(gavel banging)
-: Good morning,
this meeting of the Public Utility Commission of Texas
will come to order to you consider matters
that have been duly posted
with the secretary of state of Texas for August 12th, 2021.
For the record my name is Peter Lake,
and with me today are Will McAdams,
Lori Cobos and our newest Commissioner,
Jimmy Glotfelty, he will be joining shortly
when he returns from obligations at the Capitol.
We are here for another one of our work sessions.
This time focused on weatherization,
which is a key mandate and directive
from the 87th Legislature,
and obviously was a key part of the tragedy
that occurred in February.
Look forward to hearing from a range of stakeholders.
Appreciate everyone who has contributed
to this conversation.
And also all the hard work our staff
has put in both developing a draft,
draft of the draft proposed rules
and also going through stakeholder comments.
I don't have anything for items one and three,
I think we can dive right into item four,
our conversation on weatherization.
I anticipate this will largely take the bulk of the morning,
depending on how that goes.
Let's plan on completing this item,
going through all these speakers, hopefully,
and then breaking for lunch.
And then we'll hear from staff after lunch.
(indistinct)
Of course we can adjust timing if that is needed.
I think first up we've got Texas Climate 101
with our state climatologists and ERCOT meteorologists.
-: Morning.
-: Floor is yours.
-: All right.
I am Chris Coleman.
I'm the ERCOT meteorologist,
the only meteorologist at ERCOT.
Some of you may already know me.
I joined ERCOT in 2012,
and actually right after the 2011 event.
And it was other than maybe Hurricane Harvey,
I wasn't too stressed,
and then along came last February.
So I'm going to discuss the February event
and give you some idea how that stacks up historically.
And I'm just actually here to give a brief introduction
which it's a challenge for me to be brief.
And I'm also used to walking around.
So this is all very new for me.
-: All of this is new for all of us.
-: Okay. (laughs)
Fair enough.
-: You're in good company.
And then I'll introduce the main speaker here to my left.
All right, so as you know periods of extreme winter,
similar to what impacted the Texas power grid
in February 2021 are rare.
And they don't necessirily...
This is one of the things I'm gonna point out here is,
just because you have a cold period
doesn't mean you're gonna have a cold winter.
I actually give a talk each September,
a weatherization workshop with many
of the generation managers and Texas RE
and this is one of my talking points
heading into before each winter.
You don't need a cold winter to have a cold extreme.
And that's exactly what we saw last winter.
So I looked at data back to the 1890s.
So you have 120 years,
a little over 120 years with the given criteria
in these following slides here,
we'll show you how I came to five winters in particular
with extreme prolonged cold temperatures
impacting the entire region.
So the top two criteria were extreme cold
and a need to impact the entire state.
And then your next level would be a prolonged period
of cold.
Sometimes you'll get a one or two day event
and then you move on and it's above freezing
and things can get back to normal quicker.
Unlike what happened in February this past February.
-: So if I may on that one,
so what was your cutoff when you moved to that next level?
Was it beyond two days since this was a five day event or?
-: There wasn't.
This was actually about a 10 to 12 days.
-: Okay.
-: What we experienced this past February.
-: Yes.
-: I didn't have a strict cutoff,
I just did a comparison and,
well, you'll get maybe some idea.
But, yes, ideally you'd look for something more
than a couple of days, but there wasn't.
I didn't really set a must be five days.
You'll see I do have some temperature thresholds.
-: Okay.
-: All right, so until this past February
it had been 31 years since we had experienced
something similar, and that was December, 1989.
You've probably heard that year mentioned.
What happened in February, 2021 and December of 1989,
both were much more extreme than what happened
in February, 2011.
The most extreme winter periods,
typically of consecutive days of cold buildup.
Again, that's your second level of focus.
And I started with primary focus on Dallas, then Houston,
and then tried to expand it to include,
so you've got North Coast, Austin Central,
Abilene West, Brownsville South,
to get as many of those cities within the set criteria
as possible to define these most extreme winters.
This is a very interesting graph, I think so.
This is last winter.
This is what it looked like.
So your normal would be any of those blue bars
going upwards.
That's above normal temperatures.
And downward would be below normal temperatures.
And you can see up until roughly February 10th or so,
most of the days had been above normal.
We had some week below normals,
but nothing out of the ordinary.
And then you see days there.
This is for Austin.
I used Austin for this graph,
just being a kind of a center point for the state.
But you could apply this,
I could show you the same graph from any location in Texas,
and you'd get the same general flavor from that.
How extreme that when you're pushing 35 to 40 degrees
below normal there by mid-month that was.
All right, so I mentioned (indistinct).
First level of focus was with Dallas and then Houston.
So I've got a bunch of data here for Dallas.
In fact, there's an appendix there.
The last two slides have some very detailed information
on Dallas kind of a daily look.
Again, if we wanna look at this a little deeper,
the data is there,
but I'm trying to keep this short here.
So in Dallas I found 14 winters dating back to 1899
that recorded a low of five degrees or colder.
Interestingly, every decade from the 1890s
through the 1990s,
actually, even though the consistent data for Dallas
only went back to 1899.
It's very clear 1895 also was an extreme cold,
but it's lagging data and spots.
But every decade from the 1890s through the 1990s,
Dallas had at least two winters with temperatures
that were 10 degrees or colder.
Apart from 1997 to 2020,
that never happened once.
-: So it's been happening once for a decade or more
and we had a-- -: Yeah.
-: 20 year break.
-: And we had at least twice a decade
for over a hundred years.
-: But not at all in the last 20 years?
-: Yeah, up until we'd gone 23 plus years,
24 years without any 10 degree cold temperatures in Dallas.
And 2011 by comparison was 13 degrees,
was the low in Dallas, to give you some idea.
In Houston then there were 14 winters.
Also winters dating back,
I was able to go back to 1895.
They recorded a low of 15 degrees or colder.
So those graphs there on the right
that shows you then the winters,
the 14 winters for Dallas,
five degrees or colder there at the top.
And the numbers in parentheses show you
where that Texas winter ranked as far as cold to warm.
So 1899 there with the one behind that,
that was the coldest winter on record
for the state of Texas.
Just to give you some idea.
So actually, it had six of the 14 winters were top 11.
So they don't again, that's one thing I emphasize
that you don't need a cold winter
to have in a cold extreme period.
And just over half the winters,
we're not necessarily all that cold.
But there's your slide
2021, 1989, 1983, 64, 49, 47, 43, 33, 30, 1918, 1912
and 1911, 1985, 1899.
You see a lot of those were pre 1950,
actually all but four of them were of the 14.
So 10 of the 14 extreme colds in Dallas
occurred before 1950.
And here's a same idea there with Houston.
You do get a few different years,
but most of those years overlap.
So those are the years I'm focusing on.
And from that, (indistinct)
well, the top bullet is really kind of my final analysis.
The winters that I focused on as the most extreme,
most prolonged impacting the entire state.
There's five winters, 2021, February, 1989, 1983.
Those were both Decembers and 1930 and or in 1899.
So you did have two in the 1980s that fit my criteria.
Again, with those temperature thresholds,
five degrees for Dallas, 15 degrees for (indistinct).
Yeah, five degrees or colder for Dallas
and 15 degrees for Houston.
So actually taking that dataset.
So again, that was kinda more my end bullet there,
but that second bullet there is the Dallas and Houston
five and 15.
So that includes those top five plus a few more.
And to get those top five, then I bring in Austin.
You see the bottom there, Austin, Abilene and Brownsville.
And so you have Austin recorded temperature
at 12 degrees or colder.
And the reason I chose 12 degrees,
I looked for a point when you had at least 10
historical winters to fit that,
but not more than 15.
So that's what applied those to Dallas, Houston,
Austin, Abilene and Brownsville.
That's why you get those.
It was nice, easy numbers there,
numbers that made sense five and 15 degrees
for Dallas and Houston,
but to get it to fit into that same,
or you didn't have too many,
but you had enough years,
he ended up with some funny looking numbers there,
Austin at 12, Abilene at two and Brownsville at 23.
And so there's the years that get that,
you put all five of those locations together,
you get those top five.
Again, so the idea is to fit every city to match
that criteria.
-: Chris.
Hi, good morning.
Is there any effort to include maybe a little bit more west,
West Texas like Midland-Odessa or?
-: Yeah, I actually, I would wanted to include Midland.
I had much more data available for Abilene.
So using Midland's primary recording observation point,
the data didn't go back far enough for me.
There are other locations there,
and it would be a matter of taking
some of the secondary locations
and maybe piecing it together
to get some more far West Texas data.
It just wasn't as readily available.
-: Yeah.
-: So.
-: So it didn't go all the way back to the 1890s?
-: For Midland.
-: To capture that.
-: Right. -: Okay, That makes sense.
-: Yeah, I think a lot of people like to claim Abilene
is West Texas and it's not far enough.
-: Yeah, no, I agree with you.
That's as far west as I,
again, now John here has at least going into this,
had a much better database than I did.
So I think he may have more available.
We spent a good period just gathering data
for within ERCOT.
We had a lot of data back to 1950
and then we were lacking before that.
So we've spent most of the last month
just trying to get historical data that covered it.
-: Just broadly speaking is of historical data
back to 1890's or 1850's not publicly available.
-: Yes and no.
There is some publicly available data.
The key is finding quality, public available data.
And a lot of it that you will just download
from the internet either has lots of holes
or it has bad data.
And so there are actually weather companies
that exist that just sell weather data,
because what they do is they fill the holes,
they clean the data and make sure there's no bad data.
So it's kind of a process to get good reliable data
prior to 1950.
-: Okay, interesting.
So that's the first question we need to ask anybody
that comes into the Commission is,
if they paid for the weather data or not?
-: Right. -: We'll talk about this topic.
-: Yup, yup.
Yeah, that was the single biggest obstacle.
-: Interesting.
-: I was just obtaining good quality of weather data.
-: But I think Commissioner Cobos's point is a good point
just in terms of whatever standard we're considering
in terms of supply chain management,
and how that's accounted for,
the Permian has to be in it somewhere.
-: Yeah, absolutely.
And even further sort of far west,
if he can or no El Paso is not in ERCOT, but.
-: Yup, I agree with you.
-: I think in Midland-Odessa because of the Permian
and Delaware Basin in the area,
but I can't think of another metropolitan area outside that.
(chuckles)
-: Yeah, I mean, there's lots of little towns
that actually do have quite a bit of data,
Alpine and in places like that,
that strangely have more data than I think Midland did.
So.
-: Yeah.
Well, I'm certainly a fan of plugging
in Alpine (indistinct).
(laughs)
-: So it's there,
it's just a matter of getting the data filled in and usable,
but, yeah, I wanted to go further west than Abilene.
I was definitely aware of there's a big gap
there between Abilene and the rest of the state west.
Yeah, and the other issue, of course,
as you see, if you just focus on 1950 forward,
then you really have 1983 and 1989, 2021.
And there's a couple other years that are kinda,
again, John will have maybe a little different spin,
but the years there may be another year or two
in the fifties and sixties that you could kind of fit
into this depending on what criteria you use.
But there was many more extreme pulled periods prior to 1950
than there has been since 1950.
-: So the last one, one more time.
-: There has been more extreme cold periods prior to 1950
and since than there has been since.
-: Okay, good deal.
I think that's your final slide.
-: Yup, except for I've mentioned.
So if you wanna dig into daily historical data for Dallas,
it's there and I can make that available
for other locations as well.
That was kind of my starting point.
It's fun to look at especially if you're either a data geek
or a weather geek, but otherwise it's busy slides.
-: All right, thank you, Chris.
-: Yeah, thank you.
-: John.
The floor is yours.
-: Thank you.
I've been asked to give a sort of broad brush picture
of Texas climate hazards associated with it.
I will be relating it to energy generation
distribution systems to the extent I can,
recognize I'm a climate expert not an energy expert.
So forgive any misstatements in that regard.
I want to give us,
start with an overview of the general climate of Texas,
give basic common picture that,
discuss the hazards that are relevant to our power systems,
talk about trends and in those different factors
and how we assess those,
getting more specific to the rule-making,
and how we analyze return periods,
return frequency for extreme events,
and then using extreme colds as an example,
and then bringing it back to the specific event
of February, 2021.
So I can summarize the basics of Texas climate
in three slides.
I've got the average minimum temperature for January
on the left.
Each color represents a three degree Fahrenheit range.
The average maximum temperature in July is in the middle.
And as an example, the average February precipitation
on the right.
And basically all you need to know is that,
in the winter time, variations are from north to south.
North Texas is typically about 30 degrees warmer
than the South Texas.
And the summertime, it's a lot more uniform.
The mountains of West Texas are cooler,
but you can have very high temperatures
just about anywhere else.
For rainfall it's an east west variation,
West Texas is dry,
East Texas as wet as you all know,
it's actually quite remarkable how regular
that pattern of precipitation is going from east to west.
The climate is not just the average conditions.
It's also the extremes.
And these are the extremes
that I think are especially relevant.
Extreme heat and extreme cold affect power distribution
in different ways.
Frozen precipitation is obviously an important hazard.
Wind storms, such as derechos and hurricanes,
and then floods and droughts
also affect things in different ways,
and be perfectly general and floods,
I suppose we should include storm surge
and saltwater flooding as well as freshwater flooding
for facilities along the coast.
Now, for assessing trends in those,
there's basically three different lines of evidence.
And these were first outlined
in the National Academy of Sciences report
several years ago.
First, looking at the historical data,
is there a trend in this particular type of hazard
that can be detected given the data?
Sometimes if you can't detect a trend
it may be a data quality issue like trends and tornadoes,
we have no clue about historically,
because we used to avoid tornadoes
and now some of us chase them.
Second line of evidence,
do climate models simulate or project a trend
in a particular hazard?
And third, is there a sound scientific understanding
of why climate change ought to be causing a trend
in a particular factor?
So I'll go through each of those types of hazards
that I mentioned and give you just a brief summary
of the scientific confidence of a trend
based on these three aspects.
And since we just finished the Olympics,
I'll be awarding a maximum of 10 points for each category.
And the final score is what will count.
So for extreme heat,
it's getting worse.
We expect higher temperatures
lead to higher extreme temperatures.
The only reason it's not 3 out of 30
is that back in the 1930s,
Texas had some really hot summers
and we really haven't generally equal
those temperatures yet,
but the trend is pretty strong since the mid 70s.
Extreme cold.
I've highlighted that in green rather than red,
because extreme cold is becoming less extreme,
according to all three lines of evidence.
So extreme cold, like February, 2021 is expected to be,
has become less likely expected to continue
to become less likely.
Same thing applies to frozen precipitation.
That's primarily because most of the time
when we get precipitation in Texas is in the form of rain.
So temperature is the main factor for determining
whether we will get frozen precipitation.
So more rain events and fewer frozen precipitation events
like ice and snow.
Wind storms, probably getting worse.
The strongest hurricanes are expected to become stronger.
So that's mainly a factor for Southeast
and the Southern Texas with droughts and floods.
It really depends upon what you're talking about
with droughts and floods,
'cause there's lots of different definitions of them.
Probably most relevant for drought is low flow,
which affects hydro-power
and also affects water temperatures.
(clears throat)
And that is likely to be getting worse over time
as higher temperatures lead to greater evaporation.
Meanwhile, floods depend upon the sort of flood protection
infrastructure rehab,
but just looking at it meteorologically
in terms of heavy rain,
rainfall is becoming more intense across the state
and across all of the Southern and Southeast United States.
So how would we estimate return periods?
-: I'm sorry, quick questions.
-: Sorry, go ahead.
-: On your last slide there,
you're saying we will have higher frequency of low flows
while at the same time in the drought category,
while also having greater frequency of heavy rain.
That would seem to be contradictory.
-: Is that because of--
-: It's (indistinct)?
(laughs)
-: So the (clears throat).
So basically what happens is,
the precipitation comes in more intense bursts
so that when it rains,
it tends to be heavier rain,
but then you have longer periods of time
between those events.
And that's true, not just a daily scale,
but that's on a monthly basis.
And the other factor affecting the droughts is,
with the higher temperature you have greater evaporation.
So the water doesn't stay in the system as long,
it evaporates back into the atmospheres.
So things dry out faster between the rain events.
-: One more question, sir.
Okay, so you say droughts, it depends.
So 2011, we saw the drought of record.
It seemed to create an environment
where it was a self-fulfilling trend for awhile.
It was a sustained,
and matter of fact, anecdotally.
So I come from a family of ranchers,
and I don't know if you gave the briefing in 1996
to my father,
but the bottom line is cattle raisers
had a briefing in 1996.
And I remember this vividly,
because someone from the State Climatologists Office
told all those ranchers
that we were going into a 30 year drought cycle.
And you could almost predict that,
because of previous events and just atmospheric trends
that you were able to monitor.
And so it's coming close to 30 years now.
And what are you seeing there in terms
of this compounding effect of these more intense droughts?
-: A couple of things there,
first off, it turned out to be 20 years,
basically cause since 2015 it's been fairly wet.
And, yeah, if I were giving that talk,
I don't think it would be as confident
as your father remembered it.
-: Okay.
(laughs)
-: But at any rate, yeah, they tend to...
There is decadal scale variability that happens,
and that's driven by what's happening in the oceans
that can affect us.
But unfortunately it's not very predictable,
especially for winter rainfall,
and summertime it doesn't really help us much at all
in terms of predictability.
But the other factor in terms of things
feeding off each other,
the amount of rain we get in the say the spring
and early summer affects how much rain
we get in the summertime,
and also how high the temperatures get.
So for example, in 2011, things were bone dry out,
whereas this summer things are fairly wet.
And the difference is we're getting just as much sun
in both seasons,
but this year the sun is evaporating water.
The plants are happy,
they're pumping water into the atmosphere,
they're growing like crazy.
So most of that energy is going into the evaporating water.
In 2011, there wasn't any water available.
So just about all the energy
went into heating up the ground,
which heats up the atmosphere.
So temperatures in the summertime and droughts
are not independent of each other,
they go hand in hand.
-: Okay.
-: Okay, I'm gonna skip most of the technical details here.
You're asking about data.
We have a good representative hourly
or three hourly data going back to the 1940s
for most parts of the state.
We have daily observations of temperature and rainfall
that in many places go back to the 1880s.
For Midland, as you heard,
we don't have climate data that covers that key period
in the early part of the 20th century or just before that.
But Lubbock is a long-term station
and Roswell New Mexico is a long-term station.
So the same sorts of trends that are present there,
would apply to the Midland-Odessa area,
so we can make good estimates of the risk out there.
And in terms of probabilities,
as it's normally used, say in 99% probability threshold
would be talking about the probability of event occurring
in a given year.
So essentially it means there's a one in 100 chance
of that particular extreme event occurring,
or 99% chance of it not occurring in a given year.
It's sometimes misinterpreted as an event
that occurs once every hundred years like clockwork,
but it's really just like a roulette wheel.
You don't know when the number is gonna come up.
-: So that's important to note that on that flesh out
that statistical nuance,
just because something happens two out of three years
in extreme event happens two out of three years
doesn't mean that that calculus is off.
It means that it flipped heads two in a row,
and there can be flipping tales many times
over many iterations and that probability resets every year?
-: That's absolutely right.
What those events do though is they give us more events
to bid or estimate what the probabilities are?
So our estimate of the risk of an extreme cold of it in 2022
is probably higher than it would have been in 2021,
just because we've seen that extreme cold events
really do still happen.
Okay, now, part of the challenge with the rulemaking,
gotta be what exactly are going to define hazards,
because different cold events, for example,
affect different facilities differently.
-: Quick question on that last point you made.
The extreme events are then rolled into historical data
for the next year.
Do your calculations give increased waiting
to more recent data,
or is it uniform across decades or across time?
-: I'll show you an example in a moment,
it'll be easier to see what I'm talking about
with the graphics.
But thank you for that question.
So for say a wellhead perhaps one or two days
of cold weather might make the difference
between whether things freeze up.
What may matter is how cold it gets?
What the average temperature is over an extended period
of time for facilities such as wind turbines.
It may not matter how cold it is as long as it's dry,
but if you have precipitation the same time,
that may be the dispositive factor.
So there are lots of different ways
that we have the ability to slice and dice the data
and come up with probabilities.
I'll give you an example for Abilene, as you heard,
Abilene is a good long-term station.
It also is very early in the alphabet.
So that's the first example that pops up.
(laughs)
Here's an example of 24 hour average temperature
and the coldest 24 hour period in any given year.
We're gonna find a year from July to June,
so that the whole winter season is one possible
set of events.
And the probabilities here are calculated
using all of those extreme events.
It's not just the most extreme ones.
So the blue line is the 50% probability.
And so half of the event should be above that,
half should be below.
Then the yellow is a 95% probability.
There's something like 70 years here.
So you'll have something like three or four or five events
below that line.
98% is the green line, 99%, the red line.
The lines aren't straight because for this statistic,
I have allowed the risk of extreme temperature
to vary with the global average temperature.
And that doesn't mean that I'm assuming the risk increase,
it just says,
if the risks are changing over time,
they'll change what that sort of temporal variation.
So more of a change recently,
less of a change earlier on.
You can compare that to a longer dataset
that goes back to the 1890s.
This is daily average temperature,
so it's slightly different numbers.
And also as it happens with this particular station,
there's not a long-term trend
present once you look back far enough
to do a reliable estimate of trend,
you would use not just a single station,
but also a bunch of nearby stations
so that you have a better sample of events
to estimate the trend.
But any event you can...
Let's see, remind me of what your question was,
because now I can answer.
-: When you make these calculations,
do you give greater weight to more recent data
than older data?
-: Okay.
So no we don't.
We are treating all data equally to the extent that we,
the data has been quality controlled and vetted,
because for determining the hazard extreme events,
you really need to have as many events as possible
to figure out how big the tail of the distribution is,
is the technical term for it.
But if cold events are becoming less frequent in time,
it'll show up in a trend of the analysis.
It's also possible,
and it's the standard way of engineers do it,
is to just estimate the odds based on all the data,
assuming no trend whatsoever.
Before climate change that was a good approach,
and it's still a good approach in many cases,
but when there's good reason to expect
that there's a trend present,
I believe you wanted to factor that in to the extent
that you can.
-: So that would include greater way to more recent...
-: It wouldn't be recent,
but since the slide on the --
-: Well, both of them now,
since the points more recently tend to be warmer
than the points in the historic past,
that will show up in the trends
so that the estimate of the risk,
as you can see, the lines are going up.
So estimate of the risk of present day,
is higher than the estimate of what the risk
was in 1950.
-: Okay, gotcha.
-: So Dr. Damon, on that point, (clears throat)
so as I alluded to,
if you're in a drought cycle or you're in a wet cycle,
like the early 80s were really wet,
the late 70s, early 70s.
Now, does that increase your weighting
since you're in those cycles of a particular
type of event occurring?
Unless if we're talking about cold,
which is the primary danger to our system,
do we weight it further in a particular cycle?
-: I do not advise doing that,
because the cycles themselves aren't as predictable
as one would hope they would be.
-: Okay.
-: You can look back in the data and say,
"Hey, see we tend to have a cold North Pacific
"and we had this weather happening here,
"then the temperatures are warm in the North Pacific."
But if you actually look at that,
those temperature data in the Pacific
and try to figure out what's going on with it,
you really can't predict it well moving forward.
Now, there is a lot of work going on,
is to try to make decadal temperature predictions,
but those are mainly focused on, (coughs)
average temperatures.
And as Chris alluded to one extreme event is,
is not consistent necessarily with about average conditions
in the winter are.
So if we can do that, we still I think several years away
from being able to do that reliably.
-: Okay.
-: Dr. Gavin, just then maybe you've answered this,
but I guess as we sort of have been hearing nationally news
and the national media about heat waves
occurring earlier in the summer as we had one in June
and both hot and cold temperatures are kind of fluctuating
a lot.
And we've had this extreme weather event,
cold weather event in February.
What can you do to plan for the future
that seems to be like you said,
a little bit unpredictable,
but definitely taking into account
that there are just extreme weather events
occurring potentially more frequently?
'Cause I don't think that we can rely
on the old models anymore.
We've got to really kind of think more progressively
going forward on how we're calculating statistics
and what data we're using and given the weather fluctuations
in Texas and all over the country.
-: It's a common shorthand.
You hear a lot that says extreme weather
is becoming more extreme.
We're getting more dramatic fluctuations.
I think really no for simplification,
you have to look at the individual type of extreme weather.
For rainfall probably yes.
For temperature, probably no,
because, well, for example,
our extreme cold temperatures
come when we get cold air from Canada
and from the Arctic.
And the Arctic is warming faster
than the rest of the planet is.
So when we do get the occasional cold air outbreak,
and we get weather patterns that bring the air down,
and we actually shouldn't expect those temperatures
to be as cold as they would have been
in the past necessarily.
So I don't recommend factoring in increases of extremes,
just in general,
let's say the weather is becoming less predictable.
On the other hand,
given the fact that we don't know what's gonna happen
with the climate,
and given we have a limited record,
it can be prudent to allow for bigger margins of air
and say, okay, well, this is what the trend
is based on the data,
that may not be what the actual trend is.
So we'll allow for a little extra leeway to be safe.
-: There was the important follow-up element of that Lori
and that the follow-up question is what do we do about it?
You mentioned earlier the heavier rainfall, you know,
heavy rainfall, lower flows to the extent
a lot of power generation,
Texas requires adequate access to water
that's a challenge,
but that's also why we build reservoirs to mitigate
that variability we've been doing it for a hundred years.
So we wanna make sure we keep in mind,
not only the calculus we have to do on the weather front,
but also how we mitigate it.
So set up access to reliable water is a factor
in any power generation resource that needs.
-: Yeah, it's really important.
So if you take a couple of the doctor's charts,
if we're looking at (clears throat) Abilene 24 hour
lowest average temperature,
1989 in URI settle out at the 98th percentile.
So in terms of the proposed staff rule,
that's black start.
So that's what they have to harden to is URI.
Under Dr. Game's panel.
Lori: And if I could add to Chairman Lakes statement
about the water,
I think we did learn a lot during 2011
in that drought season that we had.
And I think as a result of that,
ERCOT started requiring some of the gas plants,
well, the plants that require water to show
certificates of water rights to be able
to be included in the CDR.
So I think as a result of the 2011 drought
ERCOT has taken action,
the state has taken action,
certainly, so we are prepared for drought conditions.
What we're here today is to kind of look at,
you know, cold (chuckles) and some hotter,
but I'm just kinda curious about how all that,
you know, I'm not a statistician, (laughs)
and I'm just trying to figure out how it all gets baked in,
to your sort of forward look.
-: Yeah.
So I found that Texans in general
are more trusting of data than models.
Although anytime you're estimating probabilities,
you're applying a statistical model anyhow,
so you really can't get away from it.
So the standard approach is to do the best you can
with the historical observation
and historical incidents that happened.
It is also possible to factor in what do climate models
say should be happening?
And frankly, I wouldn't rely on historical data
if the climate models were dramatically
inconsistent with it,
but it turns out for this sort of thing,
they are fairly consistent.
So we can rely just on the observations,
if that's the desired path.
I'm gonna wrap up by just giving some,
put the event of 2021 in perspective.
As you heard from Chris,
it was one of the top fives,
and this is six different ways of slicing and dicing it.
And one day minimum temperature,
one day maximum pressure, one day average,
and the same things over seven days.
And you see the same sets of years
showing up again and again in this.
But if you have also noted on the previous slides,
it wasn't the coldest ever.
And actually, it's a good thing we're not Oklahoma.
Oklahoma actually had its coldest event ever in 2021,
which was quite dramatic for them.
And a second thing I wanna point out is that,
when we have the grid problems early on February 15,
we were actually still in the middle of this event
so that the seven day average temperature,
we corresponded to that red circle there,
and things had already gone south
as it were before we had the coldest temperatures
of the event.
So while meteorologists and climatologists
like to talk about how severe the event was,
in terms of the worst part of it,
that may not be the relevant benchmark for the PUC
to be considering.
And lastly, for the most part,
because we haven't cranked out all the data yet,
we've been talking about temperatures,
but also the precipitation matters.
Obviously, directly for wind turbines,
but also it affects the heat loss from other facilities
that are exposed to the weather.
And these are the four most widespread snowstorms
in Texas history, as best as we can tell.
And 1895 is one of them.
There's not very many dust,
'cause there weren't very many stations.
But 2021 was also in that set.
So the combination of extreme cold
and widespread frozen precipitation
does make 2021 rather unusual,
but not unprecedented perhaps in the record.
So just wanna thank some of the students at ANM
who helped with this analysis.
And I'll be happy to answer any other questions you have.
-: Thank you, sir.
Any other questions?
-: Yes, sir.
-: One follow up question.
We've talked several times about making sure
that we have quality data just out of curiosity,
and some datasets are paid for presumably
the higher quality ones.
How do we ensure quality data from the 1890s, the 1920s,
or how would you scrub that data?
You know, how do you say it?
-: Sure.
So, yeah, I don't pay for my data.
I get it directly from the source,
because I can address all the issues with it.
The issues that arise are missing data,
and that can affect, you know,
if you have an extreme event that's missing,
it'll affect your assessment of probability.
So the way that can be filled in is by comparing events
where you actually have data at nearby stations
and making an estimate of what would've been the temperature
back then?
For estimating trends,
you have to be careful about when the observations were made
because daily observations made in the morning
will give you different frequencies of high
and cold extremes,
than daily observations made in the afternoon.
And that'll take a minute and a half to explain.
So I'll just leave it at that.
And then also observation practices before 1897
were a bit different.
And so for trends, you have to deal
with those sorts of issues.
But the big issue for hourly observations
as they only go back to the 1940s.
So the way I would approach that is,
there's gotta be a pretty strong correlation
between what we see with hourly data, what was the daily?
So we can use the period of time
where we have hourly data to estimate at a given station
the relationship between what the early data shows
and what the daily data shows,
and then use that same relationship
to estimate conditions farther back in time.
So those are the main issues that arise,
and those are the ways we're dealing with them.
-: Thank you.
-: If you don't mind make one comment
based on what John said.
That I thought was interesting
and probably should be reemphasized
is you take that our February event.
And if you recall, especially locally,
it was Sunday, the 14th.
If I remember is when conditions started
to get really bad locally.
And they had been going on in West Texas in particular
freezing rain, freezing drizzle,
cold temperatures had already set the stage for a few days
prior to that.
And it was Sunday night into Monday morning
when we started losing the generation.
And the coldest temperature was actually,
I believe it was Tuesday morning.
Is that right, John, the 16th?
-: Yeah, about 40% of the state was cold as Monday,
but majority of the state was cold on Tuesday.
-: Yeah, yeah.
So as he mentioned,
we had already gone through extreme enough weather
to lose the generation and set the stage for everything
before we actually hit our coldest temperature.
So I think that's kind of interesting to note.
-: Really important to note.
-: Yeah, yeah.
-: Thank you, Chris.
-: Thank you.
And of course, we'll welcome our newest Commissioner,
Jimmy Glotfelty.
-: Thank you.
-: Welcome.
At this point, we'll call up Center Point.
(indistinct)
-: Good morning, chairman and Commissioners.
My name is Keith Wall.
I'm Director of Regulatory Affairs for Center Point Energy,
and I've got Jamie Herdocia,
our Director of Engineering with me today.
-: Welcome.
-: As you know, Center Point is a combined gas
and electric utility.
In Texas, we serve 2.6 million customers
in the Greater Houston area.
And on the gas side,
we serve approximately 1.8 million customers
from Marshall, Texas down through Southeast Texas
through Houston down to South Texas
and the Laredo area.
Today, we kind of wanted to talk to you all
about the life cycle of the natural gas industry
from a Wellhead to Burner-Tip.
As you can see on the graph in front of you,
the gas is generated through gas wells,
you know those are our producers in the state.
The gas is then, you know, flows into gathering lines
to a processing plant where the gas is cleaned up.
Take a lot of the liquids out of the gas
to get pipeline quality gas.
Then it goes into the major pipelines in the state
where gas from there can serve agricultural needs,
it serves the generators themselves.
We can put gas in the storage,
or it can go into the local distribution system,
the city gate.
So kind of make an equivalent comparison
on the electric side,
the wellhead and the processing plant on the electric side,
it's kinda like a generator.
Then the major pipeline is kinda like transmission lines.
And when you get down to the city gate,
that's kinda like a substation where Center Point Electric
would take it at the sub station
and step down voltage to serve the local customers
off the distribution system on the electric side.
-: Is that always going to be qualified as an LDC
at that city gate?
-: The LDC is the yellow part,
and that's the part of the gas system
that Center Point owns and operates.
-: Do all LDCs have fuel storage or?
-: For the most part,
all of the major ones are,
some of the smaller LDCs
or local distribution companies might be small enough
where they just don't have the need for storage.
But I would say Center Point, Texas gas service and Atmos,
we all have had storage that we can draw on for our systems.
-: Is there an industry best practice
that sets that capacity of fuel storage,
on-site fuel storage for LDCs?
-: I think that's just an individual
company by company decision on how they manage that.
-: Okay.
-: Outside the LDCs just broadly speaking,
you have a sense of how much total natural gas storage
there is in the state?
-: I do not.
-: I don't have that.
-: Okay. -: Sorry.
-: My memory is not perfect, but I remember it to be,
I've been told multiple BCFs.
Substantial amount of storage.
-: Correct.
-: Relative to daily BCF use.
-: And so this is kind of like I said,
the stuff in the yellow,
the city gate or equivalent like a substation,
that's where we take delivery of gas from our suppliers,
and then we'll deliver that to our end use customers,
which the majority of those customers
are gonna be residential and small commercial customers.
Like I said earlier, as far as power plants,
those are served directly off the pipelines Center Point
doesn't supply any of the big generators in the state.
-: So let's talk about distributed generation.
-: Okay.
-: So small gas generators that happened
to be behind grocery stores-- -: Correct.
-: Or something.
-: Right.
-: That are taking gas at the LDC.
How insulated are they within your system from curtailment?
-: Very similar to any of the rest of our customers.
You know, if they're on our firm's service tariff,
they're up there with reliability
just like any other customer on the system.
I know during the storm,
we made sure that we were able to get gas
to those small micro grids
so they could in turn keep power at that area
and put some power back on the grid.
-: Okay.
And for your system,
do you have a weather related target already
that you maintain enough fuel reserves
to withstand any type of percentile metric that you use?
-: What we try to do--
-: 'Cause again, you're subject to hurricanes more
in Center Point service area,
Atmos will have freezes but.
-: Right.
(indistinct)
Right.
We do when we're contracting for our gas supplies,
you know, we'll look at what normal weather is,
and ensure that we have enough gas on that normal,
you know, a normal winter day to serve all of our customers.
We have firm contracts on our transportation deals
with the big pipes to ensure that we can have gas delivered
on the coldest day of the year.
-: Okay.
-: We might have to go out on the daily market
if it gets really cold to buy gas
to make sure we can vapour put it in the pipeline,
but we've got those types of contracts in place
that we can call on in those extreme weather situations.
-: Okay.
-: Those from contracts typically are presumably
have force majeure clauses.
-: Yes, absolutely.
-: Keep going.
-: That's kind of what we had prepared today
and didn't know if y'all had any more questions.
Happy to discuss what we do to weatherize
the system on the distribution system behind that city gate,
if that's helpful.
-: If you don't mind,
I'd like to explore that the firm gas contract framework
a little bit more.
Do y'all have see a difference in consistency of,
or reliability of that firmed gassed
between intrastate pipelines and interstate pipelines?
-: No, not really.
I mean, again, the way we've contracted for our gas,
which a lot of it is intrastate gas,
but we do have some interstate on our system as well.
But again, we've contracted to have the capacity
that we need on the coldest day of the year.
Center Point does serve some interruptable customers.
And if those customers are interruptable,
they got curtailed in this recent winter event.
-: Sure.
So but there's still that force majeure provision?
-: Absolutely.
-: That could disrupt the delivery.
-: Right.
(indistinct)
If there's an act of God,
there's really nothing we can do or anybody else
at that point.
-: Okay.
I mean, that's an important distinction.
-: Please.
Oh, we're sorry.
-: And the force majeure provisions.
How did those from contract force majeure provisions
impact you during the February storm?
-: I'm not aware of any force majeure claims
that we had during the storm.
-: Right.
If we had some that were very few.
Again, we had the pipeline capacity,
the gas was delivered.
Our system held up well during the storm.
The systems overall in the state for the most part
held up,
is getting gas to the local distribution
and a residential and small commercial
human needs type customers.
-: And those types of customers are prioritize via,
there are Commissions rules, right?
-: Correct.
-: That's what I'm saying,
the customers that we had behind our city gate,
they were interruptible.
We did call on them,
tell them that they needed to stop taking gas
because there was gonna be issues with gas.
And so we were able to curtail those for roughly a week
or so while it was--
-: What types of customers were those mainly?
-: It could be manufacturers,
it could be a customer that uses gas for their processing.
I know one of the customers that's an interruptible customer
was a trash truck company that used natural gas
for their trash trucks and stuff.
So there's a very types of customers
that would be interruptible
and want that interruptable service
as opposed to the higher from service.
-: Do you compensate those interruptible customers?
-: Well, I mean, compensating them, no.
They have a cheaper rate from us
because they are interruptable and not firm.
-: Okay.
So if you sign up to be an interruptible customer,
you get a lower rate?
So there's some benefit there?
-: Right, correct.
Yes.
-: Okay.
-: Dovetailing on the DG customers that you see.
In the gas world, do they aggregate their bills?
Do they bundle their connections with your services
to get an aggregated rate?
How do you account for them?
-: They're on our standard--
-: Meter, just one meter.
-: Correct, yeah.
I don't believe we're bundling their accounts together.
And so they've got a meter at each location
and they're on the standard rate of any commercial customer.
-: So in the future when we account
for large-scale DG interconnections
on the supply chain side, they're on an individual basis.
So there'll be accounted for on the gas system individually.
-: Yes, sir.
Okay.
-: That's my understanding.
-: Okay.
-: Thank you.
-: Okay, thank you.
-: Next up is Calpine, I believe.
-: Thank you.
-: Good morning, everyone.
-: Welcome.
-: It's good to be here and thank you for having me.
Before I start this presentation,
we put this together really as a primmer
on how we approach winterization every year.
And so I'll go through those details,
but I wanna talk a little bit about our fleet in Texas.
We have 12 combined cycle plants here in the state,
and six of them are in and around the Houston area,
three are in what you would consider South Texas,
and the other three are Central Inland.
And so kind of a geographic diversity for the state.
Our plants have a design basis that they were built with,
in terms of what type of winterization
they were prepared for?
And it ranges from zero degrees to 28 degrees
as a design minimum temperature.
So they're not all the same.
And it really is dependent on where they're geographically
located.
Our oldest plant was built in 1990,
so we missed the 1989 event.
However, we were around in the 2011 event.
And during that time period, I was not here.
I'm relatively new to Calpine.
But during that time period,
my understanding as the temperature got into the tins,
so less than 24 hours.
And of course there were wind conditions.
And at that time, our fleet experienced freezing issues.
The point I'm trying to make here
is that we have a design basis,
but a lot of what we do with winterization is experiential.
In other words, we go after the things
we know we had vulnerabilities on and correct.
So we harden our system to the 2011 experience
going into the 2021 experience.
We're doing the exact same thing this year,
we're taking into account what type of issues we saw in 2021
and our planning for them,
and hope to have them ready for the winter 2022.
I just wanted to put that out there
in terms of how we approach this.
-: I appreciate that.
-: Okay.
So I'm gonna go to our first slide
and this is not an advertisement.
It's just who we are.
Okay, we're an independent power producer.
We have about 26,000 megawatts, primarily gas fired.
In fact, all the gas fired.
We do have some geothermal energy in California,
which is considered renewable,
but we're spread out and geographic areas
that have highly competitive markets.
So of course we have the Texas fleet in ERCOT
and that's about 9,000 megawatts.
Where in California, we have about 9,300 megawatts
in California.
And then in the New Jersey,
well, in the PJM, New York and New England ISOs,
we have another 9300 megawatts of generation.
And we operate these.
The plants in New England, as you can well imagine
are indoor units,
and important thing about Texas is the units built here
are outdoor units.
They were built for summer operation.
And so you have two extreme.
You have the winter extreme you have to deal with,
but you also have the summer extreme.
And so you need to take that into account
in the design basis for the plant.
This is a picture of a combined cycle plant,
and I'll get into how combined cycles actually are designed.
But this basically, if you look at the stacks,
each stack is associated with a gas turbine.
And then in this particular plant,
we have two power blocks.
There referred to as two by one power blocks.
You've got two turbines on one steam turbine
and it's referred to as a two by one power block.
If I go to the next picture,
this is really just combined cycle configuration.
And what is meant by combined cycle is that,
it employs more than one thermodynamic cycle
to improve efficiency.
So in this particular instance,
we have a gas turbine that is operating the heat
that is generated within that turbine
goes through a heat recovery steam generator.
So here people refer to them (indistinct).
And you can also add fuel to that to do duct burning
to increase the heat input.
At the same time you have a steam turbine
where the water that you put in to the heat recovery
steam generator is heated, converted to steam
at very high temperatures and returned to the steam turbine,
it too operates running a generator.
It exhausts into a condenser,
which basically is a heat exchanger.
You have a cooling tower.
You're putting cooling water.
Sometimes you're off the river,
so it's not always cooling tower.
But you're putting water into the condenser,
condensing it back to water on the heat exchange side
to condensate.
And then you just start the cycle over.
It's a continuous cycle as you're running the gas turbine.
So that's kind of how a combined cycle works.
And it's important to know
these can be in multiple configurations.
In Texas we have a one by one
where we just have one gas turbine on one steam turbine.
Primarily, the fleet are two by one,
but on our co-generation facilities,
we have two, three by one's, a four by one
and a five by one.
Because in that case, the only difference on this graphic
is that you're feeding steam to a process.
Either a refinery or a chemical plant.
And so you're over-producing steam.
So what you can put through the turbine
generates electricity,
the rest of the steam goes to your host.
So let's talk about gas plant winterization.
First of all, I wanna kind of start out
about plant personnel health and safety
is one of our core values.
And this is really important,
because when you think about what we experienced
with winter storm URI,
our employees had to be sequestered.
In other words, access to the plants
just like in our hurricane becomes questionable.
So we decided that we would actually house our employees
throughout the entire storm.
So they were there 24/7,
and these are very poor conditions,
best to be outside dealing with freezing issues, et cetera.
We of course also added some contract personnel
to assist them in this.
But you know, they're sitting there doing this safely,
while their families are at home
dealing the same winter point issues everybody else was.
So it's kind of a shout out to my employees here.
So I really just wanted to mention that.
Winter weather can present some operational challenges,
especially with instrumentation and critical equipment.
Our operational challenges really are things like,
process instrumentation that is required for the control
and operation of these units can freeze.
And then you're sort of like flying in the dark and say,
a lot of times that causes a trip or shut down of the unit.
So you have to keep that process instrumentation working.
Air systems, we rely on instrument air to control valves
and positioners.
And if that dewpoint in that air gets frozen
and you lose air,
you also tend to lose the equipment.
Our ammonia systems, most of our plants are outfitted
with selective catalytic reduction systems.
And this is for nitrous oxide emission type controls.
So you have to make sure you can get ammonia to them
so that they can stay within your compliance
with your operating permits.
We have water and steam systems that have to be monitored
to make sure that they don't freeze over.
Steam drains are very important.
These also have to stay flowing.
If not, you can damage equipment.
We have lubricating oil systems
that are essential to the gas turbine
and steam turbine for their bearings, et cetera.
These have to be careful, warm and flowing.
We have close cooling water systems
that provide cooling water to bearings and things like that.
But in addition to that, they're closed loop.
So we do this with glycol,
just like you do in your car and your radiator.
We put an alcohol-based solution in it to make sure
that it can meet the freeze design.
And then your cooling towers they can ice over also.
And that can create damage and operational issues.
And in terms of being able to cool the condenser.
The makeup water intake, debris screens,
if they ice over, you lose flow of water.
So you have to kind of maintain those,
and wash those very carefully.
And then your gas regulating and pressure valves
within the plant coming off your gas feet.
Those two can give you operational issues
if you don't properly set up to protect them
during cold weather events.
So winterization of combined cycle
and simple cycle generation facilities,
we have no simple cycle in Texas,
but we do in other areas.
They should consider a number of factors,
including among other things where the plan is located,
the actual physical orientation of the facility
and the design and age of the facility,
and then the experience of the facility
in previous weather event.
-: When you say physical orientation,
you mean on the campus?
-: Yeah, because sometimes your geographic
where it's located,
you might be right in the prevailing winds.
And so winds also impact your operation.
And because it draws heat away from your insulated pipes
and everything and makes everything work harder.
And I'll get into this a little bit about
how to prevent that,
but we do pay attention to that when we're preparing
for winter.
There's really no one size fits all here for winterization.
And just a little disclaimer here,
this is how we Calpine approach winterization.
And it comes from years of experience with the industry,
but there are other strategies that could be deployed.
It's just these are the ones we choose to deploy.
And so we have a planning guideline
that we follow every year.
I'm sorry, I didn't move this up.
So as soon as the winter is over,
we do a post winter review just to find out
what lessons we learned from the last winter
and what we need to put into the winter readiness plan
and winter operations plan.
So you can imagine from this last winter,
there were a lot of lessons that came from all the extremes
that we saw.
We do an initial site-specific readiness meeting
and during May and July,
and then there, we start to plan the work
and implement the plant winter readiness plan.
The final work scope and winterization plan
is in place that's due by the end of September,
and then a site-specific operation procedures
are reviewed and updated based on lessons learned,
any equipment additions and or any industry best practices
that have come to light.
That's usually in October.
We train for winter readiness with our plant personnel
during the month of November.
We sign an attestation,
each plant signs an attestation of where they are,
in their plant winterization plan.
And then that attestation,
they will highlight anything that perhaps is not complete
as of the date is for example, they may be in an outage.
And so they're waiting to complete their outage
to finish insulating and things like that.
So that would be an example of what would be an exception
in the attestation.
And then they come to me and then I sign an attestation
for the entire fleet and submit it to ERCOT.
And so we try to target December 1st
as the date for our winter preparation.
-: A lot of this sounds like process.
-: It is process.
-: I know it changes side-by-side,
but how much of this roughly on a percentage basis
is actual physical implementation of best practices,
or is it 90% procedural PNP or a hundred percent PNP?
-: Yeah, let me address it this way.
Typically, we don't have a lot of lessons learned
if we have a regular winter.
(indistinct)
(laughs)
-: That's a good thing.
-: This year it's a huge amount of work.
It's a huge volume of work.
And so it just really depends on what happened
the previous winter?
It's very experiential, as I said.
And so right now we're in the process of ordering
significant amount of instrument boxes, cabling, et cetera,
to harden facilities based on what we discovered
during the 2021 hours.
-: Gotcha, thank you.
-: Does that answer your question?
-: Yes.
-: Okay, all right.
Thank you.
-: Can I ask you a quick question?
I don't know if this is... (indistinct)
It is.
So the many years ago I worked for Calpine,
so I know their plants fairly well,
but you mentioned the design basis.
Perhaps as a percentage number,
is the cost of a design basis for a plant in PJM
or New England that much different
from a design basis of a plant here in ERCOT?
-: Yeah, because, and let me try to explain it this way,
PJM, New England, they're gonna have enclosed buildings.
-: Right.
-: Everything is gonna be inside.
So you probably could add a hundred million dollars
to the cost basis of the plant
for their winterization approach.
And we just finished building a plant
up in New York, Pennsylvania
that is a combination of outdoor, indoor unit
because all of the drums and everything
on the heat recovery were put into enclosures.
Here in Texas we only have one plant like that.
The rest of them are open because of the heat again.
And so you have to provide for cooling,
you know, when in Texas for those type of enclosures.
-: Right.
So you create the opposite problem during the summer months.
Does that reduce efficiency of the plant
if you have an enclosure during high heat?
-: It's not so much the efficiency as it is your electronics
and your instrumentation.
You have to keep them cool enough to operate.
-: Okay, thank you.
-: Okay, any other venture question?
Thank you, sir.
-: So sir, you said that Calpine's fleet
is hardening to a 2011 standard,
'cause that was the most recent event.
-: We hardened to a 2011 standard in 2012.
We're hardening to what we know from 2021.
-: Today?
Okay.
Okay, so that was my question,
'cause according to Dr. Games average,
1989 is kind of the new standard
that's on your 95th percentile average.
So but you're hardening to a URI standard today.
-: That is what we're trying to do exactly.
We have a documented list of all the issues we had,
and that we need to address going forward basis.
(indistinct)
-: Okay, thank you.
So this is just a sample of winter readiness preparations.
And the first thing we do is we document
the minimum plant design operating temperature,
and then we want to determine
what the lowest ambient temperature
we need to prepare for any modifications.
We have made to the unit.
We also wanna make sure these modifications
do meet the minimum plant design standard.
We review the past winters issues
and experience some with any equipment freezing.
So that's what we're in the process of doing right now.
We identify the critical equipment that may be impacted
by cold weather.
We identify what type of heat tracing
is used for the critical equipment
and develop and perform an annual preventative maintenance
of the heat tracing system prior to winter.
And I'll show you an example of what he tracing is,
towards the end of this.
We document the maintenance perform
on the instrument air system,
because this is a critical to operations
to make sure we have the proper desiccants in there,
and that we can drain and keep moisture out of the air.
We perform a walk down of all the critical plant equipment
to make sure that there's any repairs
that need to be made to the insulation.
We do it prior to the winter operation.
We carry a pretty large inventory of consumables
and emergency supplies for winter.
We make sure those inventories are up to speed.
We test all our portable heaters and equipment and storage.
And we check all our space heaters.
And then in some buildings
we have permanent building space heaters,
and we'll build an enclosure around it.
For winter operation and we test those also.
The heat trace systems are tested.
We bring an outside firm in,
they'll actually load test these to make sure
we don't have any open circuits, et cetera.
And that they're operating on the design.
We prepare to for installation of temporary windbreaks,
and in those we placed temporary heaters
if they're enclosed,
we make sure we use heavy enough tarps.
Some places will use insulated blankets
depending on how cold it gets.
And then we usually put a map together
to show where all our enclosures are at that plant site.
And it's this plant specific map.
We repair any leaks on any critical equipment.
You wanna avoid any freezing issues,
icicles, that type of thing.
That's more of a personal safety issue,
personnel safety issue.
And then we prepare critical staffing plans.
So we know if we see a forecast like we saw for URI,
we'll make the decision to sequester
and we'll have adequate resources there,
so that people can work in 12 hour shifts
and relieve them,
make sure we keep things thawed the best we can.
-: The on-site housing like you mentioned earlier.
-: Yeah, we actually housed them onsite.
We use offices, we bring in bunks and little beds
and we have connexes that have been equipped
for people to stay in.
We especially did this during COVID,
because of some of the issues we've had.
And also we did it for hurricane preparation.
So we have these facilities,
people come in and they stay.
We have food and water and all the provisions
that are necessary.
And a lot of times our plants are inaccessible
and in times like this,
so you don't want people on the road.
So yes.
-: Did you have any interaction between your fuel supplier
and the plant operations kind of in this winter timeframe?
I'm wondering obviously fuel
is the most important part of the plant
or one of the most important parts of the plant
to make it run.
I know we haven't had extremes like we had in February,
but especially with the fuel systems.
But is there ever a common discussion
between you all except on a maintenance timing?
-: Let me put it this way,
we're served by different gas suppliers and we do,
we're very active in our communications with them.
And so, for example, just last winter
we lost one of our plants because the gas yard lost power.
And so we were in constant communication working with them
to get it restored, et cetera.
So we do have those kinds of,
but it's on the operational level,
you know, it's....
-: Do you ever ask your gas supplier
what their weatherization efforts are?
-: I have not.
Good.
So this is just a critical equipment winterization.
We heat trace all systems that are prone to freezing,
including chemical addition systems.
We drain certain equipment prior to winter operation.
We have equipment that we only use in the summer,
their chillers, inlet fogging, evaporative coolers.
These are used to boost generation in the summer,
but they're uninsulated.
So we drain all of them make sure they're protected.
We prepare for icing prevention on the inlet air filters.
If you go back to that picture,
you'll see these large structures that have filters on them.
Those will ice over,
and so you have to have replacement filters
and you have to be able to pull those filters out
and replace them while the unit is running.
And so that's a pretty significant event.
And if you don't do that,
you can starve the units for air
and of course, that will cause the (insitinct) to trip.
We also have to protect our compressors.
As on the inland guide vane,
sometimes we have to make adjustments there,
to keep from freezing across that blading.
We build enclosures and windbreaks around certain equipment
to make sure that we can keep it operational.
And these are temporary structures,
again, because we take them down for summer operation,
but we'll build them, cover them and then put a heater in,
and then we check on them on a routine basis.
We installed supplemental heating on sensitive equipment.
We also look at vendor supplied,
like chemical storage toast.
They have no freeze protection.
So we either put them in an area
where it's controlled environment
or we'll build blankets around them
and make sure that we can keep them clothing
and then water treatment chemicals,
every one of our plant as a water treatment facility
within it.
And we depend heavily on that water to be able to operate.
So we winterize those plants too.
-: Another question on that kinda going up the value chain
like I did on the fuel.
On the water component,
I know you get a lot of water
and as do most combined cycle plants
around the state from cities.
So they use a fluent water for cooling.
Did you have any problems or do you know of any problems
that happen during the storm where you weren't able
to get the water that you had contracted for,
because there was either electrical or a freezing problem
with the water treatment plan at the city?
-: Fortunately, we did not experience any real difficult.
We are served by two different entities
at one of our plants,
and one of them had freezing issues,
but the other was able to deliver if I remember correctly.
And then the other thing is what we had a bigger problem
was it's processed chemicals.
A lot of the facilities here in Texas
that provide us with basic acids and bases, et cetera,
that we use for water treatment froze.
So we had to go to Louisiana and the Southeast
to bring chemicals in to keep the plant operation.
And we weren't the only operator that had that issue.
-: Right.
-: But that was another thing that was something
we hadn't really foreseen,
'cause we only have so much storage on site and so...
-: Thank you.
The next page is kind of, I guess, show and tell.
So on the left-hand side,
this is a process (indistinct) that's used for transmitters,
for transmitting pressure, et cetera.
And as you can see,
it's designed where you have your process tubes.
That cable that you see there is what's called heat tracing.
So there's a heat trace that runs with those tubes.
It's surrounded by sort of a hygroscopic
glass fiber insulation,
so it won't retain moisture.
And then you've got a coating on the outside.
And on a lot of areas, our plant instrumentation
is on the ground level,
but the actual process point is 90 to a hundred feet up
in the air.
So you have to run this cabling down
and keep it protected.
As you do so when you're wrapping pipes for heat tracing,
the picture in the center is the type of cable you use
while you wrap the piping
and depending on the calculations
depending what wattage you use,
but that's a standard of what a heat trace cable looks like.
Then on the right-hand side is your control cabinet
for heat tracing system.
This one is on a turbine.
And so what it does is it controls the flow of current
to the heat tracing along with giving you alarms
as if something is open or something is not working.
So you have some invocation.
This is a examples of one breaks and enclosures,
and these are all temporary.
We put them up every year,
but we do that as I said,
because the wind does remove heat from the plant
and from the process.
And this helps retain as much heat as we can.
When you get the kind of conditions we saw
or near zero temperatures,
it's moving across there pretty briskly,
you're losing a lot of heat,
but you try to protect against that.
On the very far right side is just an example
of an enclosure where we built a temporary enclosure
and put a heater in and we'll close that up,
keep it warm, we'll check on it in our rounds.
That's where as we're experiencing the storm.
And on the final page here,
these are instrument boxes.
These are heated instrument boxes
where we run our process instrumentation to.
These are very critical.
And in 2011, we didn't have a lot of these.
We added some in problem areas.
This year we're probably adding twice as many
as we added in 2011.
And we are using these basically to protect
our instrumentation.
You can see the cabling coming into the back of it,
on the side of it as a small thermometer
that you can quickly glance
without having to open the compartment up
to see that it's working,
that the heat element is actually keeping the box warm,
but these are very critical in winter operation.
And with that's really kinda the end of my presentation.
And I realized it's more of a primmer than anything else,
but I'm open for any questions anybody may have.
-: We appreciate it.
Questions?
-: One question, sir.
No offense.
How long has your career been in the industry?
-: 40 years.
-: Great.
(laughs)
That's helpful.
-: I don't take that as offensive by the way.
(laughs)
-: It's a compliment.
So just for historical reference,
were you in the industry and in Texas in 1983, thereabouts?
-: No, but I was in North Carolina.
-: Okay.
All right, so looking at the chart and events
when trying to marry up our proposed standards
that staff has proposed with what you,
as the industry will have to do and comply with.
So and I was wrong with my numbers.
So it looks like according to...
And again, on the low temperature scale
the 95th percentile event is 1983.
Do you happen to know what 1983 was like,
in terms of an event what was experienced at that time
and experience dictates what you will harden to,
I'm sure what you'll think about.
-: So 1983, I was working at a coal facility
in the mountains of North Carolina.
We got down below zero.
And I think we were six below.
And we had solid fuel, coal that we had to keep moving.
It was alive pile,
so we were out bulldozing coal into an underground hopper
and feeding it to the units.
We had significant freezing issues,
but we were able to keep the units on.
We did have, and I remember this very clearly.
We had one instrument that froze and was a false invocation
and we actually did significant damage
to one of our boilers.
And then I was tasked with repairing it afterwards.(laughs)
I remember that very, very distinctly.
But going back to that time,
we did address those issues.
We actually built additional enclosures
because it was an outdoor unit again in the Carolinas,
but the summers aren't as taxing there in the mountains
of North Carolina.
So we were able to address it,
but it was again experiential.
-: Okay.
-: Did that answer your question, sir?
-: Yeah, yes or no.
So 2011 is our...
I mean, 2011 affected at a number of facilities.
But again, it was the famous picture
of trip dog it up there in front of the Senate panel
with the valve on that line
that froze the tripped one critical or two critical plants,
and all over of a sudden we had a problem.
But so 1983 was one of those deep freeze events
that covered the country.
Again, coal piles froze.
So it is somewhat akin to 1989.
1989 as I understand it was certainly that type of event,
you couldn't break into the cold piles
'cause it was so cold.
But 1989 it looks like it's the 98 percentile metric
on our at least the Abilene chart.
And again, we're looking at this regionally,
but that's helpful.
-: Okay, very good.
Thank you.
-: One more quick question.
To build on Jimmy's gas supply chain question earlier
on the force mejuere,
a conversation we had with a previous panelists,
is there apples to apples to compare onsite storage
to firm gas in terms of availability
in an extreme winter event?
-: Well, I'm not sure it's apples to apples.
The way I would look at it as on-site storage
is a pretty significant undertaking
with the volumes of gas that we burn.
So just think about this calculation,
it takes 7,000 BTU of gas for one net kilowatt hour,
and you're doing 600,000 kilowatts an hour.
So the numbers get tremendous, you know,
many billions of BTU and then you divide
that into billion cubic feet or convert it,
it's a large amount that you'd have to store.
So our approach is always,
I think that more aligned with having firm gas delivered.
-: It's on the cost of storage instructions basis.
-: Yeah, and you take time to do that and engineer,
et cetera.
I mean, you can do it,
but it's pretty significant.
-: Just one follow up question.
So earlier in your presentation,
you stated that there is no one size fits all
to weatherization.
It depends on a variety of factors,
such as unit age and design and location.
Have you had experience somewhere else
like North Carolina or anywhere
where there was perhaps weatherization standards
that would specifically address say,
you know, uniformly industry best practices
for old steam units, old combined cycles
in different types of categories of plants?
In your experience are there best practices
that you can apply uniformly across
different types of plants,
rather than just a whole segment of plants and megawatts?
-: I think there are best practices you can adopt
based on new technology, et cetera,
that you can apply to your plants.
But when I look at the design basis of plants
depending on where they are geographically,
they're just so different.
Like I've operated plants in Indiana
and they're all enclosed and they have following sheds
for their coal and those types of things.
But a very specific to that location
for the combined cycle fleet,
which is probably more comparative to Texas
and North Carolina.
I mean, they're their outdoor units, et cetera.
Most of the stuff that we're doing here
is exactly the same as I was doing at Duke Energy
with our combined cycles up there.
The only difference was the two combined cycles
that were last ones built and were up in North Carolina
in the mounts to replace the coal plant I started at.
Those were built with indoor enclosures,
because the winter is more extreme there,
but the rest of the fleet is pretty much outdoor fleet.
And we use the same technologies and practices.
I hope that answers your question.
-: I think so.
I mean, we're in a large state
with a lot of different variation and weather and by region
and different types of plants,
some like anywhere else.
And I'm just trying to figure out what are some baseline
weatherization standards that could be applied
to different types of plants depending on their age,
location, variety of factors.
And we can probably continue that discussion
during the discussion draft,
but I was just kinda curious
given your great extensive experience in the industry,
if you might be able to point us,
and it sounds like you you've had that experience
in terms of some best practices baseline
that can be applied to different types of plants
on their location.
And I think that's just maybe some of it's driven
by operational experience.
-: Yeah, and some of the things we're proposing to do,
to prepare for the 2022 winter,
assuming that it's gonna be a repeat event, (chuckles)
we hope to God, it's not.
But we are planning to that standard.
And so there are things we're doing with upgrades and stuff
that we could definitely bring to the table.
-: Okay, thank you.
-: Thank you.
-: So I would have one more follow up to the follow up,
and that is obviously the big two turbine suppliers are GE
and Westinghouse.
Do they have support efforts
or things that best practices may be,
on how to winterize or,
I mean, have they been a beneficial resource as they have,
they monitor turbines all over the world,
through Atlanta, all over the winter months everywhere.
And obviously they have a huge data resource there.
Have they been...
-: We actually used them for a couple of plants
for we had some issues
that we're concerned about whether or not
they were freeze related compressor failure
at a plant in Alabama.
And then also one in Baytown here in Texas,
but it turned out that wasn't the case,
but they did monitor it for us,
and we did depend on them.
But from a weatherization perspective,
they really don't add anything.
They deliver you a unit and it's up to you to decide
how you want to protect it.
-: Okay, thanks.
Okay.
-: And one more question on,
now I'm curious.
It sounds like you're very prepared,
like you're already taking proactive steps to be ready
for this next winter based on the February, 2021 event.
Are you in the process of acquiring
all the weatherization, measures, equipment?
Have you experienced any supply chain issues?
-: We're hoping to avoid those,
because we're assuming that everybody else
is doing the same thing.
And so we have an order in,
and they've told us they can deliver
for the instrument boxes and the TV,
and the rest is us implementing it,
in terms of installing it with craft and labor.
So.
-: Okay, thank you.
-: Thank you, Mr. Gates.
-: All right, thank you.
-: I appreciate your time.
-: Very much.
-: Next up we have the Renewable Generation
Weatherization panel.
-: All right, good morning.
-: Welcome.
(clears throat)
First off, thank you for having us.
We appreciate the opportunity to speak with you
about this important topic.
My name is Kirk Crews.
I'm the Vice President of Business Management
for NextEra Energy Resources.
I have with me, Mark Lemasney.
He is I'm the Vice President of our Power Generation group.
So Mark has operated wind farms, solar farms,
fossil (indistinct),
operated just about every technology out there.
And then we also, Daniel is here.
Daniel, you wanna introduce yourself?
-: Sure.
Daniel (indistinct) with General Electric
on the (indistinct).
-: Welcome.
-: Sorry, with who?
-: GE.
-: Oh, GE.
Got it.
-: So thanks for talking about us, sir.
(laughs)
-: All right, just briefly,
this is sort of the plan of what we'd like to cover today
in terms of weatherization of renewables.
We're to spend the majority of our time
on wind winterization.
So Mark will spend a little bit of time talking about
turbines and how they operate and the evolution of turbines.
And then Daniel is going to talk about operating
in cold and hot temperatures and then icing.
Before we do that,
we would like to spend just a few minutes on solar
and battery storage,
and just give you a very brief overview of operations.
And then how we think about them from hot conditions
and cold conditions and the way they're able to operate.
So jumping into to solar.
I think the key takeaway as we think about solar in,
we think about the weather conditions
we typically experience in Texas in terms of hot summers.
And you can see some of the cold temperatures
is we feel comfortable that solar can operate
in those varying degrees of temperatures.
The electronics and solar are an enclosed containers
that we're able to monitor the temperatures.
And they're able to operate at negative four degrees
and up to 120 degrees.
The basics on a solar panel
is it's going to convert sunlight into DC power.
That DC power is then fed into inverters,
which are enclosed containers on the right of the screen,
and that converts it back from DC power to AC power,
and then feeds it to the grid.
And within those containers,
that's where we're able to see the ability to operate it.
Like I said, negative four degrees and 120 degrees.
The only maybe limiting factor on solar
is if you get a significant amount of snow accumulation
on the panels,
it may block the production from the sun.
There are essentially two types of solar farms
that typically get built those with what we call
a tracker system, and then those that are fixed.
And we have a picture of a tracker system on the slide.
It does what the name implies.
It essentially shifts the panels with the sun.
If you were to get a large amount of snow accumulation
on the panels and he had a tracker,
you could use the trackers to essentially dump the snow
to the ground.
If you have fixed panels where there's not a tracker system,
then it has to be removed by hand.
-: Can you maybe a high level describe the price difference
in terms of deployment of tracker versus fixed?
-: Sure.
(indistinct).
-: It's in range of 25%.
-: Yeah, 25%.
But I think one thing to keep in mind is there's advantages
to the tracker system in that as it rotates in with the sun,
you're getting better production.
-: Right
-: And so oftentimes when you're looking
at that investment choice,
you're looking at the resource and that drives it.
For the solar farms we have in Texas they are trackers.
-: So the net cost is positive when you add the two--
-: It could be.
It depends on the solar resource
and the geographical location.
-: Yeah.
-: And what happens if it gets to minus eight.
What happens to the inverter?
Does it shut down or is that a--
-: If it gets to minus four degrees,
once you pass the minus four degree threshold,
the invertible shut down to protect the (indistinct).
-: It will automatically shut down.
-: Yes.
-: As a protective measure?
-: A protective nature, yes.
-: And there's...
-: On the opposite extreme, when you go above 122,
it actually will not shut down,
it'll continue to operate.
And it starts slowly derating itself to protect electronics
from being overheated.
-: Gotcha.
And when you say the panels themselves are resilient
to these extreme temperatures.
Is that out of the box,
it doesn't require any additional investment?
-: Correct.
-: Gotcha.
-: Correct.
-: Battery storage systems think of them similar
to what we just discussed on solar.
The batteries are enclosed in how
and housed in controlled environment.
So you have the containers which you see on the right.
The bottom is a inside of a container.
So if you open it up.
Typically, with batteries,
what you're most concerned about is them overheating.
And so we have HVAC systems in the containers
that regulate the temperature.
They have a similar ability to operate
at the negative four to the 120 degrees Fahrenheit.
So it's very similar to solar again in close.
So it allows us to be able to regulate the temperature
a little bit and...
-: Out of the box, no additional--
-: Correct.
Correct.
And when we design them,
we design them with the ability to have the HVAC system.
I mean, there's a lot of attention and time spent
on the technology of the HVAC system to give it that range.
And so what you actually see in a cold environment
is it actually, you know,
as long as it doesn't go below negative four,
the cold environment actually help.
I mean, you don't worry about the batteries not operating,
that's not the risk profile.
The risk profile is the extreme heat.
-: So if you put a battery system in North Dakota
and the likelihood of going below negative four,
is there an enclosure system or heating system
or something else for the inverter
that would allow you to operate there?
Or is that a limitation of that type of inverter or?
-: Yeah, I mean, as an example,
we have a battery system up in Maine
and similar type environment as North Dakota.
And that container is actually housed inside the building.
So you can contain to temperatures even better there.
-: Okay.
-: So.
-: How low temperatures allow that inverter to operate?
-: I mean, it really comes down to what temperatures
can you maintain internal to the building.
And you've got heating systems (indistinct)--
-: How much insulation (indistinct)?
-: (indistinct) of employees.
So it really takes that away as a variable completely.
-: Gotcha.
-: Any other questions on any other questions
on solar or batteries before we shift to wind?
Good, all right.
So with respect to wind,
you can see illustrated on the right,
the geographical location of the ERCOT fleet,
it's mostly Northwest and south.
Wind began to be built in Texas in the late nineties.
So you can see wind farms that are brand new
to over 20 years old about 10%, excuse me,
about 40% of the fleet is 10 years or older.
In terms of our geographical footprint.
We have just over three and a half gigs of wind
that we operate in Texas that's about 13%.
And then GEs turbines represent about 43% of the fleet.
-: So with that, let me turn it over to Mark.
-: Thank you.
(clears throat)
So obviously, wind technology has evolved quite considerably
over the years.
The image here, the chart shows you how it's progressed.
And from the early 2003, you can see at a rotor diameter,
which is basically the swept area of a wind turbine
to capture the maximum amount of wind energy.
In a photograph there are a picture there,
that's about 71 meter, one meter rotor diameter on the left
and all the way to today's turbines
now we're about 140 meters.
So considerable technology advancements,
obviously, a lot of changes in the design
and capabilities of the equipment over the years.
Typical wind turbines, two to three megawatt turbine
today costs about two to three million dollars.
That's for an individual turbine.
And it generates energy anywhere between eight miles
per hour and 56 miles per hour.
So basically we call the eight miles per hour,
your cutting speed.
So once you see around eight miles per hour of wind energy
at that elevation,
that's when they'll start producing output,
and they'll run all the way up to 56 miles per hour.
Now, 56 miles per hour is not a hard cutoff.
It basically there's protection inside the wind turbines
that looks at if you're above 56 miles per hour
for a 10 minute period,
then it would shut determined on to protect that
You can operate up to 68 miles per hour for 30 seconds.
If you were above it for 30 seconds,
it will take it offline.
And then to storm protection at 76 miles per hour.
And I'm speaking particularly to the GE technology,
which is over 70% of our current portfolio.
-: So what was the last thing you get to 68 and then--
-: 68, you got at 30 Seconds,
76 mile per hour, you got about three seconds.
-: And that's storm protection.
-: When you say shut it down.
-: It'll shut it down.
It'll fetter the blades out of the wind,
and it will stop producing energy.
-: So it physically stop turning?
-: Right.
As soon as conditions clear,
it comes right back online itself.
-: For just driven by the rotating of the blades?
-: Absolutely.
-: Okay, gotcha.
-: What would you say?
I mean, these things are obviously rated
for certain conditions,
but what's the average hurricane force winds
that are experienced?
I mean, I'm just thinking about South Texas
and wind turbines.
-: Yeah, I mean, what is a category?
One is 75 mile per hour winds.
So.
-: So you'll shut down well in advance
of landfall of a hurricane--
-: No, no we shut down only when those winds
are actually experienced at that site.
-: Okay.
-: Yeah.
-: They do not shut down automatic.
-: All automatic.
And you may even have occasions where,
you know, half the sites running half the sites not running,
because there's a difference in the wind resources
experience across the different terrain are different.
Yeah.
-: And so on the full rating,
the latest 140 meter diameter
is how many megawatts per unit at a time?
Or what's a maximum they can produce at 56?
-: Oh, (indistinct) at 56 miles per hour.
Three megawatts (indistinct).
-: Three megawatts.
-: Yeah.
-: Okay.
-: Yeah, three megawatts there'll be a (indistinct).
-: That's where it tops off?
-: That's right.
-: Gotcha.
-: Right.
-: I'm sorry, you did say,
but above what wind miles per hour
do your blades start automatically shutting off again?
Sorry, sir.
-: Yeah, it's dependent not just on the speed of the wind,
but also the amount of time you're in that condition.
-: Okay.
-: So like 56 you can operate
in that condition for 10 minutes.
So it has to be sustained above 56 for a 10 minute period
before we shut it off to protect them.
If it's dropping in and out, it'll stay online, right?
And then it goes up in steps from there.
Any other questions on?
Okay, the other thing obviously is as we site
or wind facilities and we make sure
we cite them out of floodplains to make sure
that there's no risk of any flooding damage
to any of the equipment.
So this is a standard wind turbine overview.
Like I mentioned, we have a wide range of technology
within our fleet in Texas.
Our first units were installed in 2001,
and they're 0.7 megawatt turbines,
and they got 47 meter rotors, right?
So that's the swept area of the entire rotor.
So the diameter of the rotors.
And then till today,
this year we currently have machines up to 2.8 megawatts
with 127 meter at diameter rotor.
And so when you talk about how wind turbines operate?
I'll start really with the pitcher
and you talk about the blades.
So obviously the blades capture the wind energy
to kinetic energy into wind,
and they convert that into rotating mechanical energy.
So when a wind turbine is offline initially with low winds,
the blades will be pointing directly into the wind.
As the wind starts picking up,
the blades will capture that maximum mono lift
and the turbine will start coming online
automatically itself.
It uses a pitch system which each of the blades
are controlled independently.
In order to capture that wind and rotate the shaft.
You have a main bearing.
You can see here as you move back from the blades,
you have a main bearing that supports the load of the shaft
and take staff rotating energy from the blades
and transfers it into a gearbox.
That is a low speed, 20 RPM when it's a full output.
So what the gearbox does is it takes that 20 RPM
and it converts it into high speed
to feed it into the generator.
And then insight and your generator,
your generator converts that mechanical energy
into electrical energy.
From there it's fetched through a cable,
goes down tower into a collection system,
into your transformers and boost it onto the grid.
Few things to point out to support that as well,
is your weather station.
Your weather station essentially includes a wind vane,
which is looking at which way that prevailing wind
is coming from at any given time.
And what it actually does is it tells the controller,
Hey, winds coming out of the south.
And it turns the turbine around
directly into that to capture the maximum wind.
The way it turns the turbine around
is that y'all system underneath the second cell,
which is a big gearing system.
And what it does is it just rotates the entire turbine
into that wind to capture the maximum wind.
Also up there, you have an anemometer,
which is what's reading your wind speed.
And that's what it controls it's protective settings
based on it.
I'll pause for any questions.
-: We're good.
All right.
-: Thank you.
-: All right.
Thank you.
I'll jump through the intro here,
but one point I did wanna highlight with the GE
mentioned the fleet size here you're in Texas,
but we have just looking around the globe
we have about 49,000 wind turbines installed worldwide.
And about just over 7,000 or so here in Texas.
Just to put some perspective on these.
I do wanna speak a little bit about
just the temperature ranges.
We'll certainly focus on the cold weather side,
but did wanna talk through the hot weather
since that's been a point of discussion especially today.
Our standard weather turbines operate
between five and 104 degrees Fahrenheit.
The five degree limit is a fairly hard limit
that I'll go to in a little bit more detail
on the following slide.
The 104 is a softer limit,
similar to what Mark was just describing
with the solar inverters,
it's really around component protection.
So we have individual temperature sensors
on individual components that we monitor
and curtail the turbine in order to protect those.
-: So that's the point of failure.
The high end of the temperature spectrum is the inverter?
-: Other electronics.
-: And other electronics.
-: Correct.
Correct.
Yeah, we will look at the gearbox,
the generator, the inverter system that's there,
as well as a few other electronic components,
but it's almost all electronics.
-: Okay, a lot of the systems have individual cooling systems
and as long as they can maintain the cooling conditions
for that component,
we'll continue to operate even above 104.
-: Very cool and components for the electronics
or up on the blade or that.
-: Yeah, so fans in the cabinets for the electronics,
you've got ventilation systems
and just like a radiator for cooling of your gearboxes
and your vehicle components.
-: Okay, so it's both off of the actual windmill structure
and included in the windmill structure or no.
-: Up in the top where I was showing you a while ago.
-: Okay.
-: Internal to that top section,
you've got all different individual cooling systems
for each of the major components.
-: Gotcha.
-: Yep.
-: And is that 104 upper limit up at the turbine site
or is that at the ground level?
-: Turbine side.
-: It's a temperature that's right outside in the cell.
-: That's right.
-: Again, what's key is it's not a hard limit
that we often see are turbines running.
-: Is there like an average differential
between ground temperature and 300 feet?
I mean, is that a three or four degree difference
or, I mean, I know it has to do with wind
and all sorts of things, but is there just a gas.
-: I'll have to ask a climatologist.
(laughs)
-: (indistinct) a couple of degrees.
-: Couple degrees (indistinct)
-: So in addition to that,
that standard weather operation
really there's two solutions
that we provide today around cold weather operation.
One, we call winter ice operation mode.
And I'll go into this in a little more detail
on the following slide,
and then a cold weather extreme package
that's available as...
Both of those are available as a new unit offering
as well as a retrofit for existing fleet.
And then the following two points
just wanna touch on some of the technologies
that have been in the news talked about a lot recently,
especially after February, GE as a whole,
we purchased LM wind power in 2017, 2018 timeframe,
which is the world's largest blade manufacturer
between them and ourselves have quite a history
of blade technology development,
including those two solutions around coatings
on those blade services as well as heating solutions
for heating blades.
And unfortunately the isotropic coating.
So coatings that tried to shed ice,
they're just not a proven technology at the moment,
but we do continue to investigate
those as we proceed forward.
But right now, because they aren't a proven technology,
it's not an offering that we have today.
-: And the hidden blade solutions aren't either.
-: Correct.
So for currently not offered in the United States.
We do have specific offerings in Europe for that.
-: Okay, what are the constraints on the heated blade?
-: It really gets down to the type of ice you experience
and the number of days that you experience ice.
So just to put some things in perspective
of that 49,000 turbines that we have installed globally,
around 300 of them have this ice mitigation system
and they're all in the Nordic region.
So Sweden, Finland and--
-: Gotcha.
So that sounds like an economic constraint
rather than a technical constraint
in terms of utilization of the heating resource.
-: There is a technical constraint component,
and when I get into discussing, I'll hit that.
-: Can I ask you a question about,
if you say you have 7,000 megawatts here in ERCOT,
maybe if that's a little bit more,
if you include the panhandle, the SPP area,
but do you have a percentage of those
that have either one of these ice packages on there?
The ice or the-- -: Sure.
so in insects is of it is 7,000 turbines.
-: Oh, I'm sorry turbines.
Got it. -: Yeah, that's okay.
There's around 6,000 of them have that winter ice operation
mode control installed,
and around 1800 of them have the cold weather
extreme package.
-: Is the optimum to have both,
or does the cold weather extreme package
come with the winter ice operation mode
or are they two different?
-: They are two distinct offerings.
And on the next page I'll get into a little bit more detail.
-: Got it.
-: They address different things.
-: Sorry, to get--
-: It's a great question.
Good lead into the following slide.
-: For relevance, the isentropic coating
'cause we have a fleet of turbines all the way from Texas
all the way to Canada.
We have been testing that technology independent of GE
and about 400 turbines across our Northern fleet.
And we were able to look at similar cases
that were experienced here in Texas,
and it would have provided very minimal benefit.
The way the isentropic coating really works
is it's for all our purposes think about Rain-X
that you put on your windshield, right?
So it reduces the adhesion of icing that the blade.
And so what happens is it allows it to shed quicker,
but because of the high humidity conditions
that were experienced here in Texas
with the type of ice that Daniel will talk to,
it would quickly overwhelm this,
and it would only have promoted the ice shed
in a couple of hours faster on the back end
of the 10 to 12 day event.
So unfortunately minimal benefit from that solution.
-: All right.
So the first one, we'll talk about
the winterized operation mode.
The picture in the top left
is what we refer to as a power curve.
So Mark was just referring to how much energy
we generate at different wind speeds.
For wind turbine,
it's kind of an S shape and it's kept at the top
at our rating.
So three megawatts in the example
that Mark was just referring to.
And that's exemplified with the gray dots on the chart.
Whenever if you have winter ice operation mode installed,
and as you start to accumulate ice on the blades,
the effectiveness of those blades starts to drop.
You basically it's an aerodynamic fouling.
You just have this buildups,
or you're not getting as much lift on the blades
as you expected,
and so you start to generate less and less power,
and it becomes actually the red dots
that you see on the bottom of that chart.
And if you don't have this solution installed,
you would eventually stall out and shut down the turbine.
But with this solution installed,
it allows you to continue operating.
It's not all the way back up to the gray,
but you're able to hit the blue.
So this solution specifically controls base
and trying to address the initial accretion
of ice on blades.
-: So what does the solution actually do in practice?
-: Great question.
As mark was saying, we have pitch systems on our blades
that change how their angle of attack.
And it's really changing that angle.
So we have a set schedule in our control systems today
for that, what it should be at certain wind speeds.
And it's looking at that curve and says,
Ooh, we're not generating as much power as we should.
Let's adjust that a little bit.
And then it's able to bring that back up.
-: Okay, so that's...
Correct me if I'm wrong.
It sounds like that's a programming adjustment to increase--
-: Software adjustment.
-: It's a software.
-: So it doesn't actually physically change
any element of the ice,
it just optimizes the angle of the blade
to get back up a power curve for generation?
-: Yes, sir.
-: Gotcha.
-: Correct.
And depending on the technology
the different (indistinct) technology,
sometimes it can oscillate the blade intentionally
to basically try to shake off the ice is what it does.
-: Okay, just like the solar panels?
-: Yeah.
-: A lot of programming to dump it.
-: But it does it automatically itself,
does not require an operator action.
-: So is this solution sort of...
Does programming measure?
Does it detect it by sensitivity or degrees
or like how does...
-: So it's independent of temperature.
It's purely looking at how much power
am I generating at this wind speed?
And is it different from expected?
So there's a certain band of accessibility.
And once it gets outside of that band,
it starts to adjust that pitch activity.
-: The turbine knows when it's on its power curve,
because it's got the wind speed anemometer
I was referring to.
And when it falls off its power curve
it knows something's wrong.
So it knows in this condition,
he's not being conditioned that's like the icing.
So it turns on that (indistinct).
-: Reset optimized blade angle for generation.
-: Correct.
-: Gotcha.
-: And I may have heard this incorrectly,
but out of your 7,000 turbines
that your equipment is installed on,
you have 1700 that are winterized.
-: Around 6,000, have this winter ice.
-: Okay, 6,000.
Okay, great.
So 6,000 of them could be rated from five degrees
to minus 22.
-: Oh, sorry, just for the first item.
-: Just the first item.
-: Okay, great.
-: For the second item,
that one is closer to your number.
It's 1800.
1,800.
-: Okay, so in December of 1983,
the high was 12 and the low was negative one.
Okay.
-: When did you develop this solution?
Like around what timeframe?
-: The first one was I would say around 2009, 2010 timeframe.
-: So when your company NextEra decides
to put wind turbines in Texas,
is this something that you offer like,
you know, here are here all the different,
I guess, (clears throat) additional features you can add
to your wind turbine and they decide whether they add it,
or is it just sort of kind of a standard,
has become a standard sort of addition
to most wind turbines.
-: So the first one winterized operation mode
has become standard today for new units.
The second one is not.
That is an option.
-: So...
-: Specific to the first one we have that installed at all
on equipment.
-: Okay.
-: Which has over 70% of our Texas fleet.
Okay, and that's a lot of our wind generation
was put in place around CREZ, right?
In which started, you know, about 2007, 8, 9.
So it sounds like a good chunk of,
as you said to tie back to your statistics,
6,000 out of 7,000 turbines have this in there.
So the majority of the fleet, your fleet here in Texas,
'cause I think the wind turbines went back all the way
to the late nineties,
started being built,
but it sounds like with respect to the significant increase
in wind generation that occurred as a result of CREZ,
there's more of this solution became available
around that time.
And it's now part of the turbines
that had been installed during that period of significant
wind generation increase.
-: The, yes.
I mean, we have a fairly high penetration there.
Like I said, there's still maybe about a thousand or so,
that are left.
-: Maybe it's the older units.
-: I'm not sure exactly which ones,
but that would be a high probability that it is older.
-: What is the life cycle of a wind plant?
-: 20 Years.
-: 20 years.
-: Design life.
Even though our newer ones are beyond that.
-: And they can operate,
you know, that's the design life,
our experiences they can operate beyond the 20 years.
This winterized operating mode should be relatively easy
to retrofit or implement given
that it's a software solution-- (indistinct)
Yes, sir.
-: Okay, that's great.
-: How much does it cost?
(giggles)
-: We don't necessarily share price.
(laughs)
-: Well, okay, that's fair.
-: Yeah.
-: Yeah, maybe if I can share maybe a little bit of info
that may be helpful in this topic.
So as we look at our fleet,
we have winterized ice operation mode,
about 40% of our turbines located in Texas
have the cold weather extreme packages.
The new turbines we're building are going to have both,
and we're looking at what are the options
and possibilities of retrofitting
for the cold weather packages on the portion of our fleet
that do not currently have it.
We have to evaluate whether or not
they may have elements of it,
so we just we're in the process of validating that.
But one thing I do wanna raise is,
you know, we're talking about GE solutions.
We do have other OEMs that and we operate wind farms
with other other technologies.
Some of those technologies don't have these options.
Some of them you can, from our discussions with other OEMs,
you can purchase a cold weather extreme package,
but it limits the ability of the machine to operate
in the hot summers.
And so it becomes a bit of a trade-off on,
do you wanna operate in the summers,
or do you wanna operate in extreme code?
You know, have the ability to go to negative 14
and limit your ability in the summers.
And historically as an organization,
we've always prioritized the summer.
-: And in that vein, how does it limit?
What does it draw you down to,
in terms of your maximum heat performance?
-: Yeah, do you remember the temperatures?
-: We have it but it's just one moment.
-: 95.
-: Yeah, 95.
-: 95 degrees.
-: 95.
-: It's good to know.
Again, that's not specific to the GE technology.
-: Yes, sir.
-: Or the other technologies we have.
-: One of the other technologies.
-: And essentially that's because remember
that graphic I showed up the turbine,
they basically insulate right in the cell.
So it contains a lot more heat.
-: When NextEra says the a hundred percent of your new build
turbines in Texas have both products,
is that a consideration taken on a geographic basis
or is that a universal going forward?
-: For us, it was a universal decision after February.
-: Okay, gotcha.
-: Does that include retrofits also?
-: Well, we're in the process of evaluating
whether we can retrofit.
So think of, let me give you some percentages.
40% of our fleet already--
-: I really meant repowering not retrofitting.
-: Oh-oh! Repowering.
Yes, sir.
-: Okay.
-: Yes, sir.
-: And can I ask you a quick question?
What does rime ice?
Is that leading edge ice?
-: It's coming up in two slides.
(laughs)
-: Sorry to be head of ya.
(laughs)
-: Well, it's my fault for using words I have to find.
If I could wanna talk through the cold weather extreme
package real quick.
It's really around, you know,
earlier I talked about standard operation
going down to five degrees Fahrenheit.
With cold weather extreme,
we're able to extend that down to negative 22 Fahrenheit.
And you see in the curve there,
it's a declining line.
We start to derate the turbine as we go down
just from a loads mitigation standpoint.
Now, that what Kirk was referring to earlier,
the key component here is the type of steel
that's used in the towers.
So these towers are quite massive,
and in order to sustain operation below
five degrees Fahrenheit,
you have to have a cold weather capable steel.
And the reason for that is steel becomes quite brittle
at cold temperatures,
if you don't have the right gauge of steel,
you can have a minor imperfection
become a very big problem pretty quickly
at the loads that we see.
So the evaluation process that the curve
is referring to is the technical evaluation
we're looking at each of the towers
that are installed in Texas and saying,
"All right, what kind of steel do they have?
"Can they be extended down into the negative?"
-: So literally the oscillation of that blade
creates enough stress on the superstructure
of that facility to where it could fall.
-: The way we like to refer to it is,
it's almost like a jet engine on takeoff
is the amount of load thrust load
that's at the top of that.
-: On that level?
Okay.
-: Yeah, so and then you have a 80 to 90 meter lever arm.
So there's a ton of bending moment
at the bottom of that tower.
Sorry Mark, you wanna say something?
-: No, perfect.
-: All right.
Cool.
-: What does implementing that cold weather extreme package
look like in practice?
-: Good question.
So it's, number one is doing that evaluation
that I was referring to.
-: Gotcha.
-: And beyond the steel,
once you get past that gate,
it's around looking at the other components
within the wind turbine.
We're looking at maintaining temperature of our electronics
that we were referring to earlier,
as well as lubrication systems.
You know, just like the oil did you use in your car
a summer weight versus a winter weight oil,
those sorts of things.
So we do that evaluation and depending on what is installed
versus what is needed, that sets up the scope
of what's required.
-: Okay, so it doesn't sound like it's a physical,
it's a components adjustment rather
than a physical installation or?
-: It can include and particularly on the lubrication side
for the gearbox, for example,
you have to put additional heating equipment
into the oil systems.
-: Okay, so the main bearings that I showed you,
you'll change all the lubrication out
for a lubrication that can actually withstand
the lower ambient conditions.
So there's physical modifications as well as software.
-: That's right.
-: Okay, gotcha.
Thank you.
-: Any other questions on the slide?
(indistinct)
Participant: All right, so the wind is industry at large,
and whenever we start talking about icing,
we use the International Energy Associations classification
of ice regions globally.
And that is broken between class one
all the way up to class five.
And it's really comes down to how many days per year
are you expected to experience icing?
And for most of US, Texas included it's class one,
which is zero to two days of icing on average per year.
And the areas that I was referring to earlier,
Sweden, Finland, where we have most of our ice mitigation
systems installed active ice mitigation systems.
You're in the class four or five icing
where it's a hundred days plus.
-: Yup, so we've gotta ask on your map
on the lower left there,
it looks like your class one includes not only all of Texas,
but would go all the way up to Chicago.
-: It gets pretty close.
-: So I've gotta ask Chicago.
And what is the definition
if it's zero to two days of icing,
the definition of meteorological icing
is very different than the on-ground definition of icing
in Chicago.
I'd have to refer back to the IEA's use
and how they define that region.
-: Okay.
I mean, it definitely gets to New York
all the way up to Providence.
I mean, those are...
-: Those are main.
(indistinct)
-: Yeah.
We'll follow up with the IEA on that.
(laughs)
-: All right.
Great question.
Any others on this one before we jump
into types of ice?
-: You talk about heated blades.
I mean, you've talked a lot about the components
inside the turbine.
Obviously, it's the blade that gets the icing primarily.
-: Yup.
-: And I know that there has been work on polymers
and I know GE is now in the blade business,
but heated blades are not things
that I've actually heard about too too much.
Are they used in Europe or are they not working?
Are they?
What's kind of the state of the state of heated wind blades
and where are they used today?
-: It's primarily in those Nordic countries.
So Sweden and Finland
is where we have our largest installed base.
We have about 30 in Quebec
and that's about as close as you can get
to the United States where we have installations.
And there's two methods of heating a blade.
You can have hot air blown through the blade,
kind of like a heat exchanger,
for lack of a better word.
Where you're impinging hot air on the inside surface.
And the other is you can have a heating elements
embedded in the blade structure itself.
So similar to the heat tracing that was referred to earlier,
it's a similar approach,
except it's going down the leading edge of the blade.
There's pros and cons associated with each,
and certainly risks associated with each.
One of the things I'd like to call some attention to,
is just the power draw.
These are fairly large power hungry systems.
So the pump air and heat the air.
So whenever you flip those on,
it's not like you can flip on a whole wind farm
at the same time,
'cause all of a sudden you'll be a net negative,
you'll be a net draw or consumer of electricity.
-: Just one other data point that I think is helpful.
Obviously, we...
Again, we've talked with other OEMs
that have provided there in the process
of looking at these heated blade solutions
and we've asked them to take the February event
and tell us whether or not it would have mitigated
the issue.
And the feedback we've received is probably not.
They don't think it would have worked
given the level of ice that was witnessed here.
So in our mind, it's still very early,
and it's in the infancy of the evaluation,
and it's not a proven technology
and it's similar to ice phobic solutions.
Like Mark said, we're out piloting with what other groups,
we're trying to find something,
but there just isn't that product there yet.
-: So in the Nordic countries is the heated blade solution
of any variety of solving the aerodynamic
optimizing generation problem,
or does it become a structural physics problem
with too much weight on that fulcrum
at the end of that level?
-: I'm gonna jump to the next slide to answer that question.
-: Fair enough.
-: It's a great lead in.
So this slide describes the type of icing
that you can experience.
And there's really two main flavors.
And of course there's a mix, right?
It's a continuum along that spectrum.
So just as you just get below freezing
is where you start to see glaze ice.
So think icicles, those sorts of things,
where you have a fair amount of liquid water
that's able to move around,
and on the blade you get these very oddly shaped pieces.
It always starts at the leading edge
where the airflow is impinging,
and you get kind of these spikes
that come off the leading edge,
and then eventually that water runs down the back
to form kind of feather structures
that you see in that top right picture.
And then with that particular type of ice,
you have very high surface adhesion.
So it just sticks to the blade surface.
And it's also much denser,
so it's a heavier ice than you get
as you go further down in temperature.
That second flavor rime ice is what you see
with much colder temperatures and low humidity.
So it's more of a granual.
You can kinda think of powdered snow, right?
It's very different going through powder snow
versus wet snow.
And from like a snowboard and skiing standpoint.
The rime ice, it kinda flows along the aerodynamic surface
a little bit easier, much less adhesion, much lighter.
And that rime ice is what we see most of the time
in the Nordic regions.
And so the solutions that we have implemented there,
are better at addressing those, that type of ice.
Whereas the glaze ice as Kirk was referring to earlier.
It's our systems that we have are not as effective
of removing that type of ice.
And that's really the scenario
that we saw here in Texas in February.
-: And when you say that,
when this is implemented in the Nordic regions,
mainly addressing rime ice because of the energy pool
to implement these heated blade solutions
it's done on a one-off basis by turbine,
not wind farm wide?
-: Correct.
-: As needed on an as needed basis.
-: Right.
They try to do a more of an anti-icing.
So run it while the wind farm is still generating power.
-: Okay.
-: So that--
-: Every five minutes rotate.
-: Yeah, you tried exactly.
You just try to minimize your net consumption at that point.
So hopefully that gave you the definition
that you were asking for earlier
and a little bit more context.
Any other questions on the slide?
-: I don't think so.
-: Okay.
-: All right, so last slide just quick summary here
that on points I've already hit on just around the zero
to two days wising per year.
And the two systems that we currently operate,
and offer within the United States around Wyoming
and cold weather extreme.
Those are, as I mentioned, can be retrofitted
and are available for new units today.
And then I do mention just that,
that technology roadmap around heated blade solutions
in the United States,
we're continuing to work what we have in the Nordic regions,
but in terms of the units that we're bringing
into the United States is currently not in the roadmap
to bring those solutions here.
-: Appreciate it.
Any other questions for the panel?
All right.
-: All right, thank you.
-: Nice presentation.
Thank you all very much.
Next we're hearing from a NERC
on weatherization requirements.
And while we make that transition,
Dr. Gavin, would you entertain us on any thoughts
on the IEA's definition of all of Texas,
all the way up to Chicago and New York
only having zero to two days of icing per year.
Any thoughts on that?
-: I assume that it doesn't include snow fall.
Snow only tend to fall off rather
than if you really on a moving surface.
So that's probably what's involved with that.
-: That's a distinct, so it would,
their definition of icing is not on roads or.
-: Including rain.
-: You need precipitation plus on a non flat surface.
-: Even flat surface, but if it's (indistinct).
Think of it (indistinct).
So when you have freezing rain on any surface
that it accumulates and sticks.
You can't sweep it off,
the wind doesn't blow it off.
Snow particularly on a blade
which is going to be same temperature as the air,
it's not going to be the same problem in the winter,
and that's an issue.
But when you have the icing occurrence,
when you have a liquid water,
that's actually below freezing,
hitting a surface and then freezing on contact.
And that's the condition that's (indistinct).
-: Interesting.
Thank you.
Welcome.
-: Good morning, Joseph Younger,
I'm the Director of Enforcement,
Reliability Standards and Registration at Texas RE,
which is the Regional Reliability Entity.
That's part of the NERC Electric Reliability Organization.
I'm mainly gonna focus on the mandatory standards
that are being developed as part of the NERC
cold-weather standards project this year.
But I wanted to start by briefly giving a little background
on the activities that proceeded the current cold weather
standard project.
NERC and Texas RE in particular,
their engagement with the weatherization issues
really began in 2011,
in connection with the 2011 winter event.
Texas RE supported FERC and NERC in the joint inquiry
around that winter event to review and develop
recommendations around weatherization
in cold weather operations planning.
And that report, which came out in 2012,
provided winter weatherization recommendations
for generator owners and operators,
plant design, maintenance and inspection implementation
of specific freeze protection measures.
And out of that report,
NERC in connection with industry developed
a number of voluntary reliability guidelines
and lessons learned on generator, winter preparations.
And those guidelines, which have been now revised
three times, I believe,
they provide guidance on really how to design
and implement an effective cold weather
preparedness program.
And so there's a lot of elements that go into that.
I think Mr. Gates touched on some of those earlier,
but it runs a range from roles for corporate
and plant management and preparation for winter events.
The typical problem areas you might see with equipment.
And so if you can, so you can identify and prioritize
your maintenance and installation activities,
recommendations around testing,
low-frequency activities
like starting emergency generators
prior to the onset of cold weather,
those types of activities.
As well as training staffing, communication protocols.
So it's a framework for designing
your cold weather preparations.
And so Texas RE's ease activities have really focused
on implementing and sharing information
around those guidelines.
And we've done that primarily in two ways.
The first is we conduct an annual generator
preparedness workshop.
We've done it every year since 2013.
Typically, at the end of September
which aligns with a lot of the timelines
for the generators they're preparing for this season,
putting their preparations in place
and their training activities in that September
and October timeframe.
We also perform focus site visits each year.
We've done this with ERCOT staff
and over the last three years,
we've done 134 of these site visits
to look at the implementation of,
again, the controls for this specific site
share best practices.
We'll get also the procedural documents,
where training has occurred
and do some targeted outreach with those engagements.
-: So that's the lead,
and I'm not sure why this slide looks like this,
but the mandatory cold weather preparedness requirements,
that project really began in 2019
in response to a second cold weather event
that primarily impacted the south central United States
in January 17th, 2018.
And the project implements the recommendations
that came out of the NERC and FERC report
analyzing that event.
And there it's really focused on two areas
and addresses several of the mandatory
NERC reliability standards.
The first area is a requirement for generator owners
to develop and implement cold weather preparedness plans.
Now, I'll touch on those elements in just a second.
The other element provides provisions for notification
through what are known as documented data specifications.
So in this region, it would be ERCOT
acting in NERC parlance is the reliability coordinator
and balancing authority,
they issue data specifications to generator owner
and operators specific data that ERCOT needs
to perform its real-time assessment
and monitoring activities.
And so this has provisions to require generator owners
require that specification and provide data
around operating limitations, cold weather,
limitations, minimum historic operating temperature,
that type of information so that ERCOT
can have situational awareness
entering a cold weather event.
-: What does that really mean?
I mean, does that mean that that ERCOT
knows exactly which turbines have,
or should they know which turbines, wind turbines,
for example, have cold-weather packages on them,
or which gas-fired plants have weatherization packages
on them?
I mean, it seems like if they're running their models
to determine day ahead or hourly forecasts,
they need to know specifics of each plan.
Do they know that?
-: So the standard itself doesn't specify the granularity
of the data specification.
That's something that ERCOT can determine,
but what it does specify is that the generator owners
have to determine,
and then ERCOT will request on the periodicity
and with the deadlines for providing an information
that they deem appropriate.
Capability and availability of the unit.
We have fuel supply limitations, switching capability,
environmental constraints.
So those broad categories.
So the standard itself doesn't touch on,
get down to that level of granularity
where that can be part of the data specification of ERCOT
deems that necessary for its monitoring
and assessment activities.
This next slide kind of looks at the cold weather
preparedness plan requirements themselves,
and lays out what the framework
that set forth in the plan requirements
for generators group sets out.
And so it requires generators to implement
freeze protection measures based on geographic location
and plant configuration.
It does not specify a specific freeze protection measures.
So it requires you to implement those measures
that you deem appropriate for your specific site
and location, but it doesn't set a baseline
or mandate any specific measures.
And that in part reflects the standard.
It's a continent wide standard.
So it's picking up units that would be enclosed
in Minnesota as well as units
that would be here in Texas or Florida.
And so it's a trying to address that,
but it does require you to have a plan
that implements appropriate freeze protection measures.
It also requires you to perform annual maintenance
and inspection activities on those measures.
Again, it doesn't specify what those are,
but it requires your plan to contain those elements.
It's also requires you to develop data
on operating limitations,
which is what we were just speaking about in connection
with the day that you would provide in this region, ERCOT,
as well as provide unit specific training to personnel.
So and that's really the framework
that set out in those plans.
-: And how much of the supply chain do you have to go?
I mean, generator operator obviously,
or generator owner is responsible
for just what's inside their fence.
Do they have to go any further
to talk about their fuel supply
or their water supplier or anything like that?
-: It's not specified in the standard.
So the standard doesn't speak to reaching out beyond
in terms of the mandatory requirements in the plan.
There's nothing that's required in that.
Now, if you turn to the reliability guidelines
or those other frameworks that does have suggestions
on reaching beyond the fence line
and looking at those considerations,
and you do have to provide,
again that as part of the data specification,
you're gonna have to tell ERCOT,
what are your fuel supply limitations?
Do you have any?
What are your capabilities?
Do you have that switching capability?
Those elements.
But in terms of the maintenance and inspection
or those activities,
it's not a required element of the plan.
-: So if ERCOT has that information,
do we know if it is electronic?
Is it in their algorithms?
Or is it just a piece of paper
that says these are, you know,
I've written NERC compliance plans
and these are my limitations.
And I mean, can you shed any light on that?
-: Well, and I think ERCOT might be in a better place
to speak to that specifically.
But so ERCOT maintains a fairly broad data specification.
So they have a number of things that they require
and they deem that they need to perform
their real-time assessment monitoring activities.
-: Low and behold here's ERCOT.
(laughs)
-: And they can speak to it much better than I can.
So I'll be quiet and let them talk.
Okay.
(laughs)
-: Thanks for coming up Woody.
-: So we rely mostly on the current operating plan
that the generators supply to us going out for seven days.
So that's where most of that operating data
is gonna come from.
We also collect the unit data
that will have all the specifications and things like that.
Now, when this passed,
we'll have to look at that and determine
what is needed further than what we currently collect.
So there'll be some additional data requests made
once these standards are official.
-: But all of the data points that Jimmy's talking about,
how much currently and for the recent past has ERCOT
had on specific generators?
-: So in particular, which ones are you asking about?
-: Well, I mean, I think it's just the general...
I mean, I know you have general operating characteristics
of each unit in each plant that have to be accepted
by you all to put into your modeling,
your day ahead models or your real-time models.
Do you have any of these...
Are you able to look into maybe deviations from those,
or limitations of those that are...
So 99 point something percent of the year
you're running just fine,
but that's not the part of the time we're worried about,
we're worried about the 0.1 or the 0.2%
when we have extreme weather, either hot or cold.
Do you somehow integrate the limitations of each unit
into your algorithms in that regard?
In other words, if we're gonna get 110 degrees
across the state,
do we know how many wind turbines
are not gonna run above 104 degrees or 105 degrees?
-: We currently do not.
-: Okay.
-: But that's not included in the current operating plan
that's provided to ERCOT by generating assets.
-: Okay, so there's two separate things there.
So we do not have it built in to any of our systems.
Now, if a generator knows that they're gonna be outside
their operating range and they put it in their cop,
then that would go into our operating system.
But it's not hardwired into the underlying operating
algorithms so to speak of our system
to know that 110 degree day,
we have lost X number of megawatts.
That is not hardwired into it.
Currently, it only comes through the top data.
-: So--
-: The current operating plan, the cop.
-: Which is around what timeline?
-: The cop is for seven days out.
-: But in practice and my understanding
is this only about 24 hours out?
-: In practice it's more like a 24 hour notice.
-: Okay.
-: So just as a practical question, Woody,
so take URI.
We've got 1900 some-odd wind turbines
that are rated for what five degrees?
No, five to minus 22 degrees,
depending on that cop,
you do not know where they are,
and how they'll perform at the early stages
of a big winter event moving through.
So from a performance evaluation model,
do you have that information?
-: So there is a third piece of information
that comes in when we start talking about wind units
and that's our forecasting, our wind forecasting.
We do forecast icing conditions.
And so we do have another way of anticipating
wind generation that won't be there because of icing.
-: ERCOT doesn't have any visibility
on which of the 7,000 wind generators
have the cold weather extreme package.
-: That's right.
-: Unless I think (indistinct) the bottom,
correct me if I'm wrong,
I'm to try to summarize this.
The bottom line is ERCOT operations
does not have unit specific data related
to potential performance variants
related to extreme weather unless it is volunteered
by that generator at which point
it can be integrated into the ERCOT models.
-: That's correct.
Well put.
-: Okay.
-: What about those December 1st attestations
for preparedness?
Is there any additional data you can lean there?
-: There is some additional data in those,
but that's not hardwired into any of our systems.
That would be something that as we go out
and do spot inspections and things like that,
we'll discuss those things,
we'll talk about those things,
but then it's not hardwired so to speak
into any of our systems.
-: All right.
Thanks Wood.
-: Thank you.
-: Good.
-: Thank you.
-: Appreciate you stepping up.
-: Well, and that's a good transition
because this is standard is under development.
So the cold weather standards have moved
through the NERC project,
and that standards development process.
And that process is a stakeholder driven process.
So Texas RE in that process is an essence of stakeholder.
And so we provide comments on the standards,
but we don't develop the standards ourselves.
It's an industry driven process,
and that's moved through the NERC process
and the NERC board approve that in June.
It's with spile with FERC on June 17th.
And so now it's under consideration at FERC.
FERC as part of that consideration process,
they can adopt or reject the standard.
They can also accept it,
but issue directives to either implement more elements
or look at different aspects.
So that's within FERC's discretion in that process.
Once FERC acts and assuming they don't make changes
to this piece of it,
the current standard contemplates becoming effective
18 months from when FERC takes action.
So there's an implementation time period.
So it won't immediately take effect following FERC's action.
-: Do you think... -: So just...
-: Go on Lori.
-: Oh, just to be clear that the cold weather standards
that are currently pending approval at FERC
are based on the 2018 South Central weather event.
-: The recommendation, so that's the origin of that.
So they're not contemplating for instance
the current joint inquiry that's ongoing,
that may be folded into the development process
'cause STEC is obviously those recommendations
are coming out in the...
The preliminary recommendations are coming out in September,
I believe.
And then the final report sometime in November.
So FERC could incorporate those recommendations
if they wished through a directive,
or if that doesn't occur NERC,
in fact, I'll just move ahead a couple of slides.
NERC is looking at likely looking at the results
of that joint inquiry and considering whether
to add additional granularity as well,
or additional recommendations from that into the framework
that the current standard sets out.
So it's a... While this is a first draft of it,
there may be additional.
In fact, I think there likely will be additional work
in this area in some form or fashion.
-: So just kind of practical purposes,
once FERC approves the cold weather standards,
whether they include February 2021 recommendations or not,
the TRE would then ensure compliance
under the cold weather standards.
And that compliance is also supported by enforcement.
-: That's correct, yes.
Once FERC has approved the standard
and the implementation period runs.
So whether it's 18 months or a shorter period,
if FERC would prefer that,
then we would begin to one audit the standard.
So we can conduct audits,
entities can also self-report under the standard,
and we would have now a mandatory standard
to exercise our enforcement authority on.
And so it would likely be part of our risk-based
auditing enforcement activities.
It would be just like all the other standards.
Yes.
-: Do you think any of these once approved by FERC
this new standard would have really made a difference
in Texas during our event?
-: Well, it's hard to say.
I think a lot of this framework,
and again, this is a continent wide standard, right?
-: Right.
-: A lot of this framework is similar to what we ERCOT
had in place through the protocol requirements,
around having a weatherization plan,
around attesting to the implementation of that plan.
And this is a framework to,
again, have a plan and have these elements
that's (indistinct).
-: Have the plan, follow the plan, train to the plan,
submit the plan, whatever.
-: Conduct maintenance on the plan, you know,
like have those have that framework too.
So it is similar to what was in place in the ERCOT protocols
prior to the event.
-: Okay.
-: And I was just gonna flag a couple of,
we are doing some outreach activities around
as these standards are rolling out.
So we did an outreach on July 8th.
We have a targeted outreach with scheduled for August 23rd
to discuss the standard requirements
and their implementation efforts.
And our regular annual winterization workshop
is gonna be on September 30th this year.
We're also planning a lot of future outreach activities,
both in connection with the cold weather standard,
as well as the joint inquiry as this kind of moves
through the process.
-: All right.
Anything else?
Questions <v ->That's all I have.
-: All right, so any other questions for Mr. Younger?
Thank you very much for being here.
-: Thank you.
-: Next up we have STEC speaking about
weatherization requirements.
NESC weatherization requirements, excuse me.
Participant: We'll be right back.
Chairman: Welcome gentleman.
-: I would like to say good morning,, sorry.
Chairman, Commissioners.
My name is Cory Allen,
I'm with South Texas Electric Cooperative.
I'm the Manager of the Power Delivery Division.
Got Paul Person with me is the manager of our engineering
in case there's any questions at all.
(laughs)
-: Welcome both.
-: He's gonna help me answer them.
(laughs)
So the National Electric Safety Code
is a standard developed by IEEE's,
National Electric Safety Committee,
and they use procedures that are approved by ANSI.
This map shows up in two places, section 23 and section 25
of the NESC.
And as you can see, it covers the 48 states
and Mexico, parts of Mexico
but before this clips it off.
But as you can see that the three major zones
are all present in Texas,
that have differing weather related characteristics
that are used in overhead line designs.
Chairman: There's a period of difference substantially
from the IEA's.
Cory: I'm sorry.
Chairman: That map appears to differ substantially
from the IEA.
Cory: Much different than the IEA.
(laughs)
You're right.
Participant: What voltage does this go down to?
Cory: All voltages.
Participant: All voltages.
Cory: Overhead lines.
Participant: Transmission only or distribution also?
Cory: All overhead lines are covered
in the National Electric Safety Code.
I think even even service drops or it might be in there.
There is a change point where in service drops
as they go into residentials and commercials
and also at an industrial complexes
those are at higher voltage exchanges
maybe even transmission voltage exchanges
that the National Electric Safety Code doesn't apply to you
in any seed starts cutting in and and other codes.
So a lot of our discussion will reflect back to these zones.
So the map notes, clearance zones one, two and three,
they determine what specific wind ice
and temperature characteristics that land designers
have to apply whenever they are putting together
their plan for clearances,
making sure they get the vertical clearances
above ground and other obstacles.
The loading zones, heavy, medium and light.
Those are the three that are in Texas
determine where specific wind and ice mounts
and temperatures that designers take into account
whenever they are determining the strength
of the structures the loading of the wires
put on the structures and put on the arms
and put on the insulators.
So the first one was Section 23.
This is the clearance rules and Rule 230B
and Section 23 has the ice and wind loading characteristics
that the designers have to take into account.
It defines the minimum ice wind speed and temperature
for each zone cause they differ
when figuring out what that conductor sag,
and what the blowout is gonna be in wind conditions.
And ice build up applies weight to the wires
which increases the sag of the conductors,
that's gotta be taken into account according to NESC.
Ice and wind combine to make a bigger profile,
a bigger cross section that wind blows
against on the conductor and I don't know the structures,
I guess too.
And it takes them from their at rest position.
So that has an impact on your horizontal clearances
to obstacles or even to your right away boundary.
The ice and wind and temperature characteristics,
they affect the short and long-term stretching of your wires
that you have to take into account in a design phase.
So table two 30 dash one has the ice thickness
for your vertical clearances essentially.
And you can see in zone one has a half inch of ice
that you have to add to your conductor.
Zone two a little bit less, right?
It's quarter-inch.
Zone three, which most of stacks 2200 miles of line
are in a zone three or light loading zone.
And it's zero ice.
So the way that we look at it is the ice
is assumed to surround it uniformly.
And so for a inch conductor like 795 ACSR
and zone one,
the heavy loading district that would add an inch, right?
So we really double the surface
that the wind is blowing against.
-: So that means...
So on the zone one,
you would have to raise it by 12.5 millimeters.
Is that right?
-: Times two,
because that's a uniform thickness
all the way around your wire.
-: Got it.
Okay.
And that's just a...
So 24 millimeters or 25 millimeters
that you would add is that clearance that you need to add?
-: Now, that's actually the volume of ice
you have to consider, right?
And then you calculate the weight of that.
-: And those are inputs for the clearance of the line
from the ground to the conductor?
-: Yes, sir.
And other obstacles.
-: And other obstacles.
-: So this table 230-2 essentially just expands
upon the table before,
and it aids in the wind that we're supposed
to look at as a minimum for where that conductor
is gonna move to in a wind and ice situation.
Also as temperatures,
you can notice that the temperature
that has to be considered in his own one is zero
and then 15 degrees Fahrenheit in zone two.
And most of our lines are in area of design consideration,
minimum design consideration is at 30 degrees Fahrenheit.
I put this in there just to make some sense of,
you notice that the winds are put in there as a pounds
per square foot.
So through this table in there just to show what that meant.
So if you remember that the zone one was four pounds
was mentioned with its half inch ice on the conductors,
and so that's about 40 miles an hour.
Participant: Working.
Participant: Good.
No, sir.
Cory: If you can calculate that at any velocity
or estimated any with the...
Chairman: I was just gonna ask
if you could give a relative example
of what four foot pounds of or 190 pascals
looks like in practice.
Cory: So like that four pounds per foot
that you have to consider is 40 for the light loading zone,
for zone one is that nine pounds
per foot squared is a 60 mile an hour.
I think 150 mile an hour wind
is somewhere around 60 pounds per foot squared.
Maybe a little bit lower than that.
The NESC does include a calculation for you
to look at specific miles per wind and miles per hour
to see what that pressure be on cylindrical surfaces.
Chairman: Thank you.
Jimmy: Is that primarily for conductors swinging sideways
outside there the right of way or within the right of way,
or is that the wind component of it?
Cory: So we really just look at a horizontal wind force
on the wire.
It's really worst case, right?
Whether it's kicked up in a blow out position
or whether it's down at rest,
obviously, it's not gonna be sitting at rest
whenever there's some high wind blowing,
but at that at rest is really gonna be the biggest
horizontal profile, I guess,
that our conductor shows to a wind force,
you start blowing out.
I mean, maybe there's an argument that it's the same
no matter what.
No matter what angle it is,
I would guess it would be the same but.
Chairman: So this is both considering the range of motion
of the water,
but also the tension put on the stabilizing joint
to make sure it stays in place?
Cory: Our Section 25 of the NESC
is where it hits into the strength requirements
of your structure, your insulator,
your conductor itself,
your foundation and everything else.
Chairman: I jumped slides again, I'm sorry.
Cory: No, that's fine.
It's actually the same wind ice
and temperature characteristics for zone.
You'll see here in a minute.
So we're jumping into Section 25,
of what you were talking about.
Now, Section 25 really describes three main scenarios
that the engineer has to look at,
when he's looking at strength of the line components,
250B, that's the combined ice
and when district loading 250C,
extreme wind loading and 250D relatively a newcomer,
extreme ice with concurrent wind loading.
And I throw this in there just to kind of make a visual
of what we're talking about with the wind pressure
on the conductors.
So any one of all those three need to be considered
and whichever one convinces the designer
of the highest strength components,
that's the one they'll have to go with.
So again, this looks really familiar,
because it's got a lot of the same information as earlier.
The heavy is essentially it's the same area
as the zone one in the map.
The half inch of ice uniformly around the connectors.
The winds at four pounds and temperatures at zero degrees
all the way over here to what we call the light loading,
where it's got heavier wind, you have to consider,
but no ice and a lot higher temperature.
So rule 250C and I'm sorry,
I didn't say that this is really applicable
to rule 250B.
And then a rule 250C,
this is the extreme wind rule.
As you can see there along the coast.
And we do have some coastal area in our service territories
is the extreme wind in the hurricane zones, right?
That we need to consider.
We actually at STEC look at that as as a minimum,
and not wanting to be too close to the minimum.
We had 10 miles per hour to our wind loading
thought processes during our design phase of our lines.
250D is the extreme ice extreme wind and ice loading.
It introduces a new map here a little bit harder
to understand and I can hardly read it.
And I know what it's supposed to be saying.
But up here in the upper part of the state
and not exactly concurrent with the zone maps,
LCRA did file A, a map that looked pretty good
at they superimposed these extreme wind
and ice loading boundary lines over the heavy,
medium and light loading zone map.
That was a pretty good visual that they had,
and they call your attention to that.
And it's maybe easier to understand
where these things fall out.
But this is a three quarters of an inch of an ice
above this boundary here that is considered concurrent
with 30 mile an hour wind.
So that's your extreme wind and ice loading
characteristic there.
Once you get down here to Austin, a little bit lower,
a lot of our territory is in this,
where you gotta look at a half inch
and 30 miles an hour of wind.
So then you get down into the valley.
Now, we're looking at a quarter inch
and 30 miles an hour of wind
when we're considering the strength
of our components or line.
So I did wanna point out that that's not the only things
that affect our strength and our decisions upon foundations
and cross arms, Devin arms, whatever.
There's also in the NESC and rule 253,
some load factors,
all of the transmission lines are construction Grade B.
So you can see where we starting into a traverse loads,
transverse loads on the lions.
We've got factors of safety multipliers in there.
2.5 and for wire tension is 1.65.
But so there's other things besides those wind loading
and ice loading requirements.
So I did wanna list there's a whole bunch of stuff in NESC
that are not in the slides (giggles)
that designers are required to go down
quite a few rabbit holes.
Altitude differences,
lines that crosses on boundaries.
We have only one of those,
imagine most TSPs have a lot more lines
that cross zone boundaries and NESC does talk about
how to figure those.
And at certain heights, some of those extreme wind
and ice loading characteristics don't apply.
If you don't have something that's over 60 foot tall.
So there's a lot of other aspects
that the designer looks at that are weather related.
-: And we're back at the beginning.
All right, questions.
Comments?
-: I brought him for nothing?
(laughs)
-: We just assume you did such a good job explaining it,
that there's no need for the engineer to answer questions.
Thank you all for being here.
(indistinct)
That concludes our work on item number four,
roughly as planned lunch break,
30 minutes work for y'all?
-: Yes, sir.
-: We'll reconvene...
I don't think anybody has anything
for items five through nine.
So when we reconvene at 1:00 p.m,
we'll move to item 10 regarding staff discussion
on establishing weatherization standards.
We'll be back here at 1:00 p.m.
Good afternoon.
At this point, we will reconvene this meeting
of the Public Utility Commission of Texas.
And I will confirm to my fellow Commissioners
that's the last time I take only 30
instead of 45 minutes for lunch.
(laughs)
We are on agenda item number 10,
rulemaking related to establishing
weatherization standards
we have from Commission staff, Barksdale English
to discuss the straw man or draft of drafts
comments related to project 5184.
Barksdale.
Barksadale the floor is yours.
-: Thank you very much, chairman and Commissioners
I really appreciate the opportunity
to be able to visit with you today
and talk about the draft that staff has proposed
for the weather preparation standards
that are required from Senate Bill three.
I would be remiss if I didn't take this very early
opportunity to say what a wonderful rule-making team
that we have.
All of our team members are here from Kristin Abbott,
Keith Rogas, Ramya Ramaswamy
and Albert Esser are all here.
We've been working hard for the last three months.
We actually passed our three months birthday yesterday.
So and that means we've got three more months to go,
before the statutory deadline of completing this rule.
So I'm happy to say that procedurally we're right on track.
Exactly where we were hoping to be when we first laid out
our schedule,
and we're looking forward to a healthy conversation
with y'all today to figure out if we're on the right track
and how you'd like us to adjust if not.
I also wanna say that I've got probably about 15 minutes
of prepared remarks that go through the rule.
If you prefer to just jump ahead to specific questions,
please let me know.
And if not, if you want me to go through
my prepared presentation,
please interrupt me at any time.
Chairman: Sounds good.
Go ahead.
We'll start with the prepared presentation.
-: Great.
As we started thinking about this rule,
we learned early on that we needed to be consulting
with a lot of folks.
So we've been working with a team at ERCOT,
we've consulted with the independent market monitor,
we consulted with the Texas Reliability Entity,
as well as the state climatologist.
We've also had informal meetings with stakeholders
from all different segments of the industry.
So we've taken a lot of feedback
in terms of how to think about weather preparation.
And part of the reason why we felt the need to take
that time to consult with so many different experts
in the industry is because the statute
is an interesting one.
In that it talks about weather preparation.
It doesn't talk about weatherization.
It doesn't talk about the specific steps
that need to be taken,
it talks about preparing to operate
during a weather emergency.
And so we spent a lot of time thinking about
what does that mean to prepare to operate?
And also thinking about the difference
between preparation and performance.
And through this rule,
we have realized that we need to write rules
that generators and transmission operators
are prepared to operate and can maintain
their service quality and provide adequate service
during certain kinds of weather emergencies.
And that's challenging for our market.
It's challenging for our industry here,
because in an energy only market,
it's difficult to imagine what it means
to have a generation resource
that has to be ready to provide service,
because we don't have the market construct to guarantee
that they provide service at any given moment in time.
And so that's a difficult thing for us to conceptualize.
-: We also know need to think a little bit about
where we set our standards
so that if we go too far too fast,
we actually end up with a tag-a-long effect
where we see more resources exiting the market early
because of the costs that might be incurred
to have to prepare those units.
And finally, the last really big challenge
that we faced as a team
was the short implementation deadline.
And six months to write a rule
that the Commission has never taken out before,
we've never regulated in this area before.
And one that's as complex
and is as important to the public as it is,
it's been a difficult challenge.
And hopefully you see the thoughtfulness
of those preparations.
So the rule, excuse me,
the statute talks about preparation.
And I mentioned before that we tried hard
to not focus on performance.
And similarly, we tried hard to not focus on planning.
And you heard from the TRE earlier this morning
about the cold weather standards that they're working on.
And so we actually see this proposed rule
is working really well with what NERC
and hopefully FERC will be doing later on this year.
They're tackling the planning part,
here we're tackling the preparation part.
And then the performance part is an area
where my real day job is you're a director of compliance
and enforcement.
If there are performance issues during a weather event,
then that's something that we would look at,
on a case by case basis.
But the critical point that I wanna make here is that,
performance in and of itself during
any given weather emergency,
isn't something that we have proposed
to regulate in this role.
Part of the reason why we haven't proposed that here is,
one for the clear reason,
because the statute talks about preparation.
Another one is that our market structure in ERCOT
is such that there is a voluntary basis
on which generators commit their units.
They have to communicate with ERCOT,
they have to tell them when they're gonna run,
when they're not gonna run.
But at the end of the day,
it's up to that resource in the real-time energy market
to say whether they're gonna perform or not.
And there are some other products that exist in ERCOT,
the ancillary services products,
emergency response service.
These are capacity products for which generators get paid
to be available to perform.
So we do have some kind of ancillary products
to the overall market construct,
where we can think about what it means to perform
during a weather emergency.
But in the moment, when the rubber meets the road,
there's really not a great market construct
to think about performance.
So thinking about what it means to prepare
for a weather emergency,
we have to think about what a reliability standard is?
We have to think about what does it mean to be prepared,
to operate during extreme weather.
And this morning we heard from a representative of Calpine
about all the very idiosyncratic steps
that they have to take to get their resource prepared
at that site.
And we've noted through our conversations
with all of the different industry stakeholders
that those steps to prepare
are not just different owner to owner,
but there are also different plant to plant.
So the same owner could have different steps
to prepare their site in their plants all across the state.
-: And so that leads us to think
about not having technical requirements in this rule,
because if we set something down on paper that says,
thou shall have tarps up in any northwesterly facing area.
First of all, that might be great,
and that might be best practice,
but that could not necessarily apply
or be relevant to plants
that don't have those kinds of characteristics.
And then we would be requiring generation owners
to be doing things that just aren't really helping solve
any problems.
And second, technology moves faster than government,
and innovation moves faster than government.
And so rather than trying to set a minimum standard
of specific technical things
that folks have to do to be ready to operate,
we would rather put that burden on them and say,
look, you have to prepare to a certain standard
and you have to figure out what the best way,
the most cost-effective way and the most reliable way
of doing it is,
because you were far more motivated
to get your plant ready to run,
and know the steps that you need to take
at that individual site and across your fleet
in order to do it.
So given all of that background,
we're kind of left to the point of trying to define
what a weather emergency is?
And the best way that we've come up with,
is to think about all of the historical weather data
that exists in the state,
and figuring out what are situations
in which we would expect a generation owner
and a transmission owner to be prepared to provide service.
And I think you've heard from both Chris
and John this morning,
that there are a lot of different ways to slice that data.
You can look at an individual event and you can say,
well, this was the coldest average day
in the last 100 years, but if you think about it,
in terms of the number of hours in a year
then maybe it was only the seventh coldest
in the last a hundred years,
or something like that.
So because the data is complicated,
and because it's the availability of that data is variable.
You heard Chris talking about having to go out
and buy reliable weather data.
I think John's got access to a little bit
of more robust data given his role
as the state climatologist.
And Chairman, I noticed that you said
you were gonna talk to,
you know, when generators came and visited you,
you're gonna ask them where they get
their weather data from?
Because those are all potentially different sources of data,
we thought it best to use Chris and ERCOT
to come up with a definitive dataset
that we could feel comfortable was they were valid data
and it was quality data and generate some scenarios
that were probable outcomes both now and in the future.
And this has proved to be a more difficult task
than I think we on staff originally imagined,
because of the quality of the data that Chris has access to.
I think he and his folks have spent a lot of time gathering
that data and trying to figure out where the holes are,
and why the analysis isn't quite running the way
that they were hoping to?
But I know he's working hard
and is making good progress even as of yesterday.
And so in this rule, we have asked ERCOT,
or we've proposed to ask ERCOT to analyze this dataset
and for some specific parameters
for high and low temperatures for wind precipitation,
for duration of these parameters,
you know, how long those things
last over the course of a day.
And consider these parameters on a regional basis
so that we're not just setting,
we're not just thinking about weather
one point in the entire state.
I will also note that ERCOT is interested
in looking at humidity as well.
And to use the data to be able to come up
with a probability of occurrence
for any of these given parameters,
as well as a combination of those parameters,
so that we can then cobble together this notion
of kind of being prepared to operate
through the 95th percentile of weather events.
And the reason why we chose 95% here is for a few reasons.
First, it kind of lines up nicely
with some statistical probabilities.
I think this is the second standard deviation
and in a normally distributed curve.
I took just enough statistics in graduate school
to be dangerous.
So somebody will kick me from behind if I got that wrong.
And also because we know that there are generation operators
out there who have already taken steps
to prepare their plants for extreme weather.
There are others who have done more,
and there are some who've done less.
And we don't quite know exactly what level
that they're at right now.
And so we wanted to set a floor
that everybody would have to meet.
Everybody would have to be prepared to operate
through these different kinds of conditions.
And so this is just your basic standard of operating
as a good utility operator.
This is what we expect of you when you come into the market,
this is what a lot of people have already been doing.
And if you haven't been doing,
you gotta catch up to the rest of the pack.
And then beyond that,
if we want to look for higher levels of reliability,
we wanted to incentivize folks to go after that,
by thinking about different kinds of products or services
that we might be able to procure through ERCOT
that brings on or captures more capacity
that's been prepared to operate through more extreme events.
And so we used this concept of the enhanced
reliability standard at the 98th percentile
as this signal to the market,
that to go above and beyond
what we would expect you to do as a good utility operator,
you might be able to receive some cost recovery
for the efforts that you've taken to get there.
And we've been working with commercial operations folks
at ERCOT to think about different
kinds of services or products
that might be designed using that as a backbone
for qualification.
I also would note that hopefully
that might fit in interestingly into y'all's conversations
about market redesign.
And we could imagine a scenario
in which this enhanced reliability standard
gets pulled out of this world altogether.
And it saved for your conversations on market redesign
if that makes most sense.
And the final reliability standard that we have imagined is,
the 99 point seventh percentile of events,
and this is the third standard deviation as I understand it.
And so it's really the extreme of the extreme events.
And we had imagined using this for the box start
service units.
Those units which we need to be able to start up
in the worst of scenarios so that we can restore our grid
as quickly as we can.
There's some issues with the way that we've laid it out.
There's an entire black start plan
that starts with an individual unit
and then kind of builds together,
cobbles together an island of many units
and then kind of grows back to the entire grid.
And several commenters have said,
it's all fine and good to get the individual
black start units weatherized up to this,
or prepared to operate up to this 99.7 percentile.
But what about the next units in the crank path?
And so if you're not going to address those,
and you're not really guaranteeing any ability
for the grid to be restorative,
if it goes into blackout.
And that's a valid point, that's a fair point.
And so that might be an area that we wanna look at.
We also would note that it would mean
that there are several more units
that are available for real-time energy operations,
that would be weatherized and prepared to operate
in the most extreme circumstances.
So incrementally, we find that there's value in it.
And it's possible that we might think about
setting the standard out now for the individual
black start units and then coming back later
to think about the entire black start service plan
and how to prepare that path?
So before I go on with anything else,
I wanted to take a moment and see if y'all had any thoughts
or questions or comments about this,
you know, kind of the overall scope and concept
that we've laid out.
And more specifically, if you have any opinions
about the weather study that we've proposed,
either based on what you've read or heard today,
or other thoughts.
Chairman: Questions or comments.
-: Yeah, Bark.
So I just have some questions about the weather study
and I guess just background facts and maybe a status update.
-: Yes, please.
-: So it sounds like ERCOT is in the process of developing
that study right now.
-: Yes.
-: In consultation with the state climatologist.
-: Yes.
-: Are there any other additional weather resources
that they're using for the study?
-: So we actually, Albert has received data
from an organization called the American Society
of Heating Refrigeration and Air Conditioning Engineers,
ASHRAE.
I think I got all those letters right.
And it's actually proven to be a pretty robust set of data
for the last 30 years.
If I understand correctly and remember our conversations
right there,
they're over a hundred different points
throughout the entire state from which they collect data
and they've been doing it meticulously.
And so the quality of the data is good.
And the reliability of the data,
I think somebody smarter than me would tell you
if it's good.
The sole problem with it is that it's only about 30 years
worth of data.
And so we're not really gonna be capturing
some of the more extreme events
that the state has experienced,
certainly dating back to 1895, but others as well.
-: Okay, so I'm gonna take one step back actually,
as I was reading through the discussion draft,
I was sort of just kind of tying it all together
in terms of meeting the statutory deadline
to have the standards in place,
and then the timing of the study.
Can you provide me a little bit of background
as to why the weather studies being completed
after the standards are developed or.
-: It's a little bit of a chicken and an egg situation.
I agree with you.
And part of it is just we set that date
based on our understanding of the timeline
in which ERCOT felt it could complete this work.
And we saw a lot of commentary from market participants
that it just doesn't make sense to approve a rule
that's got a particular percentiles identified
before the other study has been completed.
And I think those are valid concerns.
-: So the statute that SB three says,
the Commission shall develop a study in consultation
with state climatologists.
So at some point I suspect before I got here,
there was a decision made for ERCOT to conduct this study.
Was that a staff level decision,
a Commission level decision?
-: It was a staff decision,
because this is not intended to be disrespectful
to John at all.
His office does amazing work.
It's not done through the lens
of the electric power utility industry.
And so thinking about what weather data means
to generation resource or to a transmission substation,
there is a particular filter
that we wanna be able to put on to that weather data
and to that analysis to say,
now, this is actually a more meaningful way
to be thinking about that data.
-: Did staff ever consider hiring a third-party independent
sort of expert on running the study?
I know ERCOT has a lot on its plate right now,
and there certain folks out there have different ideas
about weather forecasting done by ERCOT.
Was there any thought about hire an independent,
you know, the Commission since the Commission
is required to do so under SB three,
the Commission hiring an independent expert
to work with the state climatologist
and a variety of other weather resources,
maybe some of the ones that might've been alluded
to that have high quality data that are paid for?
-: To be quite honest,
we were concerned that the process for going through
a request for proposals was gonna take us too long
to be able to meet the six months deadline.
-: Okay, it's a question of making sure
you get that study done in time or,
but it's being done after. (chuckles)
-: I appreciate your point.
Okay, I'll let you all ask questions.
-: Yeah, I think another way of putting
ourselves last statement of the resource constraints
is that the two plus month RFP process for an outside vendor
would have taken up 30 a third of the time
to complete the entire effort,
which is not ideal.
And I can see that being a tough choice
in an uncertain environment with not a lot of great options.
-: Sure.
-: A thing that we've been thinking about
over the last two weeks
or so as we've been in communication with ERCOT
about their weather study process,
is there something that we can put into the rule now
that will address kind of our near term immediate concerns
and allow the weather study to play out,
and then allow that to inform
what this 95th percentile might mean?
And something that that we've kicked around is,
could we come up with some reasonable language
that says generator X, figure out what broke
in URI or figure out what broke in 2011,
make sure that you've got a plan to fix it,
make sure you fixed it by December 1st
or something like that.
Or an alternative could be identify
all of your cold weather critical components
to steal next language and make sure
that you've wrapped it in insulation,
that you've proactively tested all of your heat tracing.
You've put Hoffman boxes up
around all of your critical sensors,
and guarantee certified that you've done
that to the Commission now as a stop gap measure
so that we can complete the weather study
and move on to something that's a little bit
more thoughtful, if that's a reasonable word.
-: Would that establish or fulfill the statutory deadline?
-: I think depending on y'all's direction,
I think we could probably put
that into the proposal for publication,
which we want to put before you on August 28th
for your consideration.
-: Yeah, because throughout the discussion draft,
in terms of compliance for the generation companies
and TSPs it all refers back to the weather study.
-: Sure, it does.
-: And so it sounds like there could be an approach
to address the statutory deadline in a phased manner
to maybe create some kind of a robust baseline of standards
that's driven by information that the generators provide us
as to what they're doing and some maybe additional measures.
And then once we get the weather study,
then decide based on that study,
what additional measures might be needed?
-: I think that's right.
-: Well, I like the concept of a first pass
being a request to generators to identify problems
from the February event,
demonstrate to the Commission
and demonstrate to the Commission,
what they've done to address those acute problems
before we go into the next winter.
I think that's something that's important
that needs to be addressed.
And if nothing else to ensure
that we have some measurable and substantial degree
of improvement and increase in resiliency
as Texas goes into this upcoming winter.
That being said, I'm not quite sure how to resolve
the chicken and egg problem as you put it,
while still fulfilling the legislature's clear desire
to have weatherization standards in place
by the end of the year.
So that's something that may need
to be an ongoing conversation with staff.
I certainly don't wanna in any way,
indicate to the legislature that we're shortchanging
or working around the deadlines they've given us.
(clears throat)
-: Is it a way to work in a near term?
Again, it's all about the range of risk
that we're building in, right?
So 95th percentile,
is that low?
It's a low bar that we hope that everyone
will be able to cross.
But is there a way to look at near term?
And again, when do we expect to have the study complete
by ERCOT?
-: So our last draft has the study being completed
by the end of January.
And I have not had an opportunity to check in with Chris
this week to figure out exactly what his timeline
is for completing his data build out.
-: It's by the skin of our teeth.
-: Yes, sir.
-: So Barksdale and I know ERCOT has a lot on their plate,
but can you shed a little bit of light
on why it's taking months to develop the weather study,
several months?
-: So it would probably be better for ERCOT
to answer that question.
I can tell you just from what we've heard
is that it's been difficult.
It's a tremendous amount of data that they're working with.
He's trying to build out an hourly dataset
for a hundred plus years,
whereas some of the data that you were seeing from John
is kind of on an annual basis,
but Chris is trying to do is on an 8,760 data
points per year basis,
because that really gets us to this idea
of what we would expect from a generation operator
is kind of on an hour-by-hour basis,
not on a day-by-day basis or a year-by-year basis.
And so it's tens of thousands of data points
and he has to go and find the holes
and figure out how to supplement it and if it's quality,
but, you know.
-: So.
-: Go ahead.
-: Okay.
So one observation that a lot of stakeholders raised
in the project was the fact that it doesn't appear
like they have a lot of visibility into the weather study,
and they're gonna be expected to comply with standards
that are based on the weatherization study.
Is there a way to at least file in the project,
like a scoping document as to what's being looked at,
and a draft study and a final study?
I just feel like for purposes of transparency,
if ERCOT is conducting a very robust weather forecast study,
then we can at least shed a little bit of light
on a little bit more information on the study
as it's being finalized.
-: Subject to check with ERCOT.
I don't see any problem with providing
either the final dataset
or the parameters under which Chris
is trying to collect the data.
It seems reasonable to me.
-: What about this?
Something to consider for all of us to sort of chew on.
And Jimmy, with your experience from recently,
is there an industry best practice,
we heard from Mr. Gates that again Calpine
was hardening to a 2011 standard,
had been prior to the URI event.
That was something that Calpine Corporate
had determined was the highest risk
or a high risk event that they were trying to mitigate.
And so is there (clears throat) a way to flag
from stakeholders?
What is a commonly accepted metric as of right now
that we can in shrine as a near term benchmark
that everyone can meet by December 31st,
so that at least we have a standard in place
unless we're bringing up anyone
who may be a laggard in this category,
so that they, again, going into February,
the anniversary of the event,
we at least have a bar that is set.
And then subject to the final weatherization study
performed by ERCOT, we can then reopen the rule
and start doing our technical refinements.
Is that something that might be achievable?
-: Have fulfilled the statutory deadline in broader strokes?
-: That's right.
Well, again, it's not gonna be the perfect
and we're gonna work toward the perfect,
but it'll provide an industry-wide ERCOT standard
that we will bring everybody up to.
That is achievable.
It should be--
-: Based on the most recent event.
-: Not necessarily URI,
because URI by all accounts is an outlier,
even by the state climatologists.
But I'm talking about is 2011 that standard,
because I think what we found
is that some may have been a laggard
even by the 2011 standard,
but let's put a stake in the sand start, crawl, walk, run,
bringing everybody up to that stake,
and then once our final refinements are processed,
pending ERCOT study we reopened the rule
and start moving in the direction of the 95th percentile.
-: Interesting concept.
You might be able to merge something
like that with the,
I guess we can speed up the rulemaking
or we slowe down the rulemaking
or speed up the weather study, right?
A couple of variables.
Would it be possible if we're working
with 8,700 data points per year over a hundred years
get you close to a 100,000 data points in a big database.
-: I'm looking at paying face right now.
(laughs)
-: Could you?
-: No, go on.
-: You mentioned annual versus hourly.
Could you start with the annual basis,
broad strokes of the weather study,
use that to make sure we have robust rules
part of the legislature's direction.
We have the framework,
we have the framework of the rules
with a broad weather standard
that can then be fine tuned
as we get a more robust weather study product.
And with the notion being we want the broad pieces,
the broad philosophic pieces to be in place,
we want the framework to be in place,
but we don't want the lack of data
or the timeframe required to gather data
to be the tail that wags the dog
of the of the weather study
that drives the weatherization.
I think that kind of similar
with what you're talking about with the...
-: Definitely.
-: Fazed weather steady approach (indistinct).
-: So I need to step back being the new guy here
just about all of the data points.
Is this gonna be on a per generator basis or on a,
I mean coz obviously we've got lots of generators or...
So tell me what that basis is?
Obviously, if we're getting data points for 8760,
is it for each component,
each generator or each component of the system or?
-: The data that Chris is collecting is on an ERCOT
weather zone basis.
-: Weather zone basis.
Okay.
-: And so the standard would be for the generator
to prepare their assets to operate in that weather zones,
95th percentile range.
And if that means that there are various components
that need more or less preparations,
then that's up to them to figure that out.
-: And the weather zones are determined how?
-: They were originally set by in the ERCOT protocols
back when we introduced restructuring.
-: Got it.
-: So just to kind of put some things out there,
to think about and maybe questions in the middle of that.
So it sounds like potentially a consideration
of a phased approach to weatherization,
the first phase being built on a combination of information
being provided to us per our request from the generators,
what they're doing to prepare for winter 22,
based on 21, maybe a percentile that Will mentioned,
something in there to add even more of a baseline,
perhaps some information from the draft FERC,
cold weather preparedness.
So just kind of a combination of having a good
firm baseline there of to create some phase one
robust weatherization standards allow ERCOT the time
to finish their weatherization study
and would that time to allow them to finish
that weatherization study,
shed more light on the weather study
so that the stakeholder community can know
it's being looked at.
And maybe if we have enough time
maybe they can provide suggestions
on what other weather resources should be looked at?
We have a little bit of extra time.
So that way it is a robust weather study
that we later returned to for phase two compliance
or the phase two standards that will build upon
the phase one standards.
And then we can use the information
that the generators provided us for our direction
to maybe come up with weather standards
that are more specifically tied to generation units
based on age, type, design,
a little bit more fine tune,
because I'm wondering if just saying a compliance standard,
if you have 600 megawatts is gonna take into account
all the unique characteristics of a generation fleet.
Maybe we can come up with a little bit more of a,
on the phase two standards,
more robust weather standards that are specifically tailored
to certain types of like old gas, steam units.
New combined cycle or newer wind turbines
as opposed to tied to overall amount of megawatts.
-: Are you suggesting the phase two regulations
would include technical specifications
for types of generators?
-: Performance standards?
-: They would be standards that would be a little bit more
delineated by category as opposed to like,
if you have 650 megawatts,
then you must comply with this by X date,
it would be if you have an old steam,
this is just something to consider.
(chuckles)
For instance, gas steam units, old gas steam units,
whatever timeline that is.
These are some of the measures
we got from the generators themselves
as to how they're protecting them.
Let's use that as a baseline,
plus the weather study and actual performance
from the winter to see if that is the right standard
to have for phase two more robust standards.
-: So if I could respond to that for just a moment,
one of the reasons why we have chosen
not to present different standards
for different kinds of units is because,
once that electron is produced and has left the plant,
it is equally valuable to all of their electrons.
So to the public,
I understand that there are different costs,
different requirements for the age of the plant,
for the type of plant, for the location of the plant,
but at the end of the day,
what the public cares about is the electron
that gets produced from it.
-: Absolutely.
But I will add that we've heard a lot of concerns
about old gas units being rocked all summer long.
And if they have the generation company
has to spend more money on the units
to bring them up to a standard
that just fits in with all other units,
there could be unintended consequences
of not having electrons on the grid from those units.
-: And that's why we were proposing
maybe a little bit of a lower standard.
If we wanted to cover all events including URI,
we would probably have required everybody
to go for that 99th percentile event.
And so by setting that just a little bit lower,
we're trying to encourage folks
to keep their assets in the market,
but still if they're gonna to be on the market,
take steps to be able to make sure
that that electron gets out to the public.
-: And I think you also have to think of it,
not just old units, but the black start units.
The black start units and prioritization
of having to comply with the standards.
I mean, I think there's been a lot of discussion
as to how they perform during the winter
and when should they be in compliance,
should they be first out of the gate
in terms of compliance and having their own set
of perhaps standards to meet as you have already done so,
I think to some degree in the percentile,
but anyway, there just some things to think about,
because I think that, you know,
I don't know that lumping over 650 megawatts into one bucket
is going to address all the different
sort of design elements
and just really take into consideration
the characteristics of the types of plants we have,
and the realities of weatherization
for those types of plants.
That's all I'm gonna (indistinct).
-: Fair enough, and that's a delicate balance
that needs careful consideration
between certainly wanting to make sure
that assets currently in the ERCOT market
remain in the market.
But making sure that like Barksdale said,
if those assets are going to be in the market,
we need some standard of reliability.
And that's one of the questions I've got of,
you know, is there a seasonality difference, right?
Like if and I don't know the answer to this,
but if there's, you know,
is there a different universe of generators
that we wanna rely on in the winter
versus what might be available in the summer?
I mean, but again, at the end of the day,
that goes into market design and reliability.
We all know and it has been very clear both from the public,
the Governor and the legislature
that we're liability is what we are driving towards.
And so do you at any point,
do we want a unit in the marketplace
that has uncertain levels of reliability
even if you put it in some sort of summer
only classification.
That's a careful, careful balance.
-: I definitely agree with your seasonality consideration.
I think that obviously there's different
weatherization standards there,
that needed to be taken into consideration.
I think the two drivers to tell it, right?
But you do something on one end, you could impact.
So it's kind of all interrelated.
It's just something to think about.
-: Very good.
Very good point.
-: I was gonna say, all of these plants
are mechanical beasts,
and a lot of times they have things that go wrong with them.
And I think some of it has to do when they offer
their energy into the market.
You know, so most of these plant managers
get paid upon availability of their unit.
We want them available
when they say they're gonna be available.
And that's kind of where in ERCOT,
if you don't produce
when you're an available dispatchable plant,
you know, is there a consequence there or not?
But I think the one question that I had,
was to other states have anything like this?
Have you talked to folks at NARUC
or any other states that maybe there are different
categories of weatherization rules?
Have you looked at those?
-: We have inquired both with MISO and SPP
and to the best of my memory,
neither of them have anything as specific
as what we have proposed here.
-: Right.
-: They're all around the planning requirements
that currently exist in the NERC rules,
as well as what will presumably
become the newest standard once FERC approves it.
-: Right.
But nothing in the market rules for,
well, I guess by nature of the market rules,
there's definitely something in there.
-: In terms of the market rules,
it's gonna be very different
because many of them have capacity markets
which pay generators to have their units
available all year long.
And so there's just a fundamentally different
financial incentive there.
-: If I could just throw out two quick things in response
to some of the conversation I just heard.
First, one of the things
that we're trying to be mindful about is that,
we've been told that the bulk of the costs
for preparing a plant or transmission substation
is really the labor.
The actual materials itself are negligible
in terms of the cost structure of this initiative.
And so we've been trying to think about a way
to minimize the number of times an operator
has to go out and do something different to their plant.
That may not be possible,
but it's a consideration that we've been hearing.
And it is something I wouldn't say foremost in our mind,
but it's up there,
especially in terms of early unit retirement.
So trying to signal to the market
where we're going with enough clarity,
so that for those enterprising operators
who are already doing things today,
they can anticipate where we're going to be tomorrow.
So that's a great outcome for everybody.
If we have to do this in multiple steps,
just because of the nature of the complexity of everything
that we're trying to do.
So be it, and we'll tackle that challenge as we need to.
-: I liked your idea that if you had said it this way,
but this is kind of the way I characterize it is,
so looking at ERCOT black start plan across the state,
I don't know if it's divided up regionally or whatever,
but maybe like we're looking at that reverse,
or the first plant that they need to get up
and running may need the highest standard.
So and a lot of that is kind of within the plan,
but as you get down the curve of plants
and you have fewer and fewer plants left,
you want them to be there when all the others are gone.
And I don't know, just a thought,
you know if maybe blacks the black start plan
is a data point to look at those plants
that are most important to the state
to bring up grid backup that failed.
-: That's exactly what motivated our decision
to require those units that have contracted
for providing black start service to be the most prepared.
-: That's great.
-: What is the current requirement for contracted
black start units today?
-: For weather preparation?
-: Yes.
-: To the best of my knowledge, there is none.
There's I gotta have thumbs up from Woody's.
(laughs)
So this actually kind of leads into my second point,
is that Commissioner McAdams I've heard you reference
a couple of times that the 2011 standards.
And I understand your point to mean, you know,
what was your experience generation operator
during 2011 and go and resolve those problems
to use the word standard.
I just wanna make sure that it's clear to the public,
that we have no standards.
We have no regulations based on 2011, 1989, 1983, 1895.
There is no minimum regulation that either the legislature
or the state have imposed on the industry.
-: In place today.
-: Yeah, no, that's right.
Anything in the public interest
is going to be a positive development,
because at least that establishes that benchmark
that we grow from,
and that you refine your 95th percentile forward from.
But what I was saying is you started off slow,
you don't bring everybody up to altitude fast,
otherwise you're going to have some people pass out
or retire.
(laughs)
And so again, if we can't get the most accurate picture
on weather data until January,
if we find some, anything, you know,
and just establish the benchmark
and then make sure everybody goes through their facilities
and a test we got this,
it's gonna be better than what we faced in URI.
And that sort of reinforces public confidence in the system.
-: A hundred percent agree with you, sir.
-: And there's two things to note as a supplement
to Commissioner McAdam's point.
When our ERCOT goes to inspect before the winter,
they'll have that direction for phase one,
which will help them do a more targeted focus
on what they need to be looking for.
So they have their plan.
And then also phase one is going to have enforcement tie
to it too.
So.
-: Yes.
Commissioner Cobos is exactly right.
In my opinion.
-: Yeah.
-: So you would suggest getting the NERC standards
established after or I guess depending on which version,
if you look at the timeline from the presentation earlier.
The latest greatest version is in process right now
waiting for approval.
So the staggered approach would be something along the lines
of just copy and paste those for the first phase.
That's now the standard required for implementation
by which point.
-: I would ask Barksdale,
is that somewhat of an apples to apples?
I mean, we kind of get this in the same universe
of metrics here.
So what do you think?
-: If I could provide my advice here,
it would be to take just a half step forward
from what has been proposed to FERC,
which is a planning standard
and it's important and it needs to be done.
-: Yeah.
-: But I would recommend that we take a half step forward
in terms of preparations based on those plants.
And...
-: That plants should for the generators?
-: Excuse me, ma'am.
-: So the information we get from the generators,
let's just say the Commission request
that the generators provide us their plants
to be ready for the winter.
We take that information,
take some of the information from the FERC,
NERC draft standards,
and then use that and maybe a percentile
that will suggested and use that as a combined
set of information to set that phase one standard.
-: I could imagine stealing from the NERC proposed standard,
this concept of critical cold weather component,
cold weather critical component,
I think is how it's written.
And saying, identify those that failed in 2021 and in 2011,
make a plan to fix those and execute that plan.
So actually prepare your facility.
Don't just tell me that you've identified the problem,
but do something about it by a date certain
going into this winter.
-: So I'm not completely versed
with what's in those draft standards,
but I would suspect that maybe you can cherry pick
some elements of it.
And also it's based on the 2018 event, right?
In the south central region.
So there's that piece.
You can cherry pick pieces
that would be good to carry forward for phase one,
you know, standard implementation.
But I would say we would wanna know
what they're planning to do based on 2021 not 2011.
-: I agree with you that we would like to know
what they're doing based on 2021.
I would like to also add 2011,
because of it's at your direction,
but I think having the generator think about
both of those events because they were recent
and presented different opportunities for improvement,
maybe we can learn from both of them.
-: What about the next extreme event?
I mean, I almost think that we need to think
at some point in time holistically
that is there an event that's gonna be worse
than what happened in February,
at least in terms of temperature or ice or whatever.
And we have a,
NERC included does a great job of doing things just in time.
We do it just to solve that problem
that just happened yesterday,
but they didn't say, well, what's gonna happen tomorrow?
And you know I know NERC standards, not all of them,
but a lot of them are about having a plan.
It's not prescriptive.
-: That's right.
-: The NERC that's up to the operator or the owner,
but and I don't think that's what the legislature wanted.
They want us to have something that's prescriptive.
That's like, you guys have to do X, Y, and Z by this time.
-: So I'd like to speak to a little bit of that.
And I think we all watched it and it was informative.
The legislature found fault in that 2011 happened,
there were reports written and nobody went out and checked.
And so there was never that benchmark put down
that people were held to account to.
And there was a lot of discussion,
a lot of legislative intent read in on that topic.
And so anything we do if 2011 is that,
we will have already moved past
where this Commission was in 2011 or 2012 post that event.
So if we establish any type of metric
that takes that into account and they attest to it,
and then we hold them to account this year coming,
or this next year coming in January and February,
we will have established,
we will have moved forward on the legislature's intent.
-: And operationally, I'm gonna offer this as a suggestion,
but I suspect that if the cascading effect
that we saw in February would have been minimized
or certainly less dramatic if the first,
second and third units that tripped had higher standards
or that if they could, if not all of the first
like say 10 units tripped and it's only.
-: Well, yeah, or only four of them tripped,
instead of all 10,
the cascading effect would have been less severe
to the point being even if you said,
crawl, walk, run.
Even if we'd gotten to the crawling stage
that could have mitigated a lot of the cascading.
It wouldn't have been perfect,
but it could have...
-: We've even rolling out or just.
-: Hard to predict in retrospect, impossible.
-: You know, and it's hard for those plants,
the operators of those plants,
because some of the problems were not their problems
within their plant.
If they were a fuel problem or they were a water problem
or something else something
or I know that a few substations tripped,
they still may have met the burden of their responsibility
yet their plant is still not available to the people ERCOT.
-: Well, and to your point, look,
it was a confluence of events that created
a cascading failure in the system.
And it was like four different events
that were going on concurrently.
All we gotta do is break up the cycle,
the chain of events on one of those.
And we stand a good shot of ensuring the reliability
of the system.
And that's kind of to our point setting
that benchmark now even low,
so everybody can start coming up to it,
and then enhance it and move forward.
-: And I will add in I think to spin off
of what Commissioner McAdams is saying
and go back to your market design concept
and to kind of address your point, Jimmy,
(indistinct).
Basically, yes, we can weatherize,
there can be gas supply issues,
but through our market design efforts
that we're gonna be tackling this month,
there are ancillary services
that we're gonna have to put in place per SB three,
that for on-site fuel storage and mechanisms
that do feel capability that will hopefully help mitigate
those issues going forward from a market design standpoint.
So hopefully.
-: So I will also just highlight that the NERC standards,
the NERC process timeline we saw earlier
includes from the time FARC approves the proposed standards
an 18 month implementation timeline.
-: You're right.
-: So we also need to think about them.
-: To think about what that means is really
that a generator owner is probably
gonna have to have a plan.
-: Within 18 months.
-: That's still not physically enhancing the resilience?
-: Correct.
So the way those standards are written,
but maybe if they get integrated
into the planning standards,
they might get there quicker.
I mean, I haven't seen the NERC rules yet,
so I'll look at those and... -: TBD.
-: Yeah.
-: So let me ask it's if what I'm hearing is a phase one
broad strokes, crawl walk run
would be for simplicity of discussion,
just say, adopting the 2011 planning
and preparedness with enforcement on the back end,
inspection enforcement on the back end.
Do that in some timeframe
so that changes could be made on Texas assets
by December 1st of this year.
Is that... <v ->First or 31st?
-: First.
-: Oh okay!
-: So I think that what y'all are triangulating around or?
-: I would add in there,
the piece that I think you've alluded to Will,
and I think you have to determine like,
so the piece about the companies telling us
what they're planning to do,
and fall into attestation to it as well.
-: Sure.
But just for simplicity of discussions,
I copy and paste 2011 standards for implementation
by December 1st, 2021 as the phase one.
It seems to be the basic version
of what we're talking about here is that fair.
It just as a discussion topic.
-: Thank you.
-: Can you from the staff that's been in the weeds
on this for months,
can you give us just lay out some pros and cons
of that approach?
One that I can think of would be the very good point
Lori brought up earlier is a lot of generators
could look at that additional cost and say,
we're gonna retire this asset
rather than go through the first
of what will probably multiple workforce hirings,
et cetera, et cetera.
But could you just go through quick reaction pros and cons
on that theoretical or hypothetical game plan?
So I think in terms of the preparations
and the actual things that the generators
would be required to do,
I think there are a lot of pros.
I think the risks foremost is as you know,
early unit retirement as you've mentioned.
Another risk is thinking about what does an inspection
schedule look like?
We're now at August 12th,
this rule if we strip it down
to just what you've laid out, Chairman,
maybe we could move more quickly
in terms of getting it adopted,
but then we're talking about maybe 10 weeks,
eight weeks from (indistinct).
Chairman: For physical implementation.
Barksdale: So.
Chairman: Not just plants.
-: I, you know--
Jimmy: Does that mean not have already started.
(indistinct)
Participant: We have good evidence that they haven't.
Chairman: Anecdotally--
(indistinct)
Lori: Yeah.
-: Sorry, I didn't mean to talk over you.
I think anecdotally, I've heard similar things
that folks have already taken a lot of those steps
themselves.
And maybe it's helping bring up
kind of the trailing end of the fleet.
So I think we would just wanna be thoughtful about
what does inspection mean?
And how do we do something that's meaningful
to ensure compliance and targeted so that it's feasible?
-: Right.
And more?
You have some pros and cons Woody?
(laughs)
Have you tried to mics over there for you.
If you have thoughts, please share.
We'd rather rather learn the pros and cons.
We'll learn the cons sooner or later,
we'd rather hear him hear them sooner.
-: Well, one thing to keep in mind
when you talk about checking the weatherization,
I mean, our plant is not weatherized in August
for January operations.
And so that weatherization actual putting up the tarps
or putting the heat tracing on and that kinda thing,
none of that stuff takes place at a window of time
before winter occurs, winter weather occurs.
And so there's a limited window to check
that weatherization.
So if you're checking,
they give you a plan and say,
this is what we were gonna do to weatherize our plant.
We can't check that plan until it's been done.
And so you've got this November, December,
very short window of time to actually go out
and do those jugs for a large number of plants.
That has to be factored into this whole thing as well.
-: Do you think something like an attestation would work
than either... I don't know who,
but I don't know if it's a plant manager
or somebody within the company attest
that they have completed their plan to us.
It's not inspection, I get that.
But it may not meet the level that we want ultimately,
but getting them to attest similar to a NERC standard,
you think that would be serve as a component
that we or data point that would give you all information,
us information that they're actually doing
what they say they're gonna do?
-: I think you're good.
Yes.
-: Well, it'd be a bit of both.
I mean, it's a manpower issue.
You're gonna be standing up your inspection system
over the next six months anyway,
we're talking about ERCOT structure and funding right now
in the coming months where you're gonna be either doing
this internal or through an external contractor,
but you're gonna be prioritizing inspections depending
on your view of system needs.
So you're already gonna start a cycle of inspections
and then that combined with an attestation safeguard
provides us a mechanism for accountability.
And if everybody's not there in February
and we have a close shave,
and there's gonna be accountability,
and that's not a negative thing, that's life.
I mean, does that work that level of redundancy?
-: I think so.
I mean, what our plans were for this winter
was something we were going to do this called spot checks
or not because of the spot checks for any plant
that had problems last winter during URI.
That was the bull we're gearing up for this winter
is to do that kind of spot check again.
And so it would be the same kind of process.
They would say, here's our plan.
Here's what we're planning on doing to weatherize our plant.
And we would go out and verify
they had completed their plan.
And there may be a hundred things in the plan,
or there may be five things in the plan.
We'll check whether it's five or a hundred, I mean,
without a standard, then you're checking the plan,
-: Right.
-: This might be a broader philosophical question,
but how do we ensure that the plan proposed
to meet the 90th and 95th, 98% probability?
How do we confirm that that is in fact a valid
and effective plan for that asset in that location?
That's a question for both of you.
Well, the draft rule thinks about having an engineer analyze
both the plant design and the plan that is presented
to prepare that plant.
And based on the design criteria,
provide some level of certification
that yes, these, you know, the plan.
-: This makes sense it's more than a tarp
over pollical would.
-: Correct.
-: So it's their view versus our engineer's view
to be discussed.
-: Correct.
-: So what do you, in terms of the inspection plan
that you currently have right now,
I know that right now the ERCOT board
is going to be considering funding for potentially hiring
a contractor to help with the inspections.
'Cause I do think that there probably needs
to be a more robust inspection process before the winter,
whenever that window is,
that goes above it a little bit above and beyond
inspecting plants that had issues in 2021,
although a lot of them did.
So, I mean, there's gonna be,
I think by its very own I guess result
would require more robust inspections,
but so you're applying to this anyway.
So in terms of having a phase one standard baseline
to comply with the statute and attestations
from the generation companies saying,
we're gonna do X,
that gives you sort of a plan or a focus
on what you're going to go inspect.
I mean, nothing's really changing,
you're just getting more guidance on what to look for,
and maybe a little bit more.
It's kinda what I'm thinking.
-: If I may Commissioner,
I think what ERCOT would be gaining from this is,
regulatory authority.
And right now generators have to provide an attestation
that they've thought about preparing their plants.
And that was something that was adopted
through the protocols back after the 2011 event.
But there's no enforcement authority behind that.
-: So this time there would be enforcement authority.
And I think we're gonna need
a whole lot more robust information,
because back in 2011 when the event happened
and there was some weatherization evaluation done,
that was not enough for the public.
And there was a lot of criticism
of what was done back then following the February, 2011,
I don't wanna end up there.
We need more than just, oh, attestations.
We need like a detailed plan of what they're planning to do,
and maybe a little bit more,
because I don't want as regulators for us
to look like we didn't do enough on this phase one.
And did the bare minimum and be subjected to criticism
for not taking enough action
like what happened after February, 2011.
-: Well, I'm less worried about the criticism
than I am about the results in the next winter event,
but it's a careful balance between (indistinct)
and our coverage and going too far too fast.
Like you pointed out before we have robust weather study
before we have all of the information we need
to make a much more granular precise set of rules.
But if we're gonna stagger the implementation,
I think the concept you all have been exploring
is starting with exactly that baby steps,
but more than we've got now,
but not all the way to the most robust version possible,
'cause we don't have enough information.
Right?
-: Right.
-: So.
-: Yeah, yeah.
-: And to be fair.
-: You did to your point,
I think that's why 2011 is that great watermark.
We had a report on it, NERC had a report on it,
everybody under the sun from the legislature to the industry
knew what was wrong with individual facilities.
And if they haven't come up to that standard since 2011,
10 years later, a decade to get there.
And then we now have,
and that poses are the letter of the law.
We have something that they are held accountable to,
and then the enforcement standard.
So that's gonna be a sea change in six months
and at least we have that available.
-: And to be fair I mean, to your point,
it's not just about criticism,
it's about ensuring reliability.
And the fact is those steps were not taken.
-: Right.
-: And so we had a reliability problem.
-: Exactly.
-: But we need to be cognizant of the fact
that those facts happen in the background.
-: Yeah.
-: We'll point it out as well.
-: So perhaps we can do this,
perhaps we can, as we think about crafting
this new language.
We think about what broke during URI.
We look at the quanta report
that was released in the aftermath of 2011,
pull out some specific recommendations
that were included in there,
and think about what broke during 2011 event
and asked the generators to come up with a plan
that addresses each of those things,
submit them presumably to ERCOT with an attestation
that they're gonna take care of these things,
or they have taken care of these things.
And then we can use that on the backend
if there are performance issues during winter next year.
And I wanna be very sensitive about performance issues
because I don't want it to come off
that we're trying to require generators
to produce electrons a hundred percent of the time
and things break for despite your best efforts,
but we can still use that plan as a way
to assess performance against what they said
that they were gonna do.
-: Again, start with a baseline for an accelerated
or at least consider we can consider it the,
I guess, two versions.
Phase one early implementation,
acute problems identified in February
plus core principles of the 2011 standards
to be plans plus at attestation of implementation of plans
with spot slash audit with enforcement
and penalty power behind it.
(indistinct) is that?
-: Yes, sir.
-: Broadly tracking?
-: Yes.
-: So like I would almost call that a separate exercise
from what this is phase two.
-: Yes.
-: That would be something to be can developed,
considered and ruled on quickly
if we want it to make a difference for this winter.
Any other?
-: I'm gonna phone a friend and ask my director
of engineering to come up because he's got something
that he wants to make sure that we get out there.
-: This audience is getting to be a dangerous place to sit.
(laughs)
-: Albert Esser, Director engineering.
Just a clarification,
when you talk about 2011 standards,
what exactly do you mean?
Is that the temperatures, the duration, the precipitation,
or is it what was found in the Quanto report
which has not been fixed?
You know, just thought we'd get a clear understanding
what you mean by standards.
-: Well, since the Quanto report was issued,
it identified deficiencies across the board
within the types of units.
And then that was highlighted by the legislature
as why hasn't this been fixed?
-: Okay.
-: And then they passed the bill telling us,
so yeah, I'd say, that's why you're there.
-: So the quanto is what we look at as a baseline
and try to implement--
-: Those senators were quite adamant.
That was.
-: That was the question.
Thank you.
-: Any other?
-: Barksdale, I would encourage you to,
when you're thinking about those 2011 standards
to also look at the performance
that occurred in 2014 and 2018,
because what we saw was an application of those standards.
We saw people make progress,
weatherizing their plants based on what happened in 2011,
we saw improved performance in 2014 and 2018
in conditions that were comparable to 2011.
And then we saw 2021 happen.
And even though we have survived 2014 and 2018,
2021 we saw what happened,
severe consequences of that colder weather.
And so I think it's a hard thing
to have to take into account here,
but we did see improvement from 2011.
And I think I've shared some data with you guys in the past
on the number of generator outages
and how they decreased in 2014 and 2018
during comparable weather.
And so it's just data points
that ought to be taken into consideration.
-: Absolutely.
-: And I'd agree with that.
And I think it did happen.
It's just we didn't have anything on paper after that.
And once something is on paper that has the force of law,
(clicks) it's a little bit different animal, so.
-: Well, what is it fair to say?
For the improvement that you're speaking
or referencing definitely occurred we've seen the data.
Is it fair to say it wasn't universal across the fleet?
-: I think that's fair to say, yeah.
I think we've talked about some stragglers,
some trailers that probably did happen.
-: Okay, so there's still room for progress then.
-: Right.
-: And fortifying the fleet.
-: What about the transmission provider?
The TSPs, I guess, how would that they fit
into this phased approach?
-: That's a good question.
About five minutes ago, I was thinking in my head
that we would probably pull them out of this crawl stage.
However, I'm remembering the statute does require
standards for them by the implementation deadline
of the end of November.
And so I think I personally wanna huddle with my team
and figure out what that means?
-: Presumably that was addressed in the work done after 2011.
So there should be a reference point
or a similar baseline as generation from the 2011 event.
-: Yeah, and I would say kinda looking at 2021
too a little bit, just because I don't remember
what happened from a transmission service provider
perspective from 2011.
I mostly remember the generation impacts,
but if there was anything from 2011 and 2021
and then standard good utility practice,
you know, best practices and lessons learned.
I think maybe that could serve as a robust baseline.
And I don't know if there's anything
from the cold weather standards or anything
that could be cherry picked,
but just some kind of a similar baseline.
-: Come on up, Liz.
(laughs)
-: Yeah, I think before Liz puts me to shame
with her breadth of knowledge,
what I believe that I know from 2021 is that,
the transmission system as a whole performed very well.
There were specific components inside substations
that had some problems,
but by and large, the standards that the TSPs follow
from the National Electric Safety Code, IEEE
and some of the other ANSI based codes have served well,
but Liz will correct me.
-: Actually, I'm gonna agree with you
and then offer one other piece of information.
Liz Jones, on behalf of Oncor.
There were recommendations directed
to the transmission providers in the FERC, NERC 2011 report.
And so as you're thinking about sort of a parallel construct
for the generators and for the transmission providers,
that may be the corollary that you could use.
(clears throat)
-: What about attestation similar to what we're requiring
from the generator?
So like anything that you can,
maybe the TSP's I know you're only speaking on behalf
of Oncor,
but maybe we can also require the same from the TSPs
as to what steps they've taken from lessons
from 2021, 2011 or 2021, 2011.
-: The same framework makes sense.
-: Yeah.
-: Yes, on behalf of Oncor.
(laughs)
-: With..
-: I don't know what's back there.
(laughs)
-: Based on if you've any difference of opinion.
(laughs)
-: And thinking through all the moving pieces of this,
there's not only a cost of implementation,
there's costs of reporting and compliance.
Is that something just from y'all's perspective?
Is that something that is manageable?
-: I think generally, yes.
But I say that because as a consequence of 2011
and our other obligations,
this is what we do,
and that the bulk of our seasonal readiness
is O and M preparedness.
And you see significantly less acquisition of equipment
than perhaps Calpine had described.
-: Thank you.
Anything else for Liz?
Appreciate it.
-: Thank you.
-: All right, Barksdale,
we've got a concept regarding a phase one
accelerated implement or accelerated direction
for discussion that another meeting
or any other thoughts on pros and cons
of this staggered approach and or additional questions
you may have for clarification for staff
to look at the phase one approach?
-: I think we're clear on this crawl, walk, run idea
that you all have suggested.
I know we will continue to work on the running part
while we're working on crawling and walking,
'cause we can't do it sequentially,
we have to do it side by side.
So rest assured we will continue to work
on this weather study idea and assuming
that this is a concept that in the long run,
you all support and would like us to pursue,
then we will continue moving as quickly towards
that as possible and get you some language
on the crawl part.
As soon as we can.
-: Do we have agreement on shedding more light
on the weather study?
Maybe having the draft filed,
or, you know, I know that's something
I suggested in terms of weather studies
sort of driving the second round phase two standards.
And it's very important.
And I think there's been a lot of interest in knowing,
well, what's going into it and what's going on,
are the right resources being taken into account?
Is there a possibility to maybe shed a little bit more light
on that study in terms of maybe having the final draft
or a scoping document or something filed in the project
so stakeholders can get that visibility
and maybe offer suggestions to ERCOT in there,
something like that along those lines?
-: I'm sure we could provide for that.
The only question that I have for ERCOT
and I'll take this back to Chris Coleman
is the proprietary nature of the actual data itself.
But so before I commit him to anything
I'd like to ask him about something.
-: So basically a clarification on methodology, right?
Is what we would like to... -: Yeah.
-: We would like to...
-: Yes.
-: And theoretically, as long as he doesn't provide
the data points which is proprietary
and somebody is buying it,
but methodology that seems reasonable to explain it.
-: Well, is it methodology and or scoping timeline
and then methodology at different milestones,
depth of analysis and identification of deliverables?
-: Yeah, exactly.
-: Yeah.
-: I asked which one?
-: All of them? -: Well, all of them.
(laughs)
-: All of them, I like it all.
-: I can't sit (indistinct).
-: Well, yeah.
Well, let's see what you said
is like kind of a scoping document.
You know, what the scope is of the study?
Maybe general sources that are being used,
the methodology, deliverables,
you know, anything that we can provide
that's not confidential.
I think it'd be helpful to shed a little bit more light.
And if you all are comfortable with that,
I think that would help.
-: Okay, so you wanna ask Chris?
-: We will.
Okay, I just ask them to follow the document
on the project number with a scoping document
with timeline, methodology used,
deliverables expected and inputs.
-: Sources.
-: Even if in non-proprietary or confidential types of data,
inputs, sources of data, non-proprietary sources of data,
expected outputs, timeline,
and how that will inform the phase two final.
-: Sounds like he needs to write down his plan.
(laughs)
-: There you go.
-: Yeah.
-: Next, we'll do that.
-: But we will hold them to the performance
of that plan, sir.
-: Okay, so that's item one.
-: Yeah, and because if you visit with Chris
and he a document, maybe he can provide it to us
and see if that's all the information
that we want out of this discussion.
And if it is, he goes ahead and filed it,
and we want a little bit more information.
We can give him input and then he can follow it.
-: All right, so that's deliverable one as a result of this.
The second one we're going to while continuing to work
on the straw man now characterized
as the second and final phase of weatherization.
Timeline, TBD, depending on what we learned
in the scoping document.
In the meantime, between now and when we were considering
the PFE was the 26th?
-: 28th is what I have in my head.
-: We're now on the 28th,
a proposal for a phase one
immediate action weatherization standard
based on both regeneration and transmission
based on the 2011 the results of the core principles
of the 2011 NERC guidance and reports.
Plus a draft proposal of recording generators
to identify acute problems from this past winter.
Identify how those acute problems can be mitigated
or should be mitigated and attestation done by December 1st
those problems specific problems
from this winter event will be mitigated
by December 1st, 2021.
-: Yes.
-: Anything else you need from us in terms of deliverables,
specifics?
-: I think we're good, sir.
Thank you.
-: Anything else on this topic or is that?
-: Please no.
(laughs)
-: Fair enough.
-: Thank you for all your work.
-: I gotta go ahead to the pink building.
-: I think you better get over there.
(laughs)
-: You're in demand.
-: We'll give you a hall pass easier than they will.
-: Have fun.
-: Thank you.
-: All right, see you later.
Take care.
-: Thank you, Commissioner.
-: All right. Anything else we need to?
-: Yes, sir.
Thanks, Barksdale.
-: Thank you all.
-: That's Will McAdams (indistinct).
-: I think as he (indistinct).
-: I think Barksdale is gonna go straight to running.
(laughs)
All right, that will cover agenda item number 10.
Don't have anything for items 11 through 19.
All right, we will recess in closed session
after having convened a duly open meeting on,
we will recess at 2:39 p.m on August 12th, 2021
told a closed session pursuant to Chapter 551
of the texts government code section 551 1071.5510.074
and 5510.076.
We'll be back shortly.
For August 12th, 2021 is now reconvened.
No action was taken during executive session
on any matters discussed during the executive session.
Having no further business this meeting
of the Public Utility Commission of Texas
is hereby adjourned.
The time is 3:23 p.m.
(gavel banging)