(gavel bangs)
-: The meeting of the Public Utility Commission of Texas
will come to order to consider matters
have been duly posted
with the Secretary of State of Texas
for August 26th, 2021.
For the record, my name is Peter Lake.
And with me today, Will McAdams, Lori Cobos,
and Jimmy Glotfelty.
To get started,
a brief logistics announcement,
our next work session will cover demand response.
That will be in mid September.
I know there was a lot of comments this time
on demand response,
so appreciate it if you'll hold your thoughts on that
during this conversation and save those comments
for the dedicated work session on demand response.
And I know we'll be providing guidance
part of the calendar next week
for that demand response conversation
in that work session.
I think in general,
our market's got a pretty well-developed
commercial industrial and transmission level demand response
that of course,
there's always something we can improve on
and we'll look forward to suggestions there,
there's a big unknown
in the residential demand response world
which have many of you highlighted.
I look forward to hearing about that.
Mechanics will come out next week,
but I will also remind folks that it would be very,
very helpful to know what demand response
in the residential world is already happening.
So we can get a better sense
of how much is being addressed by market forces,
where you of course don't want to jump in
and regulate something
if market forces are already solving the problem.
So we'll,
we will be grateful for any and all information
related to current demand response activities,
and level demand response
in residential places going forward.
Before we dive into today's full business,
I will first of all want to thank
the stakeholders who provided constructive,
creative comments as part of this exercise.
Many of you,
showed up in good faith
and provided valuable input.
You know who you are, thank you very much.
We're tackling an enormous challenge.
And so we need and appreciate all the help and insight
we can get.
And I think we're all grateful for the
the people that showed up in good faith.
There was another subset of comments that
primarily focused on preserving profits
and incumbent business models.
There is nothing in Senate Bill 2,
or Senate Bill 3,
about protecting businesses or incumbent business models.
As you know,
it's very much related to improving reliability
and accountability for the Texas power grid.
So we will appreciate going forward,
focusing on truly constructive changes.
We don't need comments telling us
that this crisis based business model
is just fine and we don't need any changes.
You can save your breath.
It's not the direction we got from the legislature.
And it's certainly not the changes
that the people of Texas are demanding.
With that we will move to the public comment portion
of this meeting.
Invited oral testimony related to a specific agenda item
will be heard when that item is taken up.
This is for general comments related to today's agenda.
Do we have any public comment?
We're not doing that for work sessions.
-: I don't think so.
-: We're focused on ERCOT design features today.
So unless you all, any the rest of the Commission,
has a desire to take up items
one through three, five through nine, 11 or 21,
I think we can go ahead and table those work.
All right.
It brings us to item number four.
We'll bring up our first panel.
Woody Rickerson, Kanun Ottoman, and Barbara Clemenhagen.
Barbara: Good morning. Peter: Good morning.
Peter: Woody, looks like you're up first.
Barbara: I believe Woody's up first.
Woody: I'm up first? All right.
So on July 9th,
we ERCOT sent a list of ERCOT reliability initiatives
to the PUC.
I think it's been referred to as ERCOT's wishlist.
So what I'm gonna cover this morning
are a four or five slides.
We kind of break those down into some categories
and then we'll go over those.
So this is all based on that July 9th memorandum.
So starting off with the first group is market concepts.
First of all, an item there
is evaluate market design changes
that would result in an appropriate planning reserve margin.
I think that's probably the most important
from a reliability perspective,
having an appropriate planning reserve margin,
a big enough planning reserve margin
is probably the most important thing we have
from a market design,
gotta have a market that gives us a planning reserve margin
that ensures reliability.
We've got studies that show that a correlation between
you know, 15, 16% reserve margin
and a loss of load of once in every 10 years.
And as that reserve margin goes up,
the loss of load potential stretches out.
If it's less than that,
it's less than once every 10 years and so.
That's definitely a correlation
that we're very interested in from a reliability standpoint.
So that's the first thing.
And on any of these, if you guys, you know, questions,
we can stop and talk.
Will: On that Woody. Okay.
This is gonna be a good day.
I've been looking forward to it all week. Okay.
(people laughing)
-: You're saying this is more fun than security?
-: It's much more fun. (people laughing)
Barbara: I'll agree with that.
-: Yeah.
As it, can you define for the record
and for the Commission,
because there's some history behind the statement
of a planning reserve margin.
ERCOT does not have a,
we have a target reserve margin.
Can you explain the nuance between what ERCOT has
as a reserve margin and the rest of the country
and kind of how they envisioned reserve margins?
-: Well, they built a reserve margin.
We let the market provide the reserve margin.
Will: Okay.
(crosstalk)
Woody: Right.
Will: So in terms of
we try to provide a reserve margin.
What feeds into that?
-: Well, all the generation online,
Will: Yup.
-: that's synchronized with the grid feeds into that.
The complexity comes from how do you count wind,
what percentage,
wind in the panhandle is different from wind on the coast.
So if it's a hundred megawatt wind farm in the panhandle,
what percentage do you count of that for the reserve margin.
Solar,
same kind of concerns during the, you know,
what kind of, how does that count toward the reserve margin?
It's different for a summer reserve margin
when solar is a really strong contributor.
A winter reserve margin, not as strong
because the peaks usually occur outside
of strong solar hours.
So all those things are part of that.
Will: Is there a different planning reserve margin
for the fall and the spring versus that summer
and a winter evaluation that we go through?
There's not, is there?
-: There's not a different reserve margin,
but we count them differently in the CDR.
Will: Okay.
So would you say,
is it fair to say that there's kind of a
a quasi reserve margin that you sort of,
you as an operator sort of have in your mind
in those periods?
Woody: Well, I mean when we look at studies,
the studies will correlate a reserve margin
to a loss of load potential.
Will: Right.
-: And, you know, in past summers,
when we've been down really low,
we've had a loss of load potential of one server.
I think it end once every two years,
you could expect from a statistics standpoint,
a loss of load event
and a loss of load, we mean a grid size loss of load.
-: That's Statewide load shed lights go out
every other year.
Woody: Right. -: Under that.
Woody: That's the
statistically,
that was what the studies would show, yes.
Peter: That's not what we're aiming for, right?
That's the point of this exercise.
-: That's why that's probably the first, you know,
that a reserve margin is the first bullet
on this presentation too,
because I think from a reliability standpoint,
that reserve margin is really the,
what we're driving for.
Peter: So you mentioned it's incorporated
related to Will's question the CDR, that's a,
I guess, a long lead time analysis.
How do,
how do we or should we incorporate real time conditions?
Say for example, the zero wind days we had in June
or into that reserve margin analysis.
-: Right.
So that's actually in the second bullet there
is a, you know, improve,
whatever market design would come up with,
we wanna improve incentives
for the attraction retention of flexible
and dispatchable resources.
So, you know,
as we continue to interconnect inverter based resources,
it's important we maintain a fleet of flexible
and dispatchable units
and having a market that has some incentives for those
is important.
There's a couple upcoming studies
that we're gonna have to,
we're gonna be releasing that with detail, you know,
what levels are necessary for reliability.
And also, a follow-up study that will detail
what kind of funding,
what kind of market design is necessary to attract those
and make those viable.
Peter: What level of dispatchable.
Woody: Right.
Jimmy: And how do you define dispatchable?
-: Dispatchable would be that when we call on them
that they can respond
Jimmy: Does that include batteries?
-: Right.
Yes.
Jimmy: Of a certain hour duration?
-: I charged batteries dispatchable. So yeah.
(people laughing)
Jimmy: But do you all have a view
on two hour, four hour, six hour,
eight hour duration batteries yet?
I mean, you may not have that yet but
Woody: So we do have four different ancillary services
that are requirements.
We, we just don't have enough right now.
We're not, we don't have a requirement
that if you install a battery ERCOT,
it's an eight hour discharge battery
or a one hour discharge,
there's no requirement that way.
What we do is we take what people,
what companies bring to us,
and we incorporate them into the system
wherever they fit.
So there's not a requirement now,
now that certainly could be
a market design feature
that there's an incentive for a 10-hour battery,
eight-hour battery, or something else.
And that's certainly something that could be incorporated,
but that's not something we have today.
Jimmy: Got it. So let me go back and ask,
do you believe that a battery
is considered dispatchable resource?
Woody: Yes.
Jimmy: Okay, thanks.
Peter: Worth noting that one of the features of batteries
is the modular nature.
So that even 4-hour duration can be scaled
to make it 8, 10, 12 hours.
And what to follow on Jimmy's question
in the definition of dispatchable
does compressed air energy storage,
pumped hydro co-located with other resources.
With that counter, is that in play in Texas yet?
Woody: We don't have any of that in play yet.
It could count.
And I should back up a little bit.
I said, I charged battery,
I guess, charging a battery is also a dispatchable resource.
So it's a load resource at that point.
Lori: So what do you,
let me ask you a question real quick.
Do you currently count batteries in your CDR report?
Woody: God, you got me on the spot there.
I know we are begin,
there's talk on how to do that.
I don't think it's in there yet,
but that is part of what's being considered at this point.
-: Just for background purposes
and for whoever's watching from the public,
what is currently counted in the CDR report
and what are the requirements to be counted
in the CDR report for those resources?
-: Well.
Lori: What type of resources are currently included
in the CDR report?
And what are the requirements
for those resources to be included in your report?
-: Nuclear fuel, coal fuel, gas fuel, diesel fueled,
any kind of thermal generation is counted.
Wind generation is counted,
solar generation.
If batteries aren't counted at this point,
they will be shortly.
Load resources.
Lori: What are the requirements that have to be met
to be counted in the CDR report?
Woody: Well anything
that's currently synchronized to the system is counted.
And then if you're looking into future years,
they have to meet certain planning guide requirements.
Lori: But my understanding is that currently,
if resource counted in the CDR report,
you have to have an air permit if you need one.
Water rights certification, if you need it,
and an interconnection agreement.
Woody: Right,
those are the planning guide requirements.
Lori: So, for renewable generation,
all you really need to have
is an interconnection agreement.
Woody: There are some planning guide requirements
for solar and wind as well.
I mean, we have a lot of generation.
Wind and solar generation
that are at different stages
of the interconnection process.
And when they reach a certain level,
then they are able to be part of the CDR.
Lori: And at that level,
will all of it get built?
Or is there a certain percentage
that ERCOT factors in will get built.
-: Once it reaches that level, we count all of it.
-: But does all of it actually get built?
-: For the most part, I think it does. Yes.
Lori: Okay.
'Cause I think when we look
Woody: We tried to set that level to the point
where it was a pretty sure thing.
Lori: Right.
I think that's important to understand
because you know the planning reserve margin,
you know, large planning reserve margins
that we're expecting to have,
but baked into the planning reserve margins
are renewable generation,
that seems to just need an IA
and maybe some planning requirements
that may or may not get built,
but it sounds like a good percentage of it will get built
based on your <v Woody>Right.
-: But then as you look at the planning reserve margin,
you know, what can he actually count on to be there?
-: So that was gonna go to my question is
so right now we're sitting at 15 plus percent.
So, and in the future, according to the CDR,
it's gonna go up exponentially a lot.
But in that is,
is your variable resource calculation
and how that's accounted for.
So as we move forward and you may think about,
again, that target reserve margin
that we try to build up to again,
other ISO's set theirs like,
and everybody else has got to bring up their resources
to comply with that.
If that's kind of what we're talking about,
what is baked into it and how do we bake it in?
-: Well, and what component of it, I know ERCOT
It looks at the capacity factor like you were just saying
for wind and, you know,
Gulf coast area versus panhandle wind,
solar, different parts of, you know,
different times of the year, different seasons,
but maybe it's worth kind of zooming in on that
to make sure we're doing that appropriately
on a seasonal basis,
different locations throughout the state,
because if it's being baked into the reserve margin,
gotta make sure that we have a real realistic picture
of what were gonna to expect to have.
-: And not on average with her
-: Exactly -: Or just skydiving.
In the universe that we live in.
-: And it might be helpful, you know,
I guess at what point,
what ERCOT include battery storage in the CDR,
does it have to reach a certain megawatt level?
So we can, you know,
as we have more and more battery storage in or the market,
you know, how should we be accounting it
for it in the CDR report?
And also,
should we be looking at dispatchable generations differently
within the CDR report
and reflected in the planning reservoirs?
Woody: Yeah one of the things you see sometimes is
you might see a future year
with a certain number of plants that are gonna be built.
And then we get to that future year.
And some of those plants have moved out a year
and you see a peak bumping out
from one year to the next.
That doesn't mean they're not going to be built.
It just means that the initial estimate
of when they were going to be built,
they may get pushed out further.
And so there may be some changes we can make
to maybe provide more clarity there or something.
Peter: And the other side of the coin
that you're talking about Lori
is what the ice ford curves show
is unlike most futures curves that increase over time.
Our current forward curves over the next few years,
ERCOT decrease in value, which is of course
a tremendous challenge for anybody who
wants to bring new dispatchable power
on there's no,
there's literally no market for revenues,
which is part of the problem.
And of course we want the right kind of investment
in our power fleet, but that's just,
it's another version of what you're talking about.
People see that increasing reserve margin
and under the current construct,
there's no rep no way to generate revenue for dispatchable,
as you can see that in the ice curves.
-: Economically.
So what are you, on that note
from your view as an Operator,
come next winter,
again we will have gone through a summer
of having a fair amount of batteries on grid
interacting within your system.
Do you believe that you'll have
and it may not be baked into the CDR,
but from an operator perspective,
you're gonna have something in mind,
some view of how they will interact
for the purposes of the winter season.
And then is from your knowledge
of staff considerations,
will we have a better foundation to build in batteries?
So we ultimately as a regulator,
can see a percentage of the CDR now
going to dispatchable battery generation
so that we can account for it
in our consideration of your target reserve margins.
Woody: Well,
as of December of this year,
we will have changed our systems
so that we can incorporate batteries.
Will: Right.
-: So that's a major step.
That's been a three-year effort
to modify systems so that we're ready for batteries.
As far as the winter of 2022, 2023,
I don't think batteries are gonna be
a major player.
Will: Okay.
-: There's just not enough hours,
megawatt hours of energy there yet.
When you think about,
if we think about a Uri type event
and you think about batteries
having the ability to contribute four,
10, 12 hours,
I mean, that's still useful on some days,
certainly useful on a summer afternoon
when we have scarcity conditions,
but for a Uri type of winter event
that lasts multiple days,
there's just not enough megawatt hours of energy
available yet.
It may be a few years before batteries
are a real contributor, a difference maker,
during some kind of event like that.
Will: But just to press further on that,
in terms of your ability to arrest a free-fall
in generation,
if something freezes up in one part of the state
or a plant trips for some other condition,
you would be able to use a fast frequency response tool
to arrest that free spot,
free-fall almost instantaneously.
Woody: Yes.
For short duration events that there's value.
For long duration events,
until there are many, many more megawatt hours
of energy installed capacity.
That's just not gonna be a major player
for a big long event like that.
And which is really what planning reserves and CDRs
and stuff are looking at
is kind of a steady state long duration kind of events.
Not those frequency events or things like that,
which batteries certainly have a major role to play in that
and will play a role in the short term.
Will: Okay.
Lori: Woody,
can I kind of address a broader concept?
You mentioned the planning reserve margin,
and currently it's at, you know, target reserve margin
for across 13.75.
Is that figure intended
to meet a one in 10 reliability standard?
-: Ah, roughly, yes.
-: And then you said that
ERCOT's latest study shows
that we're actually at a one and two-year?
Woody: I said we have been down
as low as that in the past.
Not now.
-: Well my understanding
based on stakeholder comments that were filed
is that a report in February of 2019,
almost three years ago,
showed that we were at a one
and two-year loss of load event.
-: Well, when we had a reserve margin of what was it,
eight and a half or nine percent.
Where we were.
Lori: So would it make sense
just so we could level set
because this study is about three years old
to update that study, to see where we're at,
based on where we are in the market today.
-: And in terms of the study,
is that the economically optimal reserve margin study
that kind of set that baseline down,
cause it said it low.
Is that kinda what, what you had envisioned?
-: It's a study hall by Brattle
under ERCOT reliability standard.
-: Yep.
I think that's the one that kind of establishes those tears
when we get down to economically optimal reserve margin,
which is different than the one in 10 reliability standard.
Woody: Right.
There's a, yeah.
Peter: You just trying to get a current
loss of load probability
based on today's grid posture.
Is this like what it looks like today.
-: Right, it might be helpful to,
I don't know how long that study would take,
but it might be helpful since the last study
is about four years old to see where we are today.
-: Yeah, we're gonna look into that.
Woody: So we,
We have a study that's coming out shortly
that shows that, but that's part of that
that reserve margin study that we've been asked to do
that will come out before the end of this year,
but that will they'll have those kinds of numbers in there.
Will: That's right.
That's your loss of load study.
And is that an annual process that you go through?
Woody: This is actually a special request
that we're we're working on. Yeah.
Peter: Okay. Great.
-: I know you've got a hard stop at 10:30,
so keep going.
-: Next one,
develop financial incentives for resource owners
that maintain existing or acquire new dual fuel
capability onsite fuel storage and or energy storage.
For this item,
the other small improvements that ERCOT can begin
like an NPRR that will require Black Start Units
to have onsite fuel.
That's something that we do internally
that we can work out with market participants
and that NPRR while not filed will be shortly,
but there are other broader market considerations there
that you know, dual fuel capability onsite fuel,
those certainly enhance reliability.
And what, how there,
what kind of incentives are provided for that
in a market design is certainly something to think about.
Establishing a minimum generation
to deliverability requirement for dispatchable generation
in the transmission planning studies.
So that is a rule change that will be submitted
maybe today.
Dispatchable generation,
what that does is it would require
the dispatchable generation and planning studies
be dispatched at a minimum level,
at least a minimum level.
So if you have a 500 megawatt unit in a planning study
and that 500 megawatt unit causes a problem in the past,
we might dispatch that down to 300 megawatts
and the problem goes away,
but you lose 200 megawatts of dispatchable megawatts.
And so going forward with those planning studies,
that would be dispatched to the,
at a higher level so that it would drive
what would have been an economic transmission project
that you can now accept
of getting that extra 200 megawatts out
and economically driven project.
Now it would become a reliability driven project.
So it's a shift,
to make it a reliability driven project
instead of economic project.
And so that's a change
that we are we are submitting
into the binding rules documents.
Now there'll be a planning guide change.
And finally,
the established operational requirements
for private use networks
during energy emergency and scarcity conditions.
Well, increasing demands for complex,
I'll call it complex behind the fence arrangements
are driving part of this.
We also saw during winter storm Uri
that we had private use networks that called us
and said, hey, we can produce more power
if you'll let us.
And that's a great thing to do,
but we need to get that stuff squared away
before a winter event
and not try to do it on the fly.
And so rules changes there,
Bitcoin type load behind the fence.
Those things are deemed to be ironed out.
We need to understand how we're gonna do that.
We've got internal processes in place now
to work through those,
but if you'll seek some market participants
or some market changes upcoming on those as well.
Second group is a wire company concepts,
so improve the ability of transmission
and distribution providers to rotate higher,
higher levels of load shed.
Maybe one of the most important things we could talk about
the ability to actually, when we do need to shed load,
to be able to rotate through that.
We have a spring survey that showed what could be shed
and how quickly, what's on the list can be shed.
I fear that a new critical load designations
are going to put wire companies in a bind.
And so working through those issues
is an important part of this.
And I think there are,
there are certainly things that we can change
and there's talk of changing some of the ratios
and things like that.
But those are, that's a,
that's a certainly an important,
important change that we need to make right now,
on how we rotate load
or how TSPs and wire companies will take load.
Lori: Woody on that, on that point,
very important point.
And thank you for highlighting the critical load aspect of,
of that issue.
In terms of, you know,
as we have more and more facilities
signing up to be critical load.
One option,
or potential solution that we heard about
at our last work session, well, before that,
on the TDU work session, was segmentation.
And the ability to segment off critical load
so that you can open up the line
to rotate off more customers that are not critical.
Is that something ERCOT can look into?
Woody: That's not really an ERCOT.
We don't own the wires.
We are looking at the grid from a higher level
and we're saying,
okay, we need 10,000 megawatts of load shed.
And we're calling the wireless companies
and asking them to do their proportion of it.
Now, how they do that is as an engineering,
distribution engineering, kind of a problem.
So the segmentation, that kind of thing
is something that the TSPs are gonna have to address.
Lori: Is there any potential opportunities
at the transmission level?
-: There's most of this is gonna be at the,
there is, but the majority of it
is gonna be at the distribution level.
Lori: Okay, thank you.
-: I would also say that
that changes, segmentation changes,
they cost money, and those are expensive.
Those things aren't just an engineering study.
They are real changes in the field
that require infrastructure changes.
Let's see,
evaluate increasing TSP demand response programs.
This is kind of goes to,
there's megawatts, various scarcity condition.
There are megawatts out there that could be accessed
that we don't currently access
for voltage reduction.
Through voltage reduction,
we can get access to megawatts
that could be reduced on the system
during a scarcity condition.
Once again,
I think that's
that's something that we ought to explore,
but it does cost money to do that.
It's not, they're not free megawatts,
but because they cost money to install the equipment,
to be able to do that.
But they are megawatts that, you know,
hundreds of megawatts even
that we could reduce load
and keep from having any kind of load shed,
because this is a, this is not load shed.
It's actually just reducing,
it's reducing the voltage of the megawatts
that are out there,
which actually reduces the power requirements.
And so we can get a real load reduction
without anyone seeing their lights go off
by employing this.
Will: And how many Lori: Woody,
Will: How many megawatts, I'm sorry Lori.
-: We spent a lot of time talking about this issue
at the TDU work session, because I know ERCOT
and I visited with you and others there at ERCOT
about this concept
and how there could be potential opportunities and benefits
by increasing voltage reduction with the TDUs.
However,
based on the feedback I got at the TDU work session,
it did not sound like there was a lot of opportunity there.
The general feedback,
I know Encore has a voltage reduction program and
but it didn't seem like there was a lot there
from what the feedback I got from the TDUs.
Can you reconcile that for me?
Woody: Well,
I guess a lot is relative term there,
we've seen studies that showed
that there were several hundred megawatts
and that could be the difference between
an EA2 and a load shed.
So I'd much rather have voltage reduction program in place
than go into a load shed.
Lori: But you need special equipment, right?
You need additional equipment
that the TDU needs to invest in.
-: That's right. Lori: So,
if we wanted to be able to drive that kind of solution
or assistance,
we would have to provide a cost recovery mechanism
because I don't, it doesn't sound like the TDUs
will just go invest in this equipment.
Encore has proactively done that on their
based on their own business decision but,
it doesn't sound like
there's a lot of appetite for that
based on the feedback I got at the last work session.
-: That's correct.
It does, they're not free megawatts.
They do cost infrastructure in order to,
to get at them.
But from a, from a customer standpoint,
customers would not feel a difference in usability,
it's megawatts that we can take off the system
without affecting anyone,
but it does cost money.
Will: In ballpark, it's like 300 megawatts.
Woody: I think it's more than that even.
I think I remember seeing studies that say six
or 700 megawatts,
potentially.
I mean, that's a study.
Peter: Okay.
And we can look into cost per megawatt
relative to other resources.
Woody: Sure.
The next thing here is implement weatherization requirements
for wire companies.
We, we talk a lot about that,
that that it's underway.
We've got RFPs out.
We got the, we're moving forward with that now.
So that's, that's certainly moving forward.
Require meter read data to be sent to ERCOT
for industrial customers,
for industrial IDR meters within the same timeframe
as smart meter data.
This will aid in our forecasting
or the demand response for CP.
So we could look at what happens today
and make a forecast of what happens tomorrow,
if we had that data in
that's really valuable data.
I mean right now we are, we are that
we're not able to have good strong for CP
or demand response forecasting based on prices.
It's just
Peter: What's the largest impediment
to getting that implemented?
Woody: Just how long it takes.
I mean, the forecast,
the impediment is we don't get the data fast enough
to see it.
Peter: What's the impediment to getting
that done?
Woody: Okay.
There's, there's two,
there's an NPRR that's been passed
and that makes this more possible.
I think all the TSPs are just not on the same page
as far as adopting this.
So it's something that once again,
they have to spend money to go out
and change these meters out
and change their accounting systems.
The road has been cleared to do this now.
The NPRRs have been past the load profiling,
working group has done a lot of work here.
They're actually gonna produce a matrix
that shows what each TSP has
and where they're going with it.
So this is now changing things in the field
in order to make this work.
Change and changing accounting systems
so that they can read those meters.
So that's the getting 20 TSPs to you know,
adopt all of this and implement it.
Peter: Okay.
-: Dispatchable generation concepts.
So when I'm talking about dispatchable,
I'm mainly talking about thermal generation here.
Number one on the list here,
is improve the accuracy of the current operating plan data
from thermal generation.
We just need better COP data.
We, I can look at my,
I can look at my COP data right now
and beginning at 1:00 AM this morning,
I don't have much.
And so it's hard to do studies for tomorrow
when we don't know exactly what generation is gonna run.
So having better COP data
will make us have better reliability studies
for the next day, two days out, three days out,
better outage coordination.
Everything will be better,
if we have better COP data.
Peter: To make sure we're hearing that correctly,
as of 1:00 AM this morning,
you had very little idea what generators
were gonna be running today and tomorrow?
-: Yes.
Will: That's a great segue into some questions.
Okay.
So what do you, before we lose you,
I want to get you on the record on a,
on a question.
As an ERCOT Operator.
-: That's what everybody on that panel wants to hear.
-: Yup. (people laughing)
-: You might wanna leave.
-: Okay, so in the foreseeable future, I mean,
we can see this, with a high degree of likelihood
that it dominant resources in the ERCOT region
will soon be based on variable
or intermittent sources of power,
do you believe that is in the near future?
-: Yes.
Will: Okay.
Do you believe ERCOT needs a greater degree
of command and control capabilities to manage reliability?
-: Yes.
-: Okay so,
so that's an important premise that all this is,
is somewhat based on any tools
that we try to develop to give you
should be with an eye
toward enhancing your command and control capability
to smooth this out.
-: Right.
-: So how much visibility into the future
do you need as an operator?
Do you feel comfortable with, with that,
with that variable resource mix
that maybe out there,
what duration of a planning horizon do you need?
And that relates to these COPs, you know,
to know that someone's gonna be there,
it's gonna be able to perform.
Woody: Well, let me,
let me make it distinct distinguished
between renewable generation and dispatchable generation.
So wind and solar generation,
their COP data is based on a forecast that we give them.
So they're putting COP data in telling us
when they're gonna run
based on a forecast that we give them.
And that forecast is based on, you know, wind forecast,
weather forecast, solar forecast.
And so those forecast, that COP data is I think
the only way to improve that COP data
is to have better <v Will>Forecast.
-: Better forecast.
Peter: That's an educated guess, not a guarantee.
Woody: That's right.
It's a, I mean as,
and we have improved those forecasts
over the years.
Will: Right. -: But I mean,
I think there's a limit to how well you can,
how well you can forecast the wind speed
at a panhandle wind turbine, three days from now.
Peter: Also note that's ERCOTS responsibility,
not the generators, but in the current framework.
-: Do the generators conduct any of their own forecasting?
-: Yes, I'm sure they do.
And there was a time when they put in their own forecast
and that was changed a few years ago
to put in our forecast because there was some,
there were some problems with that.
So now,
Jimmy: Was that like over forecasting
or under forecasting?
Woody: Typically, over forecasting.
Will: So yeah,
on the dispatchable side in terms of an operational,
you know, timeline up, a look ahead.
Woody: So I think,
I think one.of the changes that was made
with the recent legislation
that helps in this command and control kind of thing
was the outages, the approval of all outages,
that was a big step forward.
And I think that will help.
We also have our outage evaluation,
the being able to pull outages or delay outages.
That process is an important step.
And we've used that this year and it worked
that advanced action notice that we put out
and the ability for the market to voluntarily delay outages
or bring outages back early, or though that's a,
that's a powerful tool that we have
that still allows the market
to make market-based decisions.
So those are, those are positive steps in that direction.
Will: Okay.
So, I'll let you go on to RUC
and kind of talk through that concept too.
So. Woody: Okay.
Yeah, evaluate removing the, the RUC opt out provision,
potential market change that could have an effect
on how units commit in the day ahead market.
Will: Yeah.
So right now they can opt out,
and you still have a backstop
where the described reliability must run.
And RUC, you know,
and how these two kind of work together
as a fail safe mechanism
for ERCOT command and control currently.
-: Well, reliability must run.
Designation is for a plant
that wants to leave the system permanently.
Will: Permanently, right?
-: And so if we think that
if we do some studies that show that that plant leaving
is gonna leave a hole in the system,
a reliability issue in the system,
and maybe some transmission needs to be built
before that plant can retire.
Then we may designate them as a reliability must run
until that transmission can be built,
there have been times in the past
when we use that reliability must run designation
for capacity reasons as well,
so that you could use it in that.
Jimmy: But most of those RMR designations
are primarily for voltage issues.
Is that right?
Woody: Voltage and transmission issues, yeah right.
Lori: So when ERCOT evaluates
Jimmy: Not energy capacity issues?
Woody: Not for capacity, no.
That hasn't been used in a while for capacity,
but so the most recent RMR examples
have all been for transmission.
Lori: That addressed my question.
I just wanted to highlight that you,
when you evaluate an RMR,
you mostly evaluate that requests
from a transmission bird reliability perspective.
-: Right, yes.
Will: So that gets to cost allocation, you know,
and how you pay for this stuff.
Woody: Right.
-: And so RMR incredibly,
it's viewed as incredibly invasive in the market.
You know, you're not letting someone leave.
Some would say nationalizing an entity.
But so RUC, they can opt out and they can leave.
What's your default position
if nobody wants to be RUC?
Peter: Well, they can, they can opt out of running.
They can opt out of the RUC frame, the RUC option.
-: Yeah, so clarify that.
-: So,
if we're looking at tomorrow
and we don't think there are enough,
our studies show that there's not a sufficient generation
to match load and have reserves.
Then we will RUC a unit,
reliability unit commitment.
So we'll require units to run.
So those units then have the option
if they take the,
I need Kanun up here to help me with this,
but if they take the RUC,
then they get paid for their costs.
So they get their operating costs or fuel costs
they take that if however,
they can also choose at this point,
they can choose to opt out of that RUC
and act like they've been in the market the entire time
and bid into the market.
So that's the that's the opt out provision
is it's a, it's a way for them
to opt out of, of being required to run,
they still have to run,
but they can act like they had bid into the market
from the beginning.
Will: That's exactly what it was.
Peter: Yeah, free call option.
So you can take your cost
or you can still opt out of the cost only payment
and have a chance for some profitability.
Is that fair, Kanun?
Kanun: Yes, I mean Woody got it spot on.
The only thing I would add
is if you look at the incentives
and tie this all back to COPs and everything like that,
the reason why this is being suggested is
RUC is at cost.
You know, your costs are made whole,
but you don't get any of the upside
by having the ability to buy yourself out.
You don't necessarily need to show what you're gonna do,
ERCOT RUCs you.
And then if there is upside, you buy yourself out.
And if there is just downside,
you stick with the RUC.
That that's the link to the other things
that we had talked about in terms of incentive structure.
Jimmy: If you opt out of the RUC,
does ERCOT still get the value that they wanted
when you were in RUC?
Kanun: Absolutely.
Because the unit is saying I'll run
and I'll run at the market prices.
You don't need to claw back, you know,
money I make in excess of my cost
and things like that.
So RUC is limited on upside return,
but you don't have any downside.
Jimmy: Right.
-: So the unit runs regardless.
Will: And that's the goal for ERCOT.
They want to know that those megawatts will be there.
-: But in terms of,
I think the challenge for Woody and the operators is
by having the opt out provision,
a generator removes by staying out of the COP,
they eliminate their price risk or minimize it
because they can wait and see, is that fair?
Kanun: Exactly.
That's spot on.
I mean, the unit is,
and the owner are doing what ERCOT needs.
It's just the visibility into what they might do
going into real time
is less clear or there's an incentive
to wait and see what happens.
Jimmy: Do you often have generators
that are in the RUC stay in it?
Or do they always opt out
to that energy price in the market?
Kanun: It completely depends on
the real time pricing that's happening.
So,
if there is, if the expectation is that,
and in current status
the real time price is high enough
that there is a profit for them,
there's every incentive for them to opt out
if that price can last long enough,
if it's pretty clear that that's not gonna happen,
then you're likely to just take the RUC instruction
because otherwise you would run it a loss.
Peter: Okay, thanks.
I know we have a few more minutes left with Woody.
-: So improving the resource outage reporting
and the outage scheduler, I think that's a,
a major area for we continue to work on
improving the accuracy of the end times of outages.
I mean, that's a hard call for generators to say,
I need two weeks and then it goes longer or go shorter.
I mean, that's just something
we'll continue to try to improve.
Lori: Woody,
does this all fit in to your maintenance presentation
you provided us at the open meeting,
how ERCOT's gonna try to provide
more visibility and transparency into the outage,
maintenance outage process?
Woody: Yes, yes.
Yeah, that particular bullet, you know,
improve the accuracy of the end times of outages.
That is not exactly in that, but this does,
this does fit in, in what we talked about earlier.
Lori: Does your council expect
to be following protocol revisions this fall?
Woody: Yes. -: Okay.
Yeah, we sure do.
And the fact that requiring all the reporting
of all forced outages,
that's NPRR1084 that has been filed.
So that just means in the past,
if a forced outage was less than two hours,
it didn't have to be filed.
And now it does, or if this passes, it will.
A modification of the 60-day rule
for outage disclosures
that's that has been soon to be filed NPRR
that will this June through September outage report
that will make that a permanent report.
So there, those are some changes in those,
but from a market design standpoint, you know,
outage reporting is a big,
we've got to have accurate outage reporting.
Timely updates to HSLs
to our high sustainability limits,
to improve the PRC measurements,
the physical response capability measurements,
NPRR1085 has been filed along those lines.
We did see some PRC issues dUring winter storm Uri.
So during the frequency event,
we had a PRC
that was higher than it should have probably was.
A reported PRC that was actually higher
than it probably was.
And I think part of that was a lag
in getting those HSLs updated.
And so NPRR1085,
is currently in the market participant process.
They're looking in, debating it.
I mean, there's a good debate out there
about a resource operator that
spends time stabilizing a unit
that's having problems and then updating the HSL
or you know, that's their main priority.
And we would rather have a generator online
with an inaccurate HSL
than have a generator offline.
So we understand that,
but there still is a need to get that those HSLs updated
in a more timely manner.
We've got their winterization requirements.
Of course, you guys know about that,
we're working diligently with the BC staff
on doing that.
In fact, I've got an interview
with the Director of winterization right after this.
So that's why I'm leaving,
is to do that interview.
Peter: That's important,
we're gonna make sure you make it there.
Woody: Establish a process
where ERCOT can obtain proprietary
and confidential natural gas delivery,
limitation information.
I think the mapping process that's going on
with the gas industry is gonna help us a lot
in that area.
So we're looking forward to seeing the results of that.
And finally,
for a inverter-based resource concepts,
require inverter-based resources
to have additional reliability attributes,
such as grid-forming capabilities.
So inverters are changing,
they're getting better and better.
And it's important from a market design standpoint,
and from a reliability standpoint,
that we continue to require the newest and best requirements
for inverters.
The sooner we adopt those,
and sometimes that may mean
that you have to change PUC accepted rule and a protocol,
but it's the sooner we can adopt those rules,
the less grand following you have to do
for old inverter standards.
Peter: When you say they're getting better,
you related to, what does that mean?
Woody: Well they're in
Peter: In terms of they're just synthetic inertia or
Woody: The characteristics of synthetic inertia
is one the,
the characteristics of new inverters
are provide more reliability of the system basically.
And so as we have a lot of inverter based resources,
it's important to have good standards
for what those inverters are.
And to let people know,
if you're gonna build an inverter base resource,
this is the standard you need for the,
for the inverter.
And so the faster we get those implemented
from a reliability standpoint,
the better off we're gonna be in the long run.
Improve Resource Outage reporting,
and the added scheduler once again,
for that's the same bullet
as for the dispatchable generation,
it's not as big a deal for wind and solar
because a lot of times,
if you've got a hundred turbines and you take three out,
it's a derate.
And you don't take in the whole plan out.
And so it's a little different game there,
but it's,
it's still important to have accurate outages.
We've got the weatherization requirements
for wind and solar as well.
Those are proceeding, and I've got one item here.
I didn't include in the original list.
And that was to implement requirements,
to provide and maintain accurate dynamic models.
We have a lot of trouble getting good,
accurate dynamic models.
And I think wind and solar owners
also had the same treble from the manufacturers,
getting those, getting those up-to-date accurate,
dynamic models.
And in order for us to do those stability studies,
we've got to have done good accurate models
and getting those is a challenge.
Peter: All right,
thank you Woody.
Quick of when your remaining time,
can you expand on the inertia challenge
and how as we have increasing share of generation
from inverter based resources,
how that balances with rotating mass,
and if we can ever get to a point
where we don't have rotating mass,
just based on the physics of it.
-: With the current technologies that we have today,
we'll never get away from that.
Now, I'm not saying that in the future
there won't be a time when we can do that.
And in fact,
there are some very small grids in different places
that have gone.
Peter: And why is that?
-: Because of the grid forming type inverters
that they've been able to install.
Peter: No, but why,
why would we not be able to get away from rotating mass
with current technology?
-: Because we don't have those grid forming inverters
installed here.
Peter: I guess what is the benefit
for the public and understand
why is rotating mass and that inertia required
for stability?
-: So the there's a,
whenever you have it in balance of grid,
of generation and load, you lose load,
or you lose generation, load exceeds generation,
frequency will decline.
If you have low inertia
that frequency declines very quickly.
If you have higher inertia,
the frequency will decay less quickly
and relays and stuff are set
so that you want that decay and frequency
to be slow, not fast,
if you don't have any inertia in the system
that frequency falls off too quickly.
Peter: So is it,
I'm gonna put it in simple terms I can understand or trust,
see if I can get this right.
Is that the rotating mass provides the inertia
as large rotating objects,
provide the inertia a heartbeat if you will,
of that frequency throughout the grid.
And as you have fewer and fewer
pieces of rotating mass,
that pulse, that heartbeat, gets weaker and weaker.
And as a frequency
or gen and load come up and go down,
it's harder to maintain that frequency
and without substantial,
without it sounds like without enough of that inertia,
that rotating mass inertia,
you could lose control frequency completely
at some point down the road.
Woody: Right.
So that's really the inertia keeps frequency
from decaying too quickly.
That's the bottom line.
And fast decaying frequency in the system
is dangerous for reliability.
(crosstalk)
-: Causes the whole thing too?
Woody: Right.
So we have safeguards for frequency going down.
It takes time for those safeguards to be deployed
if frequency decays too quickly.
Those safeguards can't be deployed fast enough.
So that's why we have a minimum inertia
that we maintain all the time.
And if you think about the, you know,
35,000 megawatts of inverter-based resources we have now
that don't have any of that grid forming inverter,
we have those, those are there now.
That's why I said with the existing technologies
that we have right now,
we will have to maintain inertia.
We'll have to have synchronous generation
Jimmy: And I was gonna ask the question
about batteries again, you know,
synthetic inertia that comes out of these,
these newer batteries,
they can solve frequency problems
in a sub-cycle instance, is that correct?
Woody: In a short term
Jimmy: And what we're seeing, I mean,
not everywhere,
but from where we can see and what we know about,
you know, these larger batteries that can happen.
-: Right.
Batteries are certainly a useful tool
for short term frequency problems.
-: So is that the thought process
by creating the fast frequency response service?
Woody: That's right.
That's the frequency responses for
Peter: That wouldn't replicate inertia
in the long term.
-: There is a longer term inertia issue there.
Jimmy: Yean, and that's
but in the longer term you're gonna have,
if solve the short term sub-cycle frequency issue,
you'll have other tools at your disposal on a longer term.
-: Right.
-: In the longer term to resolve that issue,
is that correct?
-: If you have synchronous generation online,
you will. Jimmy: Correct.
Well, that's a good point.
-: So to follow up,
you're talking about interconnecting,
all the the new inverter-based technologies
that are coming to the system you would require
the latest technology that helps assist you
and smoothing this out?
-: So there are no requirements today,
Will: but you're working on it?
-: They are,
we are working on them,
but there are no requirements today.
So that's an upcoming change. Will: Right.
So how do we get at the 35,000 megawatts
of inverter-based technologies that's already in the ground?
-: That's a good question.
Will: Yeah, no kidding.
Peter: And do we need to think about
how we maintain,
even with a financial incentive
or scheduling protocols,
to make sure that we at a nodal basis or L&B basis
don't ever get close to that inflection point
where the protocols gets too weak.
-: You can,
you can reliably operate the grid with those,
with those inverters,
you just have to have synchronous generation go with them.
So it's not that they pose a reliability issue.
They just repose.
They just pose a reliability issue
if you don't have synchronous generation.
Peter: But what's the ratio?
-: That, you know, we have a ratio we run
every second of the day that we watch.
So it's 110 gigawatt seconds is the minimum.
And, you know, yesterday that ratio,
that number was 350 gigawatt seconds.
So we're way above it.
There was a time in the fall of 2020
when it got down to, you know, 110 or 111,
something like that.
So we have reached times when the system load
is you know, in the 30,000 megawatt range,
that a lot of that is being supplied by wind
and solar inverter based resources
that we have to start paying attention to that,
we've never had to RUC a unit, a synchronous unit,
to maintain inertia,
but we, we monitor it and we watch it
Peter: and we've gotten close.
Woody: We've gotten close once.
Where we had to start thinking about it,
but we didn't have, I mean, it didn't,
we didn't have to.
Lori: Would you say that that possibility
could increase in the future
as we have more wind and even more solar
coming onto the system?
Woody: Certainly.
Lori: Like the duck curve situation in California
does that translate into what you're addressing right now?
Because you have wind, I'm sorry, not wind,
but load coming off the system towards the evening.
Woody: Well.
It's, well, when the solar drops off,
it's not as big of an issue as one that's on.
So it'd beat the back of a duck, I guess,
if you wanna use that.
But certainly as you,
as the ratio of inverter base to synchronous generation
is that changes you can expect that inertia value
to continue to change as well.
Lori: Are there transmission related solutions
that could help between the balance there?
-: Very limited.
There are a couple of things you can do,
but it's very, very limited.
It's not a system wide fix.
Peter: All right. Thank you, Woody.
We've kept you three minutes over.
Woody: Oh, thank you.
-: You better make that interview.
It's important.
Thanks, Kanun.
Barbara, welcome.
Barbara: Thank you.
-: The floor is yours.
Barbara: I'm really here today
to kind of bring us back up to maybe,
well, not really 30,000 feet,
but an introduction to what's going on
in the rest of the markets, how ERCOT is similar,
how ERCOT is different.
And we'll kind of get into some details on,
on just market design principles In general.
If we can go to the first slide,
CES covers all of the North American markets
including Mexico,
I'm not really gonna talk about Mexico today.
You might know that their market reform
has cratered under the current administration
in Mexico.
So they, that market design elements
really haven't been implemented there,
but we do look at all of the other North American markets,
and I've included details on their market designs
in this report and we'll talk a little bit about those
and how ERCOT differs, and then really, you know,
I think this should be interactive
and linking sort of talk about how differences
and what the nuances are.
Next slide.
So, I first wanna kind of
just get into the fundamentals of market.
Electricity is an unusual commodity
and that it's instantaneously produced and consumed.
We don't have a lot of storage in ERCOT yet.
We are not a region with a lot of pump storage
or any other optionality
on the hydro side.
So we really are looking at
kind of a keeping a system perfectly in balance.
And we also are looking at keeping markets
and reliability in balance.
And that means you don't want too much action
on the reliability side,
where out of market activities are happening
and you don't want the markets to work in such a way
that you compromise reliability.
So you're always trying to keep those in balance.
The markets in ERCOT are voluntary markets.
They are dispatched on an economic basis
now that's security constraint economic basis.
So the security constraint part
is the reliability part that make sure
that the grid security is always in check.
When units are dispatched,
that market side is based on offers and bids.
So you have willing buyers and willing sellers
in the market that are, have their prices.
They have bids and offers in the market
and they're sophisticated buyers and sellers.
This is not a market that typically, you know,
we're looking at unsophisticated buyers and sellers.
Occasionally we have people
who don't understand the market rules,
but for the most part,
it's a very sophisticated market.
On the other side, the reliability construct,
it's a mandatory construct.
It's what he was spending most of his time talking about.
It's things where you don't wanna void,
cascading outages.
You want to ensure that the system is stable.
You're looking at voltage, frequency, inertia,
all of those things are critically important.
And that's a mandatory construct.
They're relatively cost agnostic
on the reliability side.
Now, obviously ERCOT is not, you know,
not thinking about costs when they do things.
But for the purposes of reliability,
you're really not looking at a market type construct.
They're looking at supply and demand
versus bids and offers.
So they're looking at keeping that supply and demand
as well as reserves all in check.
And they're really looking at it
from an operational perspective
versus a market perspective.
And when it's in balance,
you kind of get to this economically optimal model
and in ERCOT that
that's really how we kind of develop our reserves.
That's not the way reserves,
planning reserves are developed in other markets.
Other markets have a different construct,
but at under the energy only model,
we really do kind of balance that reliability and markets
to come to an economically optimal outcome.
And that gives us our resource adequacy.
So let's go to the next slide.
So what happened?
What happened in February?
Well, in February we saw snow and ice and cold
and extremely dramatic weather conditions.
It was not a market issue.
There were market outcomes because of the issues,
but it was a reliability event driven by weather.
And that led to high costs in the market
that you have spent the last three days.
I think Commissioner Lake, you got the buy,
which I'm sure your colleagues are a little jealous.
Peter: I would never call it that.
(people laughing)
Will: Yeah, he's fresh.
Barbara: But yes,
you get high costs and low operating reserves.
That's an event you don't ever wanna happen.
And that was event that frankly,
the market could not cure.
And we saw that.
We saw that in February, we have not seen
many of those types of events
across even North America where, you know,
you cannot fix something through either market
or at least reliability dispatch.
So it was a really unique situation.
I will credit ERCOT in the fact that we did not end up in a,
you know, cascading outage situation.
So, you know, it was a terrible event,
but the imagining what would have happened had we cascaded,
would have been, you know, just devastating for the State.
So, go to the next slide.
So that kind of led to where we are today.
(Barbara chuckles)
For good reason.
You know,
the pendulum shifts a little bit when you have a,
have a major event in any market.
And we always like to say that sort of,
it's always a push and pull between the reliability folks
and the market folks on,
on what the best outcomes are.
And after a emergency event,
you often see kind of the operational side,
there would be the reliability side,
kind of weigh a little bit more
in what they're doing.
And we see more out of market activities.
So we're seeing more reliability unit commitments
this summer than we have in any other summer,
despite the fact that it's actually been unseasonably cool.
We're seeing more ancillary services being purchased,
all of those with good reason
because of concerns around grid security.
But at some point we want to get that pendulum back in order
and determine kind of what that longterm planning horizon
is gonna look like, what the market wants
as far as kind of that system stability.
And then we'll get that resource adequacy back in check.
Next slide.
So you guys aren't alone.
This list was developed in 2000 or in 2018
for a slide presentation I did
for the Gulf Coast Power Association.
And all of the RTOs are facing very similar issues
to what ERCOT is facing.
This is not new, and there's a lot to be learned
from what the other RTOs/ISOs are doing.
Most are facing challenges
with higher renewable penetrations
and looking at their markets
as they see higher renewable penetration,
they're seeking market based solutions
to incentivize flexible generation
to balance the system
as it brings in more of that variable energy.
They're looking at required,
and expensive potentially, new transmission investment
to link wind and renewable resources into the grid.
Also transmission necessary for congestion
and other things,
but significant new transmission investment.
Not so much here in Texas,
because we're a single state RTO, but you know,
the RTOs are looking to balance state
and other policies that are extra market.
Here you know,
the best example is probably the ITC
being an example of kind of something
that bolsters certain investments over others
and might lead to, you know, more of those,
those renewables being built than others.
But you know, there's a lot of local policies
that do influence how markets react.
And then finally, and this again,
this list was developed in 2018
and I kept it that way,
but addressing field security
and concerns related to winter events and other events,
we have been in the Northeast talking about this
for the last, you know, decade really
following several different winter events,
New England suffers from sort of
being at the end of the pipeline
and often have fuel security concerns throughout the winter.
So there's a lot to be learned
from those other markets on what they're doing
with regards to coordinate good coordination
between the pipeline companies and the energy providers
to ensure reliability during those times of constraint.
So this slide is a doozy,
and I appreciate that when you look at it,
but I wanted to have all the markets together
so that we can have a fulsome conversation
about each market together.
And I'm just gonna kind of run down
on the left-hand side each of the market types
and elements, and kind of talk a little bit about
what each of the markets are doing.
So the first one is a centralized capacity market.
There are centralized capacity markets
and all but two markets in some way shape or form,
California has a supply side obligate
or a load side obligation
on their largest utilities
and load serving entities.
So they require them to maintain a certain number amount
of reserves and contract for their supply.
In the other RTOs,
we see the Ontario is just developing
a forward capacity market
isn't incremental forward capacity market.
It is looking at new investments
rather than writing capacity payments
to existing generation.
And then all of the Northeast markets,
as well as MISO have forward capacity markets
and SPP has obligations on the utilities,
so that utilities are required to maintain their reserves
and contract for their reserves.
So, it's only Alberta and ERCOT
that don't have forward capacity market.
That means that we are energy only markets
and you know it is a difference
and it does drive to what Brattle has looked at,
which is the economically optimal model,
which means at times you are going to have scarcity events.
In fact, that's where, you know,
generators make their revenues
in order make new investments.
So the scarcity events are somewhat required
under the construct that ERCOT has.
We certainly don't wanna see events like February,
but you know, sub small price excursions
when there are shortages in the market
are really what drive revenues for generators
and drive investment in the future.
And those forward curves
that you were talking about earlier.
The next contract is a day ahead market.
Most of the markets have day ahead markets.
Canadian markets are just developing day ahead markets,
but all of the US markets have day ahead markets.
Financial Transmission Rights,
pretty standard offerings in all of the markets.
Offline Reserve Market,
that's your non-spinning reserve service
in all markets.
And that is actually a NERC requirement
to have an offline reserve product.
The next one is one that I, you know,
we should talk about and that's a ramping market
that has been introduced in MISO and in California,
as they have seen new remote renewables in their markets
and having an ancillary service ramping product
in the market, first of all,
provide some of those incentives that we've been looking for
for flexible generation.
So the flexible generation that exists in the market
as well as potentially new flexible generation,
as we start to see some of that,
that pricing in the market.
And there's transparency for investors
to know whether or not they can earn in that market.
But a ramping product would help with those times
when solar is coming down,
when coming up in the mornings and evenings.
So it's certainly a product that is something
that we should be looking at in the ERCOT Market,
given the amount of renewables
that have in the market.
Real-time market, everybody has real-time markets.
In fact, it's you know,
it's really where the actual transactions
between the conversion of energy happens.
Regulation markets are required,
and some of them are contracted service,
and some of them are in the real-time market only,
and not in the day ahead market.
And we can talk a little bit
about how those transactions happen
and then synchronous reserve markets,
we obviously have a synchronous reserve market.
So getting into market pricing.
Will: So before you move on,
Barbara: Yeah, sure.
Will: if we could ask questions
Barbara: Absolutely.
-: Physical day-ahead markets.
Barbara: Yep.
-: Okay.
Who has those?
-: So the markets that have forward capacity markets
to have forward obligations
Will: All of them?
-: So New England does not.
New England has a must offer requirement in the real-time,
but no must offer in the day ahead market.
But the other markets with forward capacity markets
do have a day-ahead offer obligation.
There are not day-ahead obligations in the markets
that do not have a capacity markets.
Will: Do you happen to know what the
system wide offer cap is in Alberta?
Do they have a system wide offer cap?
Barbara: Yeah, their offer cap is a 2000.
Will: Okay. 2000 appears to be
Barbara: Oh wait, wait, 1000 pardon me.
Pardon me, 1000. Will: 1000, 2000,
kind of appears to be universal range.
Is that accurate?
-: Yeah, one to two,
so the FERC went through a market pricing rule,
a scarcity pricing rule
that many of the markets now
have a verifiable option above a thousand dollars
that can go up to $2,000
and then they'll have shadow prices
that would actually take the potential market prices higher,
but the, the offer cap is a thousand dollars
or verifiable costs up to $2,000 in most of the markets.
And there's some nuances there,
there's some differences there,
but for example, SPP, you can offer up to, you know,
you can offer whatever you want,
as long as you can verify it, but you know.
-: How unique are we in this spectrum?
And you might get to it.
The ORDC Paradigm.
Operating Reserve Demand Curve.
-: So,
there are penalty curves in most of the markets,
similar to the operating reserve demand curve,
they're administrative curves,
they have penalty factors,
and they're based on the probability
of loss of load probability
and the value of loss load.
So similar constructs
and PJM is introducing starting in May of 2022,
an operating reserve demand curve
that actually goes up to $14,000.
Will: Wow. Barbara: Yes.
Will: That's expensive.
And a capacity payment?
Barbara: And a capacity payment.
-: Wow. -: Yeah.
-: Neat, for them.
(people laughing)
-: I wouldn't want to be paying electric bills.
-: Me neither.
Barbara: You know,
we will be monitoring it as it gets implemented to see,
you know, what impact it really has on real-time prices.
My expectation is it's gonna be, you know,
pretty limited amount of events
would get to anywhere near that price, but it does.
It's a longer curve.
And then when there's been a lot of comments in,
in this docket talking about, you know,
changing the slope of the curve
and the PJM curve although it does have that high cap,
it takes a little longer to get there. So.
Will: So if they get into a big blizzard,
which they're accustomed to having in those areas
and a lot of freeze,
could they stay at 14,000 for awhile under that model?
-: They could.
Will: Wow. -: They could.
Typically they handle those reasons a little better
than Texas does.
So typically those events are, you know,
they do have those types of events.
They have fuels security type events,
but typically they resolve a little better
than we've had experience.
But obviously,
they both the NERC
has changed their weatherization requirements
for power plants.
There's been new NERC requirements put in place.
And all of the Northeast markets have really been
spending a lot of time on fuel security issues
as it relates, especially the you know,
as it relates to capacity that is getting a capacity payment
and ensUring that there's a fuel security for those
those units that have,
that are making those commitments into the market.
Peter: That's part of the paradox, right?
Like the whether it's 2,000 or 9,000 or 14,000
from a reliability standpoint,
nobody ever wants to get there,
but that ORDC is there to provide the incentive
and the revenues for people who are able generators,
who are able to provide generation when it's needed most,
but we never want to need it that badly.
Barbara: Yeah.
I mean,
the thing about these high caps is first of all,
nobody wants them.
Generators don't want them because it turns out that,
you know, when it happens,
typically some generators are short and that's you know,
where we're at, we're at high prices.
So those generators are having to resolve their obligations
in the markets at very high prices.
Loads don't want them because there's very high prices.
Now there's hedging around, you know, the exposure to those,
those prices.
Peter: So why do people keep doing them?
-: Yeah, so we talk about the operating reserve demand curve
in absence of the hedges that actually exist in the market.
And we have to be, you know.
Most thermal units,
there's very few merchant thermal units.
In fact, I can't think of one right now.
There are, there are some, you know,
limited merchant units in the ERCOT market,
but everybody else is under a financial hedge of some sort.
So they are not actually getting
the operating reserve demand curve.
What the operating reserve demand curve does,
is it signals the need for new generation
and hopefully pushes those forward curves up
and pushes the value of the next PPA
that someone signs.
But for the most part you know it's,
Peter: So, under the current construct,
the only way to send market signals
for future generation, for future new generation
is by having a terrible crisis,
which spikes they already see.
Barbara: Well, we hope that we get nuance signals
throughout the year
that are not at $9,000 but maybe higher
than the marginal costs of the market.
So what you really want is margin.
You want the market to be above the marginal cost
of units in the market
and that clearing price to be higher
than the marginal costs.
So there is some profitability in the market.
Peter: So sounds like we need to work on that.
-: Yeah.
-: Work on that part
but there's also the only way
under the current construct, not just at ERCOT,
but from what I understand other markets
with the uniform price going,
and the only way efficient units
can have profitability
is if there are other more inefficient units
that have higher marginal operating costs
to bring that price up.
Barbara: Yes.
-: So marginal pricing in the market is the weight
(crosstalk)
-: If we had all very efficient thermal generation
under the current construct,
nobody would generate a profit
unless there was a terrible crisis.
And so, yeah, we have some work to do.
-: I think people would withhold
to create the crisis to raise the prices.
-: Oh yeah, we got some work to do if that's the case.
Barbara: Well, I hope that's not the case
cause we don't wanna talk about economic withholding
that you know, but people will retire assets.
People will, you know, have seasonal,
seasonally take off their units.
So they won't be running their units in seasons
where they don't think they can be profitable.
So rather than sort of an a withholding,
they may, you know, retire units.
We certainly will see.
And that's what drives us
to this economically optimal reserve margin,
which is relatively low from a comfort perspective
of a typical system operator.
So when you're looking at kind of rattles, you know,
study that came up
with an economically optimal reserve margin
of 10 plus percent,
that number for a lot of system operators is you know,
it's lower than we typically see
in some of the other markets
and a system operator often you know,
will look at that.
And it worked, and that economic optimality
basically requires certain times
where you're going to have, you know,
high prices and the potential for loss of load.
You hope that if it's economically optimal,
you don't get into loss of load conditions,
but you are going to have those scarcity prices.
And that's how the market,
that's how the market operates.
So when you get economically optimal,
you are gonna have those scarcity pricing events,
which you know for regulators and politicians,
and as a recovering regulator myself,
high prices are not fun
because they become political issues.
They become public issues.
They affect load.
They affect buyers in the market and just mitigate that.
But it's one of those, one of those things,
when we see sustained pricing events,
it typically causes problems.
And we end up in discussions like this,
where we're talking about
whether or not that's the optimal market,
that being said,
the energy only market has been extremely successful
in Texas.
It has driven prices very low.
We have not seen a excessive amount of retirements
in the market.
We are keeping units in the market.
We have the event in February
was not a event based on margins.
It was a weather event that's you know,
it was an operational events, not a you know,
event that we could have foreseen.
We had great planning reserves going into kind of you know,
that event.
But unfortunately the operating reserves
didn't come to fruition.
That was not really a market event,
but certainly, you know we,
we don't want those, you know,
price excursions to last a really long time.
Peter: Sure, but -: No one wants to see that.
Peter: the only way new generators
or new investment in a dispatchable generation can happen
is if we have these crisis events,
say they put the price signals out there
for the forward curves.
Barbara: Not,
so we're not looking at crisis events.
What we're looking for is the marginal,
the prices in the market to exceed the marginal cost
of the existing generator, such that there's a profit.
Peter: Sure.
So I guess the point is, as long as we have the bonus,
the RCD bonus associated with
increasing scarcity,
so you own revenues are only generated,
profits are only generated
the closer we moved to running out of reserves.
Barbara: So,
the profitability depends on the efficiency of the units.
So an efficient unit is going to make more money
than a less efficient unit in the market.
The operating reserve demand curve,
as much as it does influence profits in the market.
It's not something any investors looking at,
because it is driven by operational events.
Peter: We heard earlier
that that's what sets the price signal for forward curves.
So my question is,
does anybody has any market out there?
Barbara: So the market clearing price sets the price,
the operating reserve demand curve
sometimes influences that market clearing price.
But what investors are really looking at
is the average market clearing price.
Sometimes that is influenced
by the operating reserve demand curve.
But we've seen over the history of ERCOT
up until sort of recent events
that that operating reserve demand curve
has not really been significant at all.
And we are seeing investment in the ERCOT market.
We're seeing tremendous amount of investment
on the renewable side.
Peter: What about dispatchable reliable assets?
-: So I would argue that, you know,
that renewable assets do provide reliability.
They are variable.
Peter: Okay, please reconcile that one for me,
because we had a couple of days in June
that we're zero output.
Barbara: So.
-: And we all know what happened.
So please explain how we reconcile that.
-: So you are gonna have days now
during that period in June,
it was sunny and the solar did perform,
and you did have a low wind event.
And we do need to reconcile that
with either storage
or because we are gonna it's variable generation.
And there are times when we're gonna have low,
low wind events,
which means you still need that dispatchable generation.
You need a balance in the system of dispatchable
and non-dispatchable generation, but that,
that low cost supply that the variable energy resources
are bringing into the market
is bringing reliability into the market.
It just requires,
it just requires a workout Peter: How?
-: The same way any megawatt.
I mean, a megawatt is a megawatt.
Will: Yeah, but it's not,
but it's not moving forward.
Again, it's all a game as we heard from Woody.
A percentage basis,
when your dominant resources intermittent,
it becomes it economics work against the laws of physics.
We have to reconcile that.
Barbara: So it depends.
So one of the things that we look at
as you look at more variable resources
coming into the market
is how diverse that those variable resources are.
So we look at the diversity of the fuel source,
so solar wind,
but we also look at the geographic diversity
because that creates more reliability with those assets.
So as you get more and more online,
you get more coastal wind that it does perform at peak.
Peter: Sure.
But you still have days where it's zero,
which happened in June.
And while on average, it looks good,
but in a day-to-day operation of a grid,
you're skydiving.
And if the shoot doesn't open once
the rest of the day is on average don't matter.
Barbara: Yeah.
But that's why we need a balanced system.
That's why we also need dispatchable generation
in the system, we need base load generation.
You need a healthy mix of assets,
but you can't discount the fact
that when they perform and are available,
there are low cost.
Peter: Love the price point, love the carbon profile.
But the challenge and what I'm trying to ask is
how do we get
because right now we can see the forward curves
and the increase, like Lori said,
the increase in that reserve margin
is over the next four or five years
is crushing the forward curves
that investors and generators rely on
to drive new investment and dispatchable generation.
So what, so we clearly need to change something.
Barbara: Yeah.
-: What has anybody else out there
in any of these other markets globally?
Barbara: So that,
that brings me back to the ramping product
that was introduced both in MISO and in California,
for that exact purpose.
To incense dispatchable generation and storage,
to provide that ramping capability
with a payment for that product
to bring in those resources that you need.
And it's a market based solutions.
So it provides a market that values
the capabilities of the units.
So we really wanna look at
at products in the market,
the value of the capabilities of the unit,
it's the same way we don't value
the full range of capacity for renewables,
because we know that at certain times of the year,
they're not gonna be there.
So in the CDR, they're discounted tremendously.
So we do discount those resources
and we want to value the dispatchability of other resources.
And by introducing certain products,
like a ramping product that will allow,
that will create some opportunity for these.
Peter: how long is California
had their ramping product in place?
-: So California's product came into place
in the last couple of years.
I don't know exactly when it was,
I don't have the exact implementation date
and MISO has had theirs just a tiny bit longer.
So they have not had them
for a significant amount of time.
Obviously, California is going through
an incredibly difficult period right now
and are looking at other options as well.
I will say that, you know, California struggles from,
from problems that Texas doesn't have
in the siting of generation.
Siting dispatchable generation in California,
I think anybody who's ever tried to do it
can attest that it is much more difficult
to site generation is much more difficult
to site transmission in California.
Texas has, you know, unique characteristics
that make it really attractive to investors.
So when we are,
when we make create the right market conditions,
people will be quick to move into the Texas market
because it's so attractive to be here as an investor
because of, you know, the market in Texas
and the ability to site generation in the state,
they run the access fuel supply in the state.
And you know that yes, we had some issues
with regards to fuel supply,
but they weren't related to long-term infrastructure.
They were related to weatherization issues
that we need to address.
Lori: Barbara, what about the ramping market in MISO?
-: So the ramping market in MISO
has been around a little bit longer.
It's been a successful market.
I, you know, I think both of them,
the California and the MISO markets
are moving in a direction to attract the right investment,
but they haven't been around long enough to,
you know,
sort of see the kind of fruits of those markets as yet.
And that's you know, I mean,
that's as you introduce new markets,
but it is creating some revenues
for existing dispatchable generation
that may have not remained in the market.
So you also have to look at dispatchable generation.
That's not being dispatched as often
dispatchable generation that may be offline,
that would be offline because of a ramping product.
Lori: And in the MISO market,
is it,
are they dealing with a tremendous amount of primarily wind
or is it also solar? Is it on the rise?
Barbara: So it's mostly wind,
although solar is on the rise as much like ERCOT,
you know solar, solar is more recent,
we've seen more recent solar developments.
They also have a lot of rooftop solar across their system
based on kind of state incentive plans
within the MISO footprint.
So they do have been behind the meter
so more behind the meter solar
than they do utility scale solar,
but they have a significant amount of wind
in the MISO market
and SBP is also looking at a ramping product.
They have a proposal in play in SBP.
And SBP as you well know,
has a significant amount of wind in their market
and are looking, you know, opportunistically
at trying to manage that through a ramping product.
Will: Is that,
I'm sorry, go on.
-: So we had some discussion on the CDR report
and you know how different resources are factored in
are there any,
any aspects of other markets in their reporting
that we can look to to improve our reporting here,
with respect to CDR.
SARA, do they have other reports
that they may use for planning
that we may wanna look to?
Barbara: Yeah, so, you know, depending on the markets,
they definitely have, you know, long-term planning
different long-term planning documents.
I will say that the Texas capacity demand reserves report,
you know, there are,
there are things that might be improved in it.
The ASPLI adequacy working group has been talking about
some of those potential improvements at ERCOT.
But some of the things that you know,
we kind of have always looked at the capacity demand
for reserves report is as sort of the best known fiction
in the market.
It's not, it's never gonna be right.
It has develop MINT has future forecasting
that's typically is a lot more generation
than actually comes into the market we see,
you know, it's a relatively low option
to have an interconnect agreement.
And if you don't have
an engineering procurement and construction agreement
to build your plant,
you know, that plant is
and with a commercial operation date, you know,
it's not as likely that we're gonna see those assets
come into the market.
So I think improving the requirements
to be included in the capacity demand reserves report
and checking on those units that are sort of have had
outstanding interconnect agreements
and have been in the,
for lack of a better term, queue for awhile,
but have not been in constructed
to ensure that we're not counting things
that are never going to be built,
because obviously a developer,
when they're looking at building
either a renewable or thermal assets,
a developer wants to build everything they've got,
but there's a finite amount of capital in the markets.
And all of those projects that are in the queue
are not all going to get that amount of capital.
So not everything is gonna get built in these markets.
So that's one area.
The other area that the capacity demand reserves report
probably suffers from
and this is not actually as much a renewable issue
because we actually count renewable
based on their historical performance at peak,
but there's a dispatch ability issue.
And Woody talked a little bit about this
when he was talking about the transmission planning
and making sure that units were actually dispatchable
as part of the reliability studies
that we have for units.
But when we look at the CDR,
we count nameplate capacity for the thermal units
that are in the, in listed in the CDR.
And oftentimes during certain system conditions,
not all of that, those megawatts are dispatchable.
We have congestion across the market.
So we do need to maybe not in the CDR,
that might not be the document to look at this,
but if you're really looking at what's deliverable
in a system,
you do need to kind of look at what happened
during your peaks, not just on the renewable side,
but on the thermal side,
what megawatts were deliverable during those peaks,
so that we have an understanding on kind of a globe
and that doesn't have to be on a unit by unit basis.
But looking at what was deliverable in the market
is critical when you're in an energy only market,
we get some of that transparency in markets
that have capacity markets, because a,
because of the nature of the capacity market
is that there are penalties, if you don't perform.
An asset owner who's bidding into a capacity market
is only going to bid the capacity
that they know they can perform too.
So they almost bid in those,
those transmission and other limits
that there are no end limits
so that those may be seasonal limits,
they may be limits that they know
that they have for the asset.
So they may only be bidding
in a certain amount of their capacity
into the capacity market.
And that shows up in that capacity market
and shows up in the planning for that reliable capacity.
Peter: And they're accountable
for what they put in there with penalty,
associated penalties.
-: Associated penalties
because they're receiving a payment
to be available and that payment comes in advance
but it does create a condition where they are going to bid
the capacity that they know they can deliver.
And what we account for an ERCOT
is nameplate or discounted
based on actual historical on the renewable side.
So the renewable is basically accounting for
kind of that deliverability,
but we don't account for that as much on them.
Peter: Out of curiosity in the capacity portfolio,
say PJM or any others defer to you on that.
What percent of the generators receiving capacity payments
are dispatchable versus weather dependent?
-: So they take renewable,
but they discount how much they can offer
into those markets.
So it's kind of similar to what we do in the CDR,
you account for the capacity that you might,
not that many renewables bid into the capacity market,
because of those requirements.
So we don't see as much participation by renewable.
We see a lot of demand response though,
in those those markets, because demand.
So there's a lot of demand participation
in the capacity markets.
There's less intermittent resource participation
in the capacity markets.
Peter: Okay, thanks.
Lori: Barbara, can I,
you touched on three issues that I was trying to highlight
to Woody earlier, interconnection requirements
to be included in the CDR report.
And you're mentioning,
I think you mentioned that, you know,
can go get an IA pretty easily with ERCOT.
And from my understanding,
and I've been kind of curious about this,
cause I've heard this in the past
and I'm not sure how accurate it is,
but are ERCOT's interconnection costs
or fees they charge some of the lower fees
compared to other markets?
Do you know that?
-: I, I don't know because the costs
for interconnection studies and those fees vary
based on kind of a TDSP to TDSP
kind of basis around the country.
So there there's a lot of variability.
I don't think ERCOT is dramatically lower
than other markets,
but the cost of entry in many ways in ERCOT,
you know, for siting and you know,
cost of labor,
all sorts of other things are really attractive in Texas.
But, but I mean, in any market,
the cost of kind of an interconnection agreement is it's,
it's not a material costs
when you're looking at building a power plant.
So it's a relatively low cost option
to create value for that development.
Because now that development is enabled in the market,
it makes that proposed development much more valuable
for a developer or to either build that
or take it to a lender
to borrow capital for that, for that project
or to sell that development investment,
because it's a development investment
that it now has interconnect agreement
has permits it's ready to go.
So it creates value.
And in most markets,
a developer is at least going to get to
an interconnect agreements,
create that value before it goes to lenders
or buyers to actually take it to the next level
and actually enter into an EPC agreement.
Lori: So for renewable generation,
it's to site?
I mean, you really just need an IA.
So any other type of thermal resource,
it would be more expensive process for the site.
Barbara: Yeah, so for thermal resources,
ERCOT print planning criteria requires air permits
and water in that criteria to be included
in the CDR for renewable.
There I think is
a land requirement.
Yeah. Site control.
And then, and then obviously an assigned IA.
Lori: So you mentioned financial requirements earlier,
and I know we've had this discussion in the past
on whether or not the wind generation should be required
to provide documentation
showing they have the financing in place for their project
to be able to be included in CDR.
In fact, my understanding is there was an NPRR
in the past that got rejected by the board.
Do you think that type of requirement would be helpful
in our CDR at this time?
I know back then there was an influx of wind
and you know crisis going on and there was you know,
just different,
a little bit of a different backdrop to that discussion,
but in today's market and given the inflow
of wind generation,
do you think that it would help solidify our numbers
in our CDR report to have such a requirement?
Barbara: So, I'm not sure.
There are definitely resources that are included
in the CDR that may never get built.
Frankly it has actually been the thermal resources
that are the ones that have kind of, you know,
sort of trips tripped years.
So they, there was a planning for those units.
We've seen a lot of the renewable generation
that has been in the planning crew criteria
eventually be built.
It may not be in those first few years.
The problem is that
until you really have a COD,
including it in those longterm planning
and you know,
and the COD is a commercial operation data
I try not to use acronyms, but anyway,
you really are,
there has to be a discount factor to that,
that category of planned resources
and most people in the market,
when they look at the CDR,
they look at that section of the CDR
with their own sort of lens on it,
to determine how much they're going to discount
some of those,
those projects that are in that queue.
And everyone has a slightly different perspective on it,
but for ERCOT,
they want to know,
I mean that they have an operating reserve requirement
and they need to know, you know,
where they're going to be down the road
and have pretty reliable information.
So the more ERCOT,
data ERCOT can have on commercial operation state,
and including that in their planning criteria,
the better optics they're gonna have
on where they might be sitting
as it relates to their resource adequacy in future years.
Whether the CDR is the place to do that,
I'm not sure.
But ERCOT does need to have a level of security
that when they look at a 21% reserve margin
in future years, that that's realistic.
And I think at this point, what we've seen is in,
in the near terms,
our reserve margins have typically been between
nine and 12%
as we actually get into kind of operating years.
And rarely do we have, you know,
kind of the 16 to 20% that we actually see
in the planning years.
Lori: It's just the toughest place to be at, right?
Because it's determined like was noting earlier
that our forward markets investors look at,
it could be looking at our CDR months,
amongst the host of other sets of information.
And when we put out that report
and it shows high reserve margins,
it sends a signal and
or doesn't. -: Not the way we wanna send.
-: And so that's why we're so interested
in figuring out a way,
if we're gonna continue to have a CDR report
that we provide a more meaningful picture.
Barbara: Unlike a lot of other markets
to CDR in Texas does to a certain extent create,
it's a newsworthy item.
Whether or not an actual lender, or developer
or you know, market participant looks at that
and is making an investment decision
to not build because reserve margins are high
or to build because the reserve margins are low.
I think it's sophisticated market participant looks at it
under the lens that, that it is,
and provides their own discount and review of the CDR.
But there is sort of a public perspective
that is probably the more difficult perspective,
which is the public sees we've got 21% reserves.
Why, why are we having high prices?
Why are we, Lori: Without power.
-: Why is there no power?
Why did my lights go off?
I mean, my lights went off this morning, so,
but I don't think that had anything to do
with resource adequacy. Lori: Right so,
yeah, I mean it's definitely the case
that generation resources, resource owners,
and investment investors out there
look at a host of information,
don't completely rely on the CDR report.
But like you mentioned,
the very critical aspect of the CDR report
is the public perspective on it.
And the signal that does send
when you see a high reserve margin
that you're gonna have reliability.
Barbara: There's a perception that it creates
for everyone in the market,
a little bit for the sophisticated players
cause they look at it and they,
and they have their own view of it.
But it does create, you know,
to a certain extent an illusion
of that planning criteria
are the same as operating criteria and that
Peter: Certainly needs some work.
-: It does.
And you know, and that's why we wanna make sure
that we're looking at things like deliverability,
that we're looking at what ERCOT actually does
during peaks and analyzing
the actual system conditions
during the various peaks throughout the year.
So that,
that you as regulators
and the public have a better understanding of,
of where ERCOT is.
Because we are an energy only market.
We don't have that forward commitments to
for physical assets to be in place.
We are basically a voluntary market that's saying
we look okay in three years.
Lori: Do you think the SARA report gets it there?
Or do you think that we need an additional
even more near-term report?
Barbara: So that's SARA.
SARA is your near-term report.
And I think the SARA does a good job of evaluating
sort of the more operational criteria,
typical outages during those, those seasons.
So when we're looking at the seasonal aspects of reporting,
first of all, we're a lot closer to operating days.
So the closer we can get to operating day,
the better the information is gonna be,
you know what assets are physically gonna be there,
you have COD dates for the,
so you're not including planned resources
unless they have a COD date,
which is it within that window.
So the SARA is actually a much better perspective
of where ERCOT is at
because it is looking at now it does have,
it does have scenarios in it.
And, you know, would depend on kind of
what your view of the scenarios are.
Whether you're gonna have a high outages
or low wind or all those other criteria it looks at,
but it does give you a much better operational perspective.
The closer we get with those planning reserve information
to real time,
the better we'd have better knowledge we have around
what our actual reserves are.
Peter: Yup. All right. Thank you.
This is an excellent slide.
And then we got one more panel before lunch so,
we'll refer back to you to
-: Yeah, I'm gonna move on,
I think we've talked about most of the issues
that I had on the slide,
one thing I did want to just before I move on,
well actually, I'll get it on the next slide.
So real-time co-optimization, most of the markets
in the North America have real-time optimization
and it's really important.
And it's,
it will drive some of the investment
that we've been talking about
to have quick start resources
being dispatched in real-time,
for both energy and reserves.
So it does actually create some of those opportunities
that we've been looking for for quick start units,
as well as load and storage.
So it really creates a lot of opportunities
for those flexible megawatts that we need,
whether it's load megawatts, storage megawatts,
or quick start,
or other types of flexible resources in the market.
So I can't say more that
that project moving forward is critical.
And I know that ERCOT had some delays, you know,
much of it related to, you know, this event,
but frankly,
this is a really good solution to solve
for some of the problems that we've been seeing
and create some of those opportunities.
It does have a corollary kind of con
and that is that more efficiency in the market
may drive lower costs and more efficiency in the market
is kind of been, you know,
the hallmark of Texas has been we've been super efficient
and had super low prices.
And that is a concern that many have expressed, you know,
if this drives to lower prices,
will we get those, those investments?
So, you know, it's
that that's just one of the concerns.
And I can run through all of these
or we can hit ones that,
Peter: Why don't you hit the highlight soon.
Barbara: Okay,
so the first few are ones
that we're already working on.
So contingency reserve service,
we have a sort of partial implementation
of a contingency reserve.
Again, a really critical element that ERCOT needs
in their toolbox
is to have that contingency reserve service
that will provide some of the, you know,
operational criteria we're talking about with
with ramping,
it will be a service that they can increase the amount
that they need based on the contingencies in the system.
So if they're coming into a winter event
and they haven't known a winter event,
they can increase their procurement of contingency reserve.
So that's a, that's a critical part.
And it also,
there are some constraints
on load participation in that program.
And frankly,
the more load you can get participating
in all of these programs,
because load provides a lot of value
in the ancillary markets.
So I know that, you know,
ERCOT had some concerns around
kind of the amount of load that they're procuring right now,
but I will say that load is a critical element
in any of these reserves services.
Emergency pricing mechanism.
We dealt with the scarcity pricing mechanism
in the previous docket,
but one of the things we didn't deal with is
what happens once we get into an emergency
and the prices, you know,
what is there going to be a adjustment to the price
when we're in conditions
where that next megawatt is just not available?
And we ended up in a sustained situation,
and do we have a, a auto-correct to,
to get to a different level.
Critical load standards, We've you know,
I think Woody talked a lot about that, but
it's very important first fuel security,
and obviously the health and welfare
to have critical loads designated,
but we need to be careful
on those critical load designations,
because the more loads that get designated
and often after these events,
you have a lot of people deciding
that they're critical loads.
We need to make sure that the right loads
and that the TDSPs have the right tools in their toolbox
to be able to more discreetly manage those loads.
And I'm not gonna go through,
I think the rest of these
we've already talked about ramping service,
but I'm certainly available for questions.
Peter: I think we got to those first,
go ahead.
We did the questions.
Barbara: We're doing the questions
all the way through. Peter: Throughout.
Barbara: In the next slide,
I'm kind of taught I just talk about
existing things that are going on in the market.
The operating reserve demand curve.
We've spent a lot of time talking about it.
It is, you know,
it improves the price signals in the market
when we are truly in scarcity, but it's not, it's not,
it is, it is a just one element
of the market of the energy only market.
And I think we've had a lot of discussions around
kind of the,
what the appetite is for those high prices.
So we need to talk a little bit around kind of the,
not just the operational characteristics of the market,
but the politics and the public perception
of having, you know, high prices
and whether or not, you know,
that sort of a sustainable situation.
We've talked about the CDR and with that,
I am available for questions.
Peter: All right. Thank you very much, Barbara.
Excellent presentation laying out
a lot of complex ideas.
Appreciate how you pack a lot of information in there.
I think at this point,
we should go ahead
and we will go ahead and break for lunch right now
and save the panels for when we return.
I clearly did too short of a lunch last time,
we went in 45 minutes?
Work for everybody?
-: Yep. -: Sure.
-: Right.
We will reconvene at 12:15, the first item,
we will get a Commission staff
to we'll jump to weatherization item
and then we'll return to our panels.
See you all soon.