback.
I think it's been very helpful to understand.
I definitely agree with Chairman Lake
that we've got to figure out how to use
this very important service in a way that provides us
a reliability benefit, and we get what we pay for.
And have a more, we want to give ERCOT
operational flexibility to use it when they need it,
but using it earlier to prevent us
from getting into an emergency
or at the very beginning of emergency
seems to make more sense.
But that's something we'll continue to evaluate.
The other piece of it is, you know,
we have a significant amount
of CNI customers that are registered.
There's been a lot of comments that have been filed
about residential demand response and performance blocks,
distributed energy, resources, storage, aggregations,
are there, with respect to any of those options
of new options potentially of being included in ERS,
Are there any opportunities you see
with some of these newer participants,
potential newer participants in the program?
And if so, is there any benefit for ERCOT
piloting some of some new participation?
I know ERCOT's done that a lot in the past,
and it's a way to sort of understand
how those resources will behave in a ERS scenario
so that we can see if we get any benefit.
-: So, I mean, ERS is probably more conducive
to some type of aggregation than any other program we have.
So I would, the areas that I'm more interested in seeing
how we might be able to aggregate
are more and load resource,
where they're participating in ancillary services,
both storage and a load.
We, ERCOT does allow non-spin,
some aggregations of load
to participate in non-spin,
but they have to follow base points.
And the data flow is necessary to manage
a lot of small resources and an aggregation is expensive.
So nobody is participating in that currently in that form.
But the data centers and things like that
have found that to be a good path.
So to me, the challenge we have
is to see what we can do on aggregations on this other end.
As far as pilots go, you know, certainly open to pilots,
but a lot of those sometimes turn into
just like a small set-aside project
that I don't know how much value that has or does not.
-: Okay. -: Yeah.
-: So, I mean, I do think we need to spend energy
and attention on aggregating
within the ancillary service suite.
And as I think a lot of the commenters pointed out
that might be also an area that you want to grow
from the perspective of system reliability anyway.
-: So it sounds like your conclusion is,
and I don't want to put words in your mouth,
but it sounds like you're saying that with respect to ERS,
the current participants, the status quo,
is you don't see any other opportunities
for any other resources to participate?
-: If I may qualify, I was trying to answer that
only in the terms of aggregation.
I think there are opportunities for other resources
to participate if, you know,
that meets your public interest standard.
But I think on the aggregation, and this might be
the most friendly product we have to aggregation.
Laurie: What type of resources?
That's what I'm trying to get at.
I'm just trying to figure out
what else we can be looking at.
-: I think there is a potential
for maybe some kind of aggregated storage to participate.
I think it's more on the small scale,
and not on the, you know, megawatt scale,
but I wouldn't preclude anything.
And we, this program is relatively open
to those types of resources,
as long as it's behind the meter,
and, you know, we can measure it and validate.
-: But as home storage proliferates
and as transportation electrification drives
more home electrification to a certain degree,
and more controllability at that on an aggregated scale,
you're saying that you would rather see that,
well, once it's a scalable and controllable,
participate in your ancillary services,
because you can forecast that, you're bidding that,
you're auctioning that.
And for ERCOT's purposes, that's a much more refined
mechanism for usage.
-: It sounds like they can already participate.
They just haven't found the right business model
to make it economic.
Is that accurate?
-: That would be, -: Data centers
could participate. -: I mean, the things
that you mentioned-- -: Do participate, right?
-: The items that you mentioned,
we would, I mean, I think they can participate.
Where they are unable to right now is in ancillary services.
But they have to meet the requirements
of the program, sorry.
Peter: Is it the economics doesn't work for them
in the ancillary services
or the reliability dispatchable requirements don't,
the performance, they don't meet
the performance requirement?
-: Well, I think right now, from an aggregation standpoint,
it's difficult to meet the ancillary service requirements.
But every day, folks are getting much more sophisticated
about controlling these devices.
And to me, it's possible,
I think we want to remove those barriers
and the ancillary services, also an open-ended,
the funding is more open-ended than ERS is.
-: Yeah, it's, just to harken back,
it's the performance barriers that ERCOT has to have
on a physical basis.
-: There's requirements for reliability.
So the barriers aren't,
the performance aggregated load demand response
is not participating ancillary services right now
because they don't have, they, for whatever reason,
don't meet the existing performance requirements
of ancillary services.
Is that accurate?
Kenan: Yes, and in fact--
-: Okay, we don't want to lower those reliability standards,
I feel confident in saying, is that generally reasonable?
-: They're there because that is the service that we need
to maintain reliability.
But sometimes registration requirements were built
on thinking about the resources that were on the system
at the time, or, and that's where ERCOT
needs to be nimble and adjust.
So I don't want to--
Peter: Sure, is there anything specific,
any barrier that you could point to on the ERCOT side
that needs to be tweaked or adjusted
to facilitate this without reducing reliability standards?
-: So I would say we want to get this moratorium
around DGRs away when we can do it reliably.
-: I think that's in process. -: That's important. That is.
I think we want as many of the new resources
coming on the system,
if they provide the value that we're looking for,
allow them to qualify.
So we would want to, if there's something
stopping them from qualifying,
we would want to look at that.
I think a lot of the comments that I read,
in and around this, you know,
wanted to reduce the hour duration or things like that.
That's where I get a little bit more nervous
because if I have an hour long event, I am--
Peter: Yeah, we don't need to adjust reliability
to meet existing technology.
We need the technology to rise to reliability.
-: Exactly, and then be open to any technology
that can meet those requirements to qualify.
Peter: Yeah, I think we've got,
we'll hear from lots of folks today
about any opportunities to improve on the ERCOT side.
-: So, with respect to the moratorium on DGB being lifted
over the years,
and expected significant increase in those resources
after that moratorium is lifted this next year,
and those resources are connected to the distribution system
by way of just pure definition, how are we gonna, you know,
how does ERCOT anticipate managing that?
Or what can we do to help you manage that situation
where we are in a load shed event,
and, you know, we have a bunch of resources
on the distribution system and we've, you know,
we can designate them as, I mean,
how is that gonna all play out?
-: So I think what folks from the TDSPs
are gonna share with you
is gonna be really important to answer that.
But one thing I would throw out there is, you know,
the more granular we can be in terms of the load shed,
then we might be able to keep more of these resources that
are on the distribution system of available.
But that's quite a challenging and expensive proposition.
But that's one thing I think,
as far as distribution level resources go, that, you know,
that's a challenge to manage for the distribution providers.
And I think they would be able to share
a lot of thoughts with you on that.
-: We did hear from at least Encore at the TDU work session
that said they do have some distribution resources
on their system, and obviously wouldn't roll them off
because they are providing an ancillary service.
But as we have a tremendous increase in those resources
on our distribution system,
I think it's gonna be really important,
as you've highlighted,
to figure out a way to get the reliability benefit,
especially if they're enrolled in AS product or ERS
so that they're not being rolled off
and we also don't have operational issues
in conducting load shed because we have a bunch of lines
in addition to critical care that can't be rolled.
-: Yeah, absolutely.
Programming question for you, Kenan,
how many more slides do you have?
-: I believe there's three more if I remember correctly.
But I can move, I can move through them pretty quickly.
And in fact, a lot of your questions
are on the subsequent slides.
-: I mean, nailed it.
All right, take it away.
-: So TSPs or TDSPs do have load management programs.
They deploy, those are deployed through ERCOT instruction.
We're actually tracking them more closely now
because there is a price adjustment for their deployment
that now is in our system.
So there's like a price run and we adjust the price up
for the deployment of those megawatts
to make sure we're sending the right scarcity price
to the system.
This program has between 250 and 350 megawatts.
Next slide, please.
The four coincidence peak load reduction
is a major response that we see in terms of demand response.
All the data on this slide,
I need to highlight, is from 2020.
We don't have 2021 data yet
because we actually collect, September is a 4CP,
we collect data through September
and we'll issue an updated report in December on this.
But what you'd see is load reacting
to the transmission cost of service allocation
that they would face.
And they curtail both on the 4CP day or days,
but they also, to be absolutely sure
that they don't miss it,
there are also these near 4CP days
or near coincidence peak days that we see large deployments.
And in fact, I believe it was 2019,
one of the coincidence peaks change
because so much load responded on one day,
it moved back to a prior day in the week.
So, you definitely want to catch the near days
as well as the actual days.
And there's large value in that as this slide shows.
-: So speaking of how the grid is changing
and as the peaks change,
so if we will experience some of our peaks in the non,
you know, summer periods,
like as we go into shoulder months
and we have more, dispatchability offline
due to maintenance schedules.
If the Commission was to consider a,
and I'm not doing it here, I'm just asking the questions,
a more disparate CP,
you know, some comments have indicated a 12 CP approach.
Again, that number, that all in number wouldn't change,
it would just be spread over a longer range.
Again, more months.
-: Yes, you would have to curtail at the peak of every month,
for example, in a 12 CP to make that work.
I do, Woody's not here,
but I do want to channel my operations colleagues and say,
one of the things that ERCOT is very interested in
is instead of just the load peak,
the net load peak is of particular interest to ERCOT
in terms of managing the grid
as you have more and more intermittence on the system.
So it's that peak adjusted for intermittent resources
from an ERCOT reliability standpoint, that is--
Peter: Can you put net peak load in context?
For non-engineers. In layman's terms.
-: Yeah, so it is load adjusted for intermittent resources.
So it's the combination of intermittent resources and load
that is that net load peak.
The one thing I would caution you is on,
this methodology was chosen on a cost causation basis
for the transmission build.
I'm not, I couldn't tell you
that there is a cost causation link
between the net load peak and the coincident peak.
So I think you would get people arguing that before you.
-: Yeah, so net net peak load comes later in the day,
generally as solar, as the sun sets,
and that may not necessarily be
when an industrial consumer of power is,
that's not the same time that,
the peak power consumption happens at 4:00 or 5:00
in the afternoon.
Kenan: That's correct.
-: And, so, from a reliability standpoint,
in the control room,
the most challenging time is when the sun goes down
and solar comes off, the solar power supply comes off.
Not necessarily when the most power is being consumed
during the day.
Is that what you're trying to say?
Kenan: Exactly. Also when wind is really low,
or something like that. -: Right.
The supply drops closer to the total demand
rather than the highest total demand of the day.
Kenan: Correct.
-: Well, what about the winter?
Kenan: Allocating on the winter PX?
-: Yeah, like a net load impact on winter.
Cause I mean, renewable generation
definitely performs different then, right?
Kenan: Yes, so renewable performance
would be different in the winter.
You might have, you know, less solar on the system,
so there's not as big a drop
and also the sun goes down earlier,
so the timing of that changes.
I mean, I think our observation is more,
this net load peak is of material interest
in the summer right now.
-: Okay. Thank you.
-: Next slide, please.
Also just want to make sure that I share with you
that retail electric providers have programs
that they don't necessarily have to register with us,
but there's a financial interest in them
reducing their consumption at certain times.
And NOIEs have demand response and 4CP programs.
So we try and account for that as well.
And we've identified kind of the day in 2020,
when that was the highest amount.
Next slide.
This is just an informational slide showing
both in megawatts and in numbers,
the amount of growth in what we are calling
settlement-only distributed generation.
So because nobody's really qualified
to be a generation resource
or a capital D capital G capital R,
distribution generation resource,
this is the main number that we're tracking.
When the moratorium ends,
there'll probably be a different category here.
But as you can see, both in numbers and megawatts,
year on year, these resources are growing.
Next slide, please.
We are also tracking what is going on
in the rest of the United States.
FERC order 2222 is just of interest to us
to make sure we're not missing any good ideas
or bad ideas for that matter, or things that don't work.
But we are implementing rules ourselves.
They are not necessarily tied to any FERC order,
but those are items that we do track,
as well as the regular developments
in different jurisdictions.
Next slide please.
So, and this is my last slide.
I think we've talked about a lot of these,
but the one I want to really focus on is this first bullet.
And we actually filed in this docket comments on this,
which is, when I look at the price
at which we compensate load, it's the zonal price,
the zonal average, and the reliability baked in price
is the locational marginal price.
And we would like to find a way to move,
for compensating load resources,
to this locational marginal price
rather than the zonal price.
And I can give you an example of where this came into play,
but when I think it was, it's almost two years now,
when the hurricane hit the lower Rio Grande Valley,
we saw really high prices in the south zone.
Those really high prices in the south zone
were driven by issues in the lower Rio Grande Valley.
However, the prices were as high as $1,400.
I saw load in, you know, north of,
or east of San Antonio curtail due to that price,
but they actually hindered a reliability solution
rather than help by curtailing
because the locational marginal price
would have been more like $10.
So I've done two things as I think
about both the Texas economy and reliability.
One is I sent somebody a price signal that said curtail
when they should be making whatever it is they wanna make.
And two, I didn't really help the reliability problem
that I was having in the Rio Grande Valley.
And I may have actually hindered it.
So the the impact was extremely small,
but it kind of gets you thinking,
if it was closer to the constraint that load curtailment,
it actually could push the prices up even higher
and make it more difficult for ERCOT to solve the problems
that it's trying to solve.
And that's why we've advocated for this issue
in our comments.
Peter: So, more precise price signals.
Kenan: Correct.
-: Is that an ERCOT problem or is that a substantive?
I'm not seeing that in the substantive rule.
-: So actually the substantive rule
talks about all resources getting an LMP.
When we implemented nodal,
we didn't have the technology to get them that price
so we can change
our rules to reflect that.
However, in our comments, we also at least propose
that all load, whether it's a resource or not
potentially be settled, if it's greater than a megawatt
at the LMP.
And I don't think that is something
you want to do immediately.
That's probably something you want to phase in over time.
But it is something to be thinking about
as we try to more reliably operate the system,
and we're likely to have more load resources or load,
large loads on the system
that can curtail in response to price.
Peter: Very good point. Thank you.
-: And I think we've talked about everything else
on this slide.
-: Yeah, I imagine we have.
Appreciate you, Kenan, and Mark.
Thank you all for being here.
Thank you for presentation and your sporting willingness
to field all these questions.
Kenan: Oh, it's a pleasure.
Thank you for having us. -: All right.
Next up we have a panel of Tetra Tech, Xcel Energy,
and the Sierra Club.
-: Someone get her attention, is she the only one here?
Is she the only one here?
(people whispering over each other)
-: Okay. Welcome.
I think we're by, in terms of programming,
we're gonna get as far through y'all's presentations
as we can get, and aim for an 11:45 break time for lunch,
and 12:30ish return.
I learned my lesson on 30-minute lunches.
Well, with that, we'll turn it over to Tetra Tech. Welcome.
-: Great, great to be here.
Hello, I'm Lark Lee with Tetra Tech,
and I've been working in this demand side management
for over 20 years.
Specifically since 2013, I've worked very closely
with Commission staff to oversee
the IOU energy efficiency programs.
So the eight investor-owned utilities we have.
What I was quickly hopefully to do with you,
I know time is of the essence here,
but is dive a little bit deeper into those programs
that ERCOT talked about
to hopefully give you a little bit more insight
of how they currently operate, what constraints,
maybe some of your questions on how they can help
keep the lights on.
And maybe some of the ways we could use them more
to help keep the lights on, but totally informational here.
So just a little history,
Texas was one of the first states that legislated
energy efficiency goals.
We did it very uniquely compared to other states,
as we always had in mind using these programs
to help address peak demand.
So, whereas a lot of other states talk about KWH goals
as a percent of annual sales,
ours has always been to reduce peak demand growth.
So the current goals have been set in 2013.
There's a floor, 30% of growth, peak demand growth
until that hits four tenths of 1% of summer peak.
And then that's the new goal.
Encore and Center Point have hit that.
So they do have higher goals right now.
Goals can never reduce. So that is a floor.
So even if demand goes slows down,
they're still held to that higher floor.
The substantive rule that governs the programs
was, the latest one was in 2012 coming into effect in 2013.
There are some very specific things in there
that we need to be aware of.
Summer peak is very, it's defined very clearly.
It only includes Monday to Friday non-holidays.
I think about that when we think about winter storm Uri,
that came in on the Sunday.
Also winter peak is clearly defined as well.
There's nothing addressing shoulder seasons.
So that's something to keep in mind on that.
Any questions on the history
before we go into some specifics
of their demand response programs?
All right, next slide please.
So this is a quick overview of what we've seen
over the last five years from the programs.
As you can see, 2020, I don't have the latest from 2021,
did see the most amount and peak demand reductions
from these programs.
Slightly less than two thirds of this
is from load management demand response offerings.
About a third is from energy efficiency offerings.
The difference in there, right,
is that demand response requires annual participation.
So this is about getting customers in,
retaining them every year.
Whereas the energy efficiency,
when you're installing something more efficient,
you should see that peak demand reduction
not only in the year it's installed,
but for the life of that equipment.
Peter: Move your microphone a little closer?
Lark: Yeah. Oh, I'm sorry.
Usually I'm told I'm so loud I don't need a microphone.
Peter: You can pull it closer to you as well.
-: Okay. Is that better?
Can you hear me better now? Okay.
All right, so again,
I'm gonna talk about next a little bit more
on that 328, right in line with ERCOT's estimates,
they kind of had a range over time,
is what we had from 2020.
And most of that is from
commercial load management programs.
The next couple of slides,
I'm gonna give you a little more information
on how the commercial programs
and residential currently operate.
I can talk about these programs all day.
So any questions you have, I would love to answer,
but there are also a lot of reference slides
for future consumption.
So moving onto the commercial load management slides.
This is, we do have a slide later on for future reference
that shows all the programs.
We focus just on ERCOT today.
The bottom line is, you know, Center Point, Encore.
And then we have AEP and TNMP.
One of the things that's worth noting
on that participant count,
is we have seen participation go up over the years.
You know, we do a deep dive into these programs,
our last one was in 2019, to really understand
how the participants are responding, what the makeup is,
how they're making sure that they curtail.
So those are things I can go into more depth,
but that, for the time, might not be something of interest
at the moment.
So moving on to residential.
So residential is different than commercial.
So when we came on board in 2013,
the commercial load management programs
were already very mature.
They'd already been operating for over a decade.
Residential was just starting.
Center Point was the first one who started working
with the reps to roll out residential demand response.
And since then, Encore has really the largest program now.
AEP did have a program for a couple of years.
They had issues with the implementation contractor.
That's why it's discontinued.
I'm probably not gonna talk about El Paso's program
at this particular juncture.
One of the things that I think is important to note on this
is in talking with all the utilities,
there's significant interest in participating
in these residential programs.
They put a limit on how many people can,
they turn people away from these programs.
So that's something to keep in mind.
Will: And again, sorry.
-: Yeah. -: And again, why?
-: Well, because of the way the rule works is,
so why I talked about the legislative goal
was set in peak demand,
there is what, a unique Texas term,
an energy efficiency conservation load factor.
So we set an energy savings goal in relation to that.
So we can't have everything coming from demand response.
So they do have to keep some budget
for that energy efficiency.
So I think it's just in how they allocate across,
what do they do in energy efficiency versus demand response.
There's not been, it's an ongoing discussion.
And I think the utilities can tell you this directly.
They're never quite sure how much
they should have in their portfolio from demand response.
In some states, we have some specific guidance on that.
We don't really, we don't have a limit in the rule
other than the fact they have to get
those energy efficiency savings too.
Did that answer your question?
-: Yeah, so we, just to kind of recapture that
in another way, we tell them they have to do it,
they have to do something and we set a floor,
and then they are playing the odds
in terms of what a rate case is gonna come back at them on.
Lark: Well, (laughs)
so rate cases are a little bit out of my area of expertise,
but-- -: Is that economics?
Is that the-- -: Yeah, I guess I would say,
remember, so there is the floor
on the what they have to do on the demand reduction,
but within their budgets,
which are baked into the rate case, right?
So everything, these programs are funded
through the energy efficiency cost recovery factor, right?
So that is what you're alluding to.
And so they have to meet both goals to keep everything
part of their, get their bonuses, everything.
So they do also have that energy efficiency goal.
So they couldn't in fact get 100% from demand response
and also meet that other goal
and recoup the costs they need to under EECRF.
So it would then be a very sticky situation for them.
-: Okay, and you may have this in your later slides,
but as I sort of see this system,
you're kind of the,
you're the sheriff, you go out and make sure
that there's actually quality as a part of these systems.
So as per the comments that I alluded to earlier on HVAC,
and up-to-date and most technologically advanced
inverter system, inverter-based systems,
and they alluded to efficiencies in the winter,
as well as the summer,
just in its ability to regulate power use.
What do you do to sort of, and how is that accounted for
in these systems?
Is it accounted for?
-: Yep. Yep.
So there's a couple of different parts
to answer your question fully.
So stepping back on the summer and winter,
right now these programs only address summer peak.
So they were not called when winter Uri hit.
They're not set up that way.
The way the current rule reads,
because the utilities can only claim summer or winter peak.
So they can't get people to participate
without being able to offer an incentive.
We believe that the current rule would allow
there to be a separate winter peak program too.
So that's one aspect of your question.
The second is my role as the sheriff.
This is where we really do have a lot of confidence
in the savings from these programs.
So I will be honest with you, when I started in 2013,
there was no consistency in how people were coming up
with how these demand reductions calculated.
Now there is.
We have a centralized document
called the Technical Reference Manual,
which I won't geek out too much on you,
but it does say this is a baseline you have to set
for commercial programs.
It's six out of the last 10 hottest days.
I also qualified non-holidays, et cetera.
For residential, it's three out of the five.
We get a interval meter data
for a census of those participants.
We calculate it independently.
After doing those with a few years with the utilities,
they now, you know, we've resolved any differences
in the way they calculate it, both of us.
So we have a lot of confidence in the calculations
that they pay incentives for.
There are no penalties in these current programs.
We also require a test event
so that we, again, really know what people can curtail
and see that that's there.
We ask them to modify, you know, consider contracts
based on the results of that test event.
So there hasn't been a lot of done
to increase our confidence
that those savings are really there.
-: So is it fair to say you would have mechanisms
if we enhanced, and again,
if we're supplying capital for this effort
as approved in rates, rate cases,
there are mechanisms and that you already employ
and that you could enhance
to ensure that latest developed available technology
is being employed or at least valued differently,
more enhanced value within those systems
that the utilities could recover for.
Just so that the Commission could have a view
that look, no, we are sure
that we are getting what we pay for here
and its latest available today.
Lark: Correct.
So I don't even, my last slide just literally walks
you through the history of the EMNV
because I wasn't even gonna talk to that.
My point was there isn't infrastructure in place
if it's desire to expand these programs,
there's an infrastructure to support that happening
in a way that you can have confidence
those savings are there.
-: Okay.
-: I was told to keep it to 10 minutes, so, I'm gonna try to,
so that's it.
I mean, that was the only point I was gonna make
is just letting you all know
kind of the background that supported this infrastructure
and just the fact that everything is in place.
We already, for energy efficiency measures,
we do already have winter peak.
So expanding out the current demand response protocols
to address winter peak versus summer,
again, our only limitation under the current rule
is we're really constrained in being able to do anything
in shoulder seasons.
So that would be something that would need to be addressed,
but otherwise I think we have a good infrastructure in place
if it's so desired to expand these offerings.
Peter: So I think two key points being expanding,
opportunities to expand and improve.
-: Accountability, or-- -: Bang bang for your buck.
-: Yeah. -: Value delivered
for dollar spent, is that fair?
Jimmy: Can I ask something? This is, uh.
-: Yeah.
Jimmy: I just wonder if we get demand response
at ERCOT right, should the transmission companies
focus on energy efficiency?
-: So that has, that is a long-standing
debate and discussion.
-: Sorry. -: So we did meet, (laughs)
we did meet with ERCOT in 2019 and we talked about that,
of when they come in.
I, my personal opinion from that take away
was that at that time,
ERCOT did see value in having those programs as a resource.
So we did work to make some improvements.
Like they made the comment, not all that utilities,
some of them had an hour advanced notification
versus 30 minutes.
Hey guys, we need to, everybody's gotta be 30 minutes.
So I would say
that it's an ongoing debate. -: Thank you.
Peter: Very, very important question.
-: It is, yeah.
-: Very important question.
All right, thank you very much, Ms. Lee.
Xcel Energy.
-: Good morning. My name is Bill Grant.
I'm a regional vice president for a regulatory
for the SPS operating company.
A little bit about my background before we get in,
I've had various jobs with Xcel Energy,
the service company, plus SPS,
but I've seen all sides of the demand response
and the distributed energy.
For seven years, I was director of power operations
doing all the real time dispatch and marketing
for Xcel Energy company for all of our operating companies.
And that includes the MISO market.
One utility that's not in a market,
public service Colorado in the SPS system,
that's in the Southwest power pool market.
Also, I was the manager of the transmission control center
for several years.
So I've seen that side of the operation
and how these resources actually meet
with our emergency plans and the other issues we have.
And currently, and I've been doing regional policy
all during this time, and also now
I'm over the regulatory department.
So I want to get started by talking about SPS
and what makes us different than ERCOT.
We're a fully bundled utility and not in the ERCOT system.
Most of our programs that we offer for a demand response
are tariff driven.
And I've seen, like I said, I was overall,
three operating companies.
So each company was different with their resources
and the offerings they made, and the tariffs.
And a lot of it had to do with their capacity position.
So a lot of the pricing of the demand response
was due to their capacity positions.
For example, do I need some quick-start resources,
we'd have a 10 minute product versus a one hour product.
And our pricing was what type of resource where we avoiding?
And we would make those.
Our NSP system has a lot of demand response,
well over a thousand megawatts of demand response,
the SPS system, we did not have as much.
Our capacity position is a little bit different.
A lot of our companies do have
their own sustainability goals
where they have the generation behind the meter,
but they're not participating in the market
for the most part.
They're offsetting the retail rates.
And then, you know, we have some customers,
when they produce excess, they're getting paid the L and P.
So we do have some dump behind the meter generation,
but not as much participating in the market
as offsetting their load they're taking from the utility.
On our offerings for demand response,
we do have the program
where we interrupt the air conditioners on days,
but we're not limited to peak days,
where we can actually utilize that program
when we see high prices,
it's not necessarily a reliability issue.
We can actually do it to avoid pricing.
So the whole concept is to minimize cross subsidization
by offering the payments,
but also utilizing that when, you know,
when it benefits all the other customers on fuel.
Peter: Are your customers auto-enrolled in that?
Or they, you have to opt into that?
-: They have to opt into that.
One of the things I will tell you that I did learn,
you know, we did learn the hard way
is when you're doing resource planning,
one of the things you need is a longer commitment
from customers that are going to participate
in demand response
because we used to have a very robust system
where we had over 350 megawatts in the SPS system
that participated in demand response.
At the time, we only had a one-year notice to get off.
If you can imagine 350 megawatts given you one year's notice
because the price of natural, price of oil spiked up,
we had to scramble the very next year
to get resources in our resource mix.
So, you know, when we do offer these programs,
we do at least ask for a three-year commitment
so it fits into our resource planning,
and that we're not left in an emergency response
to somebody say, hey I don't want to be interrupted anymore.
But another thing that we have coming on
is we're in the southwest power pool market.
And what that does, that allows our load to use
even third-party aggregators,
if they want to, to participate in the market.
Now that's unique because we still have the responsibility
to serve that load,
but we don't necessarily have the communication
with the entity that might be offering this load up.
So some of the things we've been seeing lately
is the programs are not sizeable yet.
I can say we're probably less than 10 megawatts total,
but it's growing.
We're getting more and more people
signed up for this program.
My fear is, is as it grows,
if we don't know when that,
when our load is gonna be offered by another party,
into a market to be interrupted,
that impacts how we bid our load into the market.
And we start getting concerned.
So for those programs,
we're not opposed to people doing that,
but we think communication with the host utility
that's responsible for serving that load is critical
so that we can manage the load pricing.
So kind of to summarize, we offer some of our resources
through a tariff, and if people want to participate in that,
a lot of our companies do have behind the meter generation,
but they're doing it for their own sustainability goals.
And they're also offsetting, you know,
for the most part, they're offsetting our tariff charges.
And then, but we are in a market.
And FERC order 222 was mentioned before.
So SPP is in the middle of doing their compliance filing.
We've been working on that team
to help with the compliance filing on that.
So it's yet to be determined how many people
will actually utilize that program
other than offsetting their tariff load,
but we have to, you know, we have to get the rules right
to where people can participate if they want to.
But, you know, the economics is gonna drive
whether they just drive to a market
or whether they still offset their load consumption
from the host utility.
And the other thing we have going on
is third-party aggregation into demand response.
And as I said earlier, you know,
we would hope the Commission, you know,
might look at helping us out with some rules around that,
to where we have information flowing
to where we can manage our load.
It's not being subsidized by other customers as well.
So that's kind of a quick summary
of where we're at and why we're different than ERCOT load,
'cause we're fully bundled.
-: Mr. Grant, thank you, sir.
Question for you.
On, in terms of the way
SPP manages their system for capacity,
can you qualify the distributed resources, DG,
for a capacity bid?
When you put in your resources for capacity,
that 12% in SPP,
can you use aggregated DR as a part of that?
-: Yes, if we have a distributed resource
that we know that we can interrupt,
we have two choices in SPP.
If we're wanting to be able to dispatch it,
it goes into just like a generator.
It goes into a generator bucket.
But if it shows up as reduced load,
we can count it as reduced load for our load reporting
for the purposes of capacity integration.
So, if I have an interruptible product
that I can interrupt across peak,
I would reduce my load requirement
for the purposes of meeting
my 12% planning capacity requirement.
Will: Okay, good.
Given one, FERC order 2222, and now new federal policy goals
that seem to be happening now,
again, the federal renewable portfolio standard,
I'll just call it that, for 2035.
I think that's a kind way of putting it.
What do you think happens in terms of DG, DR,
what pressures is your market gonna come under
to harness that energy again in the near term?
'Cause that's a pretty short fuse on goals
in terms to meet that.
And what does that look like for that capacity target
that the system has to, you know, one, adopt
and utilize to offset intermittency?
-: That's a good question.
And one of the things we're changing our methodology
for the accreditation of renewable resources.
Now we're gonna an ALLC process,
which actually would consider the saturation points
of specific resources and the, you know,
the probability of it being there on a peak day.
So we're changing the way we're accrediting.
A lot of studies going on
as far as the reliability concerns,
how much spinning mass you have to have on the system.
One of the things we've done recently
is on a plant, of one of our larger plants,
when we're not running as a generator, we've decoupled,
and we're able to run it as a synchronous condenser.
Ideas like that help us with the voltage control
and the support that inverted base generation
does not give us.
So, you know, a lot of different things
that SPP is struggling with
as far as a lot of companies meeting their goals
and we cover 16 states.
So what's unique is not every state
has the same goals at the same time.
So cost allocation is always a consideration
when you're, if you have a state like New Mexico,
where we're supposed to be 50% by 30,
supposed to be 80% by 40, and completely carbon-free by 45.
Well, that's gonna take either a lot of different resources
or even transmission in there.
And the other states are saying, why am I paying for that?
So we have a lot of issues like that we're dealing with.
And so, to, first steps are,
what are the top resources?
How much can we handle? We're doing studies on that.
Changing the accreditation methodology.
And also the tools that real-time operators have
like dynamic stability analysis real-time,
which is a tool that we haven't always had at our disposal.
So we can actually recognize voltage,
areas on our system that have voltage concerns
and other issues as we transition
into a different type of resource.
-: So Mr. Grant, just to kind of understand, you know,
you have a lot of wind on your, in your portfolio, right?
You recently added significant amount of wind?
-: That's correct.
We're anticipating energy served to be around
the 45% range for 2021.
So we have on a 6,000 megawatt transmission system,
but also we're responsible
for about 4,100 megawatts of that.
We have close to 3,000 megawatts of wind on our system.
-: I'm just trying to understand,
'cause I know Mr. McAdams asked some questions
about federal de-carbonization,
and how does that play into FERC order 2222?
That's been very controversial.
I know following the issue several years ago,
I think was challenged.
So I'm just trying to understand the pressures
that you're facing, since--
-: Well, when it comes to FERC order 2222,
one of the problems we're facing is the RTLs
have no jurisdiction over the distribution companies.
So FERC order 2222 puts a lot of requirements
on the distribution companies
that FERC does not have authority over.
And SPP only has their system model
to the transmission nodal market.
They do not even see into the distribution system.
So when you're talking about putting distribution resources
that can participate in a market,
first of all, you know, SPP is not gonna see it.
We're gonna have to bring it,
a telemeter back to the transmission system
so they can even see it.
What does that do changing the flows
on the distribution system?
We're talking about all those issues right now
on our task force.
And one of the concerns we have
is do the distribution companies even have
the tools necessary to be able to enable,
and we don't even know how big of a, you know,
I always like to say, bring me a bread box.
We don't even know how big this bread box is gonna be yet,
and how much participation we're gonna have.
So there's a potential of a lot of spend out there,
and we might not get that much participation.
A lot of those issues out there.
But, the main point, to answer your question
is without having the, I kind of halfway consider it
an unfunded mandate.
FERC went in and said, hey, you can have generation
on the distribution system
that participates in the wholesale markets.
They didn't necessarily say how to accomplish that.
-: I heard you say three, SPP was working on
or struggling with three things,
saturation point, discount factor for,
saturation point of each type of generating asset,
discount factor to apply for each count,
type of generating asset
based on estimates of how much that generating asset
would provide during certain hours when power's needed,
and minimum rotating mass for voltage support.
Bill: Yes.
-: It sounds like, to Commissioner McAdams' point,
y'all are struggling with the same challenge
of reconciling renewable with a reliable that we are.
When you, when you get the answer to those three,
will you please send them our way?
-: Well, that is the one thing that our industry
needs to do a better job of is, you know,
you have a lot of people that didn't even think
we can incorporate the amount of renewables we have today,
but, you know, we've been able to do that.
And, and it's a great testament to our industry.
However, I do think there is with our current technology
and emphasis on the current technology,
we can put ourselves into a place
of unknown operating conditions
if we don't do a lot more studying,
and we don't get a handle on if there are limitations.
And I'm not saying there are.
But I'm just saying with the current technology,
there are limitations.
Peter: Yeah. We've found those in April and June
in ERCOT. -: Yes, sir.
Questions?
-: One last question in terms of the technical aspects,
when you incorporate these resources,
and I'm talking about DR, DG,
resources onto your system, do you require that technology
to be telemetrically controlled?
-: If we count it towards our resource plan and stuff,
we have to have control at the control center.
We have to be able to interrupt it and we do test it
to make sure we can interrupt it.
SPP has very hard requirements.
If it has nothing to do with utility and you have a resource
that wants to participate in the market,
they have to meet all the requirements
that a generator does.
They have to have the real-time telemetering,
they have to be able to send a signal back,
and they have to prove that they can react
to a dispatch signal.
Will: So it is valued differently.
-: Yes.
-: Okay. Thank you.
-: All right. Thank you, Mr. Grant.
Mr. Reed?
-: Thank you. Pleasure to be here.
Cyrus Reed, Lonestar Chapter of the Sierra Club.
I'm gonna be covering quite a bit today.
So I'm the conservation director for the state Chapter
of the Sierra Club.
We have about 30,000 members. Most of them are in ERCOT.
If you can go to the next slide, I was told not to advocate,
but I'm gonna advocate anyway, on this first slide.
Peter: That's never stopped you before.
(group laughs)
Cyrus: So first thing to say is, thank you.
Thank you for looking at the demand side.
The demand side is where residential consumers
and, you know, Sierra Club members
tend to be resonant with consumers.
That's where we are. It's half of the equation.
So I do appreciate.
I do want to make a pitch that I think I've made
to several of you in private meetings,
that at some point we have at least one workshop
where any member of the public can give
their two, three minutes,
especially as you get down to decisions.
You know, winter storm Uri was obviously devastating
to millions of Texans.
Some Texans died.
There were a lot of Texans with health problems.
And these are major decisions you're making.
So I obviously appreciate the invitation to the Sierra Club,
but it would be nice to have at least one public forum
as you get down to the decisions.
And that'll be my one specific advocacy,
can't promise you I won't do other advocacy,
but that's my one pitch, is better include the public
in these discussions.
But yes, let me recognize that focusing on demand side
is very important.
And within ERCOT, as we know, both in the winter and summer,
more than half of the peak load is residential
and small commercial.
So it's very important. If you can go to the next slide.
So this is my basic slide,
which is you guys have a lot of tools in your toolbox.
And so if you look at these four categories,
the TDU energy efficiency programs,
which is really what Lark spoke about,
ERS and ERCOT spoke about that this morning,
the ancillary services ERCOT spoke about,
and then market another.
I do think in all of these categories,
in terms of residential DR energy efficiency,
distributed generation,
and behind the meter distributed generation,
there are things that can be done
to increase those categories.
And now, you know, in some of those categories,
we're fairly limited.
So we talked about residential DR
and the TDU energy efficiency programs.
Limited capability, and basically summer-only.
Energy efficiency within those TDUs is based,
I call it a capacity factor, it's actually called, Lark, a?
Lark: Energy conservation load factor.
-: Energy conservation load factor.
We have a, I would call it a very low amount
of energy efficiency that we require TDUs to use,
to make, to meet.
Those programs do not cover distributed generation.
They can include some
behind the meter distributed generation.
There can be incentives to storage solar
within those programs.
There are some limited incentives.
That's something to think about.
ERS we've already talked about.
There's some limited residential DR,
really the 30 minute weather sensitive load.
We do think that can be increased substantially.
And I would argue if I'm allowed to advocate,
that it should be.
Ancillary services, we are appreciative
of the current efforts to get non-controllable loads
into non-spin.
And we do believe more can be done
with an ancillary services.
And then there's the market itself.
And there's a lot that can be done in the market.
So if we can move to the next slide.
I want to just remind folks,
the energy efficiency rule you have,
and this is why I say you have a lot of tools,
you have the ability to really expand it
because it does say
"ensure that all customers
"and all eligible customer classes"
and, reminder that our energy efficiency programs
really do not cover industrial.
We specifically limit them to commercial and residential.
"Have a choice of an access
"to energy efficiency alternatives
"that allow each customer to reduce energy consumption,
"peak demand, or energy costs."
So I think that gives you pretty broad authority
to change the way we do our energy efficiency
and load management programs through the TDUs.
Next slide.
I'm not gonna go through all of this,
but on the right,
this is a study from APRA-E that shows
that there is no state that has more economic potential
for electricity savings than Texas.
And in the comments we submitted, there's a footnote,
if you want to read the whole study,
but APRA-E puts the study out every couple of years.
As Lark said, we were really the first state
to have an energy efficiency resource standard.
That is not correct.
We're actually ranked 27th. I said 29th.
I'll, you know, fix that in a final version.
We are now last in terms of our overall savings goals.
And here I'm talking about the savings goal,
which as Lark said, is a percentage of the peak demand goal.
So we are really the last state
of the states that have an energy efficiency goal.
We are currently have the lowest one.
Which in my mind means if we were to aim for a medium goal,
not the Vermonts or the New Yorks or the Californias,
but the, you know, Arkansas of the world,
you know, the medium states.
Pennsylvanias of the world.
You know-- -: After last weekend,
that's just especially mean Cyrus.
Cyrus: Yeah, sorry.
Oh, I'm sorry, I didn't even think about that.
Yeah, that was, as a UT grad, that was painful.
So they'll do better next time.
You know, we could potentially adopt a goal,
not tomorrow, but over time, you know,
phase it in over time and quintuple our energy savings
compared to what we get today.
And so if you, oh, and I'll just mention,
NOIEs do have programs, they do have energy efficiencies
and DR programs,
we require a certain NOIEs to report,
both do some reporting to ERCOT and to SECO.
Those reports probably aren't as good as they should be.
But in general, we don't see
a lot of participation by NOIEs,
other than Austin Energy and CPS Energy,
which have their own internal goals that they're meeting.
-: What's the policy behind requiring some,
rather than others?
Do you know where that came from?
Cyrus: So that was a law
that was passed by the legislature
that said NOIEs have to report to SECO.
Any NOIE that's at, I believe it's 500,000 kilowatt hours,
and I get my megawatt hours and kilowatt hours
get confused sometimes, think I'm right,
have to report to SECO annually on their DR
and energy efficiency programs.
-: So that's who's got to report,
not who's actually doing it.
Cyrus: It's just a report. We're not requiring--
-: So there are reps and NOIEs out there
that may have may or may not have these programs in place
that aren't reporting them.
-: So we require NOIEs to report to SECO.
ERCOT has some new reporting requirements as well,
both for DG and some surveys for demand response.
But one could argue that we should be doing,
we should be requiring more of NOIEs
in terms of these programs.
So next slide.
I'm not gonna go over this
because I really think Lark did a great job.
I put some of the numbers down on the energy use
and the actual cost.
And these are, I didn't have the 2020 data.
So this is really through 2019.
I think I can skip this slide if you want to go to the next.
This is really my somewhat of advocacy slide
on energy efficiency.
Key point building codes are very important.
You guys have nothing to do with building codes,
but I do want to mention that we as a state
could and should be doing more on building codes.
But I do want to make the point
that energy efficiency can really be thought of
as base load if we can reduce overall the energy demand,
that's gonna buy us some time
and it's gonna be good for customers.
And then, you know, the peak demand programs,
demand response is really about those peaks.
And I do think we need both in the program.
And I do want to say that although the legislature did pass
SB 1125 in 2011,
which was the last time we had legislative action on this,
the PUC itself through rulemaking has, in the past,
expanded and changed goals.
You did it in 2010.
So you do have, as long as you meet
the legislative minimums, you do have authority
to adjust goals and adjust programs.
There are some requirements, Lark didn't mention this,
but there are some specific requirements
on low-income and hard-to-reach programs,
which I think are very important given that we don't have a,
you know, some of the system benefit fund features
we used to.
So they are very important, but it does mean TDUs are in
a little bit of a, you know,
they've got to do a lot of balancing
between the peak demand energy savings
and the low income programs,
but it's just something to be aware of.
The 20%, and I call it the load factor.
Well, that's correct.
I sometimes mix up (mumbles).
But, the 20% load factor is something that can be adjusted.
That's in the rules.
So if we want to get more energy savings,
we could adjust those.
We could also adopt a separate energy savings goal.
And obviously all this gets back to the rate payers,
the rate payers are paying for these programs.
And so you do have annual energy efficiency
cost recovery factor proceedings.
But ultimately you all, the four of you,
make those decisions really about, you know,
what's the appropriate amount to charge rate payers?
Right now, we're generally under a buck average,
am I right, on to consumers?
(woman stutters)
We're around there, I believe.
Yeah, we're around there. -: Per month or per year?
Per month or per year?
-: Per month.
So the Sierra Club argument would be,
we can go higher than that
and get more energy efficiency and demand response
to these programs.
Obviously there's a balancing act, you know.
And PUC can refocus these programs
to deal with winter savings and new technologies.
We can do that.
How am I doing on time? Keep going.
Smart Meter Texas, this is another tool in your toolbox.
We invested billions and rate payers paid for this,
in Smart Meters.
We've done rulemaking on this.
This is something you could look at again.
Our argument would be that rate payers haven't gotten
all the value they could from those smart meters.
And it's really about accessing more timely access
to the information and Smart Meter Texas,
mainly for retail electric providers,
but also for third parties.
That could be really key to opening up
economic demand response,
really allowing those programs to grow.
So looking again at the rules around access
to the smart meters, who has access, how much,
how can they get information in a timely way
that can be useful to them?
And there's gonna be other people who can speak later
about the details of that.
Don't ask me too much about that. So, next.
ERS, again, we put this in our comments,
I guess I'm minute into advocacy, 50 million.
I think, I think we could double it and still,
the impact on overall on load serving entities
would not be great.
And I believe we could do a lot more with aggregation,
and that is probably the easiest place to do aggregation
in the ERS.
Next slide.
You know, we have limited residential DR
in the market itself.
A lot of it is nights and weekends free.
It's not what I would call true DR.
You guys could either look at additional ancillary services
or setting a goal for load serving entities,
making people nervous here, for residential DR,
and then let the market do what it is,
allow it to be tradable.
That's something that I think is within your authority.
And then I think this is my last slide.
And then there are gonna be many others
who talk about this later,
but I would argue right now, you know,
we've done a lot on settlement-only distributed generation,
that's growing, and these are old numbers.
Obviously Kenan gave you more recent numbers.
But how do we get the unregistered DG
and the distribution generation,
you know, aggregated, unregistered,
unregistered DG, and distribution generation resources,
how do we really grow those markets?
And we think there are ways to do that.
I think I'll allow, you know, other folks coming later
that have more experience than I do,
but we are, we generally think there is more
that can be done to get to that sort of third bucket,
and also incorporate some of those smaller units
that are customer-sided.
And so with that, I'm happy to answer questions.
-: Thank you, sir.
I know we've got five minutes before we break for lunch.
I want to be quick,
but I'm gonna co-op Commissioner Glotfelty's question.
Or do you want to?
Jimmy: Go.
-: Let me get this right.
If we do demand response,
if we do the ERCOT market redesign correctly
and get demand response correct in that redesign,
do we still need to be spending 50
or 100 or 150 million
on the energy efficiency program?
-: So you may be, so you're not referring to ERS.
You're referring to the TDU?
-: Sorry. Okay yeah, sorry.
That was ERS, I apologize.
Refer to the TDU efficiency programs.
-: I am in favor of making the TDU programs
more focused on energy efficiency
and getting homes and businesses up to, kind of up to snuff,
so they can then participate more fully.
That's not to say that we're against having some, you know,
load management programs within there.
And I think it'll be important,
at least for the next few years
before we get to that redesign,
it's kind of a way to pilot new things
and get them out there.
But I do think if you look at most states,
a lot of the focus of these tend to be energy efficiency.
And in particular, low-income working Texans,
people at 200% or less of the federal, you know,
those are, you know,
we saw a lot of the suffering during Uri
had to do with your housing stock.
So I do think it makes sense to some extent,
refocus these programs on energy efficiency,
but not immediately.
It's gonna take some time to, you know, to switch over.
-: I was just gonna ask, do we do a,
I think I know the answer to this, but a good job
or a poor job of working weatherization programs
with EE programs as a state?
-: I would say we do, we do a poor job.
That's not to say that there aren't,
you know, lots of great implementers out there.
I've always felt like, you know, there's the TDU programs.
And then there's the federal weatherization money
that flows through TDHCA.
And sometimes it gets very confusing
about what the rules are and who does what.
I think within the confines of what TDUs are required to do,
they do do a good job.
It's just, we could be doing so much more.
Jimmy: Thanks.
-: So I have a question.
There was a variety of comments filed
recommending that the Commission allocate money
from the TDU energy efficiency program
to, within that pot, to residential DR
energy savings programs,
and I'm just wondering what your thoughts are on that,
Lark, Cyrus?
And I think their basis is there are some programs
within that energy efficiency program
that could be underperforming,
and we're not getting that much bang for our buck
from a reliability benefits standpoint.
And by shifting some of that money over
to residential DR-focused programs,
that we would be able to get more of a reliability benefit.
-: So I have to be careful, right?
'Cause I can't advocate.
I guess I would say, I don't know that particular comment.
We already did, there are some residential
demand response offerings being funded right now
through the energy efficiency programs
that could be called in a way that could increase
the value they currently have.
I don't know where they're talking
about diverting monies from,
which makes it difficult for me
to kind of talk about that more.
I was really glad that Cyrus brought up
the low-income, hard-to-reach component.
That is something that's legislated.
It's something we're actually working really hard
on improving those programs this year.
So I'm sorry, that's not.
I'm just not, I'm sorry, I can't answer that one
more fully without--
-: I understand. -: You know the devil's
always in the details, right?
Laurie: And maybe the question is better
for the next panel.
Cyrus: Yeah. I mean, if you have 150 million
or whatever it is, is about 150 million a year,
that's spent through the energy efficiency programs?
I think that's about right. -: A little bit more, yeah.
-: You know, like we were talking about with the ERS,
it has to be divided in different ways.
And the money that comes from commercial customers
are supposed to be spent on commercial programs
and the money that comes from residential customers
is supposed to be spent on residential.
So it's when you start getting those details,
it gets pretty confusing.
But I, you know, I do think more can be done
on residential DR Within these programs.
I do think there may be a way to focus on winter as well.
We talked about, you know, you've seen other people
comment and winter storm Uri,
that a lot of it was electric strip heating,
drove that demand.
Or, you know, can we be investing in heat pumps
and new technologies that will really reduce,
for those people who aren't using gas.
So we can really reduce that energy load
during really cold periods.
So there may be things we can do on in the wintertime.
That would be useful.
Peter: All right. Thank you all.
-: Appreciate the invitation.
Peter: Right at our 11:45 mark, we'll reconvene at 12:30.
(group chattering)