(gavel banging)
-: This meeting of the Public Utility Commission of Texas
will come to order to consider matters
that have been duly posted
with the Secretary of State of Texas
for June 17th, 2021.
For the record, my name is Peter Lake.
With me today is Will McAdams.
-: Present.
-: This time, we'll open for public comment,
invited oral testimony related to a specific agenda item
will be heard when that item is taken up.
This public comment segment is for general comments.
Speakers will be limited to four minutes each.
Will the operator please come on,
and provide instructions to the public
on how they may be recognized, if they wish to speak.
Operator: Ladies and gentlemen,
if you wish to make a comment,
please press one, then zero on your telephone keypad.
(water pouring)
And it'll be a moment for the first comment.
And first, we're going to the line of Brad Johnson.
Please, go ahead.
Brad: Hi, I'm responsible for facilities
at NexTier Oilfield Solutions.
And we have numerous locations across Texas
and receive our utilities through Reliant NRG.
Since late March, we've received approximately 27 invoices
with over $300,000 in egregious past due
charges from Reliant.
This is over four times our normal utility bill.
I've called and emailed Reliant for months
with virtually no response.
The two responses I have received were stating,
my email has been received, escalated,
and an account executive would be responding
within 72 hours,
yet, still no response.
I've been asking for details
supporting the $300,000 plus in past due fees,
as well as disputing.
But again, no responses have been provided.
My concern is with the monitorium to shut off power
for unpaid bills being lifted,
many companies and individuals
could have their power shut off
without ever receiving a phone call
or email addressing the many requests that had been made.
I'm requesting, one, someone from Reliant to respond,
either by phone call or email.
And number two, for the monitorium to continue
for any customers that have disputes
with the February storms invoicing
resulting in past due costs from March forward.
These need to be addressed.
Thank you very much.
-: Thank you, Mr. Johnson.
Operator: Thank you.
And next, we go on to the line of Anthony Martell.
Anthony: Thank you for allowing me some time today.
I have a similar situation.
I have a small business
and just a couple of people, myself,
and a couple of others.
And we had a bill that's typically
around a thousand, maybe $1,500 per month.
We received a bill from MidAmerican Energy
for over $15,000, equivalent to almost an entire year
of electricity costs for us in one particular month.
And we have a fixed rate.
We don't have a variable rate of any kind.
And MidAmerican Energy is telling us
that these are ancillary costs,
and that we have to pay them.
And to give a little more clarity
of what we're facing right now,
we have more than one meter at our location.
And one of our meters,
they're charging us $4.09 average cost.
Our contract is four and a half cents.
It's almost 100 times,
100 times more than our fixed rate contract.
And I'm not a lawyer
and I don't pretend to be one.
But I don't understand how this, you know,
can pass any type of litmus test for truth in advertising.
I don't know how this isn't just complete
deceptive trade practices.
It's supposed to be a fixed rate.
And I'm just wondering
from the Public Utility Commission standpoint,
when a company advertises as fixed rate,
but then they can pass through literally,
almost a 100 fold increase in price
that the Public Utility Commission can stand by
and say, "MidAmerican, that's fine.
"You guys can just keep doing what you're doing."
Someone has gotta stop this.
And I'm just a little guy,
but if I don't speak out,
I don't know that we're being heard.
I know there's others.
One person that just spoke before me,
which is great,
but we need help.
I've reached out to our senator.
I've reached out to the Governor's office.
And now I'm reaching out to both of you
at the Public Utility Commission.
And hoping and praying that we're being heard
and that something's gonna be done
because we can't afford this.
We barely made it through the pandemic last year
in the beginning of this year.
Now, we're being hit with these fees.
And I have talked with other people at other businesses,
and either they received no increase
in their bill or a slight increase,
but they didn't get a hundred fold increase.
And also, one other quick comment,
it's targeted only,
it seems, at businesses,
from what I've heard, at least.
Residences, in many cases, maybe not all,
are being spared.
And if this type of fee had to be assessed,
if everyone paid something,
instead of putting these owner's fees
on businesses where they're paying, you know,
10 or 15 times or more their normal monthly bill,
maybe we could get through this
or maybe the PUC could step up
and offer some assistance and some protection
for consumers and small businesses like myself.
-: You have one minute. -: I hope we're being heard,
and I hope there's some help
that can be given before power's turned off.
And we're just kind of in a no man's land,
so to speak right now.
Thank you for time.
-: Thank you, sir.
Operator: Thank you.
And next, we go on to the line of Tammy Killian.
Please go ahead.
Tammy: Good morning.
Thank you for listening to my comments this morning.
My husband and I are restaurant tours.
And so you all know,
everybody heard on the national news.
You know what we went through
with the pandemic.
God blesses, we have survived.
And we are fighting to continue
to save two historic restaurants.
One restaurant, over 70 years in business.
We are your average citizens.
When we signed up for our energy services,
it's nearly like trying to be an expert
just to figure out all the plans,
what is right.
We thought we were doing, you know,
making a good business decision
with our businesses.
We're on a fixed rate.
We had the opportunity to
add our residential businesses or properties
to our business plan recently.
And so we thought, well, that sounds like a good idea.
So, reasonable savings.
So we were in limbo.
March 1st was the date for our properties
to go to fixed rate.
And of course, the storm took place before that.
So my 2,400 square foot home,
the month after the Texas storm was a $200 electricity bill.
I received a bill for over $21,000.
We live on three acres.
We have a barn and a shop in the back
with a separate meter,
charged at a commercial rate,
which I know all the electricity companies
pretty much do.
That bill alone, which is normally under $100,
around a $100,
was over a $3,200 bill.
And I guess, what I would like you to know most of all is
that, you know, I'm kind of,
try to be a little connected.
So literally, like a lot of other businesses,
I reached out to, you know, Tom Craddick, Hill Seliger,
PUC originally, which,
I sent all my invoices to
and unbeknownst to us
with this electricity contract when we signed up,
apparently, we signed away our right
for customer protection rules,
which we had no clue what that meant,
when we signed up.
So again, there was nothing that could be done.
So with the comments about reaching out
to all of these individuals,
we reached out to our TV stations, like,
okay, you know what,
you know, we couldn't believe it.
This, oh, this can't be true.
Surely, our state will take care of us.
This is just wrong.
But nobody could tell us what to do.
And just recently,
like a week or a week and a half ago,
I found out about OPUC
and found out about these meetings
where I could, you know, at least comment
and share what's going on.
So my number one biggest concern
that I would like you all to hear is
I believe that there are a lot more people out there
in this predicament,
but nobody knows how to get to you to let you know.
Nobody could tell us,
"Hey, this is, call these people, go here."
I guess, by the time I found out there was,
you had mentioned about being helped earlier
on other calls.
But I think that more needs to be done.
So the public really knows how to get their voices heard
or their voices before you all
for you to be able to make good informed decisions.
Now, I do want you to know
that our electricity provider is through ENGIE.
I have already received-
-: You have one minute. -: Disconnect notices.
Over time,
they basically have already given us a moratorium
that if you don't do this by this, by this day,
they wanted 50% of the fee upfront
with three additional payments,
which is very hard to do,
especially as recovering.
So when I reached out to them and let them know
that I knew that the moratorium
was not off yet for disconnect
and that I was struggling with the fact
that they were giving us such short time to pay back,
we were told that we need to provide
all of our bank statements so they could decide
whether they could give us a cash discount
or give us any other plans,
which is crazy.
Then we did receive
now some other options- (bell chiming)
Which allow it to be paid over 12 months.
But I just want you to know,
it's a tough situation.
And there were a lot more people out there
than y'all realize.
Thank you for your time.
-: Thank you, ma'am.
Operator: Thank you.
And as a reminder for public comments,
please enter one, zero.
Next, we're going to the line of Phyllis Davis.
Please go ahead.
Phyllis: Thank you very much.
We have an apartment, large property.
Apartment property, two houses, low income,
elderly and disabled, or critical care.
My electric provider is ENGIE.
The first indication I received was a disconnect letter
that I just knew was a mistake.
That was on May the 27th.
May 28th, I was on the phone with ENGIE, first thing.
And I learned about this storm recovery fee.
They were requiring me to pay 100%
in order to not disconnect that service.
I can't tell you the stress
I was under in knowing that.
And I told him, G. Ralph,
you know, I said,
"We have $12,000 in the bank.
"And there's no way I can pay this,
"but I can't afford for electricity
"to go out on this,
"you know, elderly and disabled folks.
"What can I do?"
Since that time, I've contacted you
and many other agencies just kind of in a panic
on what I can do.
I then had another conversation with Angie,
and they are unable to explain.
They kept saying I was delinquent.
The bill I paid, our invoice,
I paid current charges to have a zero balance.
And I told them I'm a good safe customer of yours for years.
And I am getting the $107,000 and 78,
$107,078 is my fee they have charged.
And they said I was delinquent.
The reason I've showed delinquent is ENGIE went back,
and redid a past invoice
for that January the 13th through February the 12th invoice
that when I paid it,
it had a zero balance when I paid current charges.
So they go back retroactively
redoing that same invoice
to show that I have an unpaid balance.
I think that is ethically wrong.
And so they're calling me a delinquent customer.
The new cutoff I have,
I spoke to them yesterday,
is Monday the 21st.
And you know, they want 50% minimum.
And she did send me a payment plan yesterday afternoon.
But if I don't pay the 50% down,
which I have literally no money.
We're a nonprofit, also.
Please consider that.
And...
They start charging you admin fees.
And I asked ENGIE,
I said, "Could you tell me what is the storm fee?
"And what is your late fee?"
The ENGIE rep said,
"90% of this total
"is actual energy charges."
So I said, "Okay, 10% is late fees."
I would ask you to take those off
because I'm not late.
If you're gonna apply this storm recovery fee-
-: [Man In White Jacket] You have one minute.
Phyllis: An extreme financial hardship.
Take off the fee.
But I would like all of you to hear the hardships,
real hardship we are getting
over these
very aggressive
behaviors from ENGIE, in my case,
and threatening on these disconnects
where I have elderly, and disabled, low-income folks.
And I appreciate the time,
but it is just not right for ENGIE
to go back and change past invoices,
so it looks like I have a delinquent amount and,
we do need someone to hear us
and change something in the state of Texas.
Thank you very much.
-: Thank you, ma'am.
Operator: Thank you.
And once again, for public comments,
please enter one, zero.
Next, we're going to the line of Jaime Sloss.
Please go ahead.
Jaime: So first off, I wanna apologize
to all the people going through hardship,
and I definitely wanna apologize to them
for thinking that the PUC,
and the Chairman, and Commissioner
or that their titles care about the people.
Because if you look at docket number 50284,
I raised various concerns about the PUC process,
and that you don't even follow your own process
on the basic set of hearings.
So any advice I can give
to the public is get yourself a lawyer
to make sure that your rights are not infringed upon
or just all together thrown out
because Chairman Walker, whatever his name is,
McAdams and Peter Lake,
they don't even follow their own rules at the PUC,
so they really don't care.
And if you're late and you're hoping
to get help for the disconnect fee,
look at the June 11th open meeting,
and you're gonna see that
McAdams laughed and says,
"Oh, I'll be happy with whatever I can get",
when they set a seven-day notice
to the public before they get disconnected.
So if you think these people care,
I just want you guys to be on notice
that they do not care,
and your rights that you think you have,
you do not have them.
So I highly recommend you get a lawyer.
Because I requested a rehearing
because the witnesses
for my electric utility were not present
as it is stated in the basic steps of a hearing process,
and they still voted against the rehearing,
and they decided with whatever the electric utility said.
And now I'm here five years later
after fighting with these people,
thinking that PUC is here for the people,
but they're not here for the people.
And McAdams knows it.
And Peter Lake knows it.
I would ask you guys to step down
and have somebody that's capable of doing the job,
and following the basic steps of the process,
and understanding the basic steps
to allow them to take over the PUC
so that these people stop suffering
because you guys cannot implement the rules.
You don't understand the tariffs that are in place,
and you do not care about the people,
not the people of Texas.
Thank you.
-: Thank you, Mr. Sloss.
Operator: Thank you.
And there are no more public comments at this time.
-: Public comment is now closed.
Moving on to the regular agenda.
Item number one, Will, I don't have anything on those.
-: No, sir.
-: Item number two,
I believe staff has some clarifying questions.
-: I do.
At the last open meeting,
you instructed
or you decided
that an order would be issued,
lifting the disconnect moratorium effective tomorrow,
June 18th.
And in that discussion,
we talked about the standard 10-day notice period
for postpaid customers,
meaning that
no disconnections would take place before June 29th.
And staff has received the question
regarding prepaid customers
who have a slightly different notice period.
I wanted to clarify
that it was your intent that no disconnections
of any kind would take place before June 29th.
-: That was my intent. -: That's my intent.
Connie: Thank you.
-: Yes, ma'am.
I don't have anything for number three, number three.
Do you, Will?
-: Backing up to that,
just because of the preponderance
of public comments on this,
'cause I think
it was such a massive
event in February,
and the financial impact
to consumers is broad-based.
And I mean, our arguments are compelling
that are coming in made by consumers.
I just wanna make sure.
And we touched on it at the last open meeting,
but I guess, we need to focus on it every time
we have the ability to speak.
In my view,
if reps are holding themselves out
or holding products out as fixed rate plans,
I think it's very important to us to try to define
or at least, look at what that means in the market,
especially in light,
I know we're gonna talk about House Bill 16
and variable rate products.
So for commercial consumers who've been calling in
as well as residential,
and again, I don't wanna overload
the PUC's complaints switchboard.
But that is the trigger
for us to be able to drill down on the terms
and conditions of contracts
to at least analyze it.
And I think it's in the public interest
for the Commission to over time process those complaints,
process those cases as they're coming through,
so that we can establish a bit of case law on this,
a bit of PUC precedent,
because in future events,
this is gonna be very important.
One, we wanna help the people that are at need now.
And two, we wanna establish safe guards,
so that we just don't go through this again.
And I would stress that a deregulated market does not mean
that there's no regulations.
This Commission exists to protect the consumer,
and to protect a healthy market that benefits all Texans.
So those are kind of my views on it.
I just wanna stress for these people,
these business people that called in,
as well as the the consumers at large,
stay in contact with the PUC,
complain if you feel like you're being mistreated.
Fixed rate needs to be established here at the Commission.
And we need to define safeguards.
-: Fixed rate should mean fixed rate.
-: That's was my view.
-: A hundred percent agree with that.
And variable can be variable, right?
And as we dig into that,
and I absolutely,
the first step is our customer production line,
encourage people to use that when needed,
and use it sooner rather than later.
And also as part of the rulemaking,
we'll be going through considering,
not only ensuring that fixed rate is truly fixed
without backdoor exemptions,
but also ensure that we take a hard look
at the fine print,
and make sure that waiving rights,
certain rights or other exemptions
we make in customer contracts,
let's make sure we take a very hard look at that,
and clearly define what is inbounds and acceptable,
so we can avoid these kinds problems going forward.
-: Yeah, I'm all about that.
If staff, and I know staff is out there taking note but,
over the next months,
I think it's important that we see a flow
through when possible to get these
before the Commission,
so we can start speaking to this
on a more specific basis.
And again, that will,
consumers, and matter of fact,
can we have, just while we have this opportunity.
This Commission has promulgated a clarification
on what the rules and regulations are,
but Connie can you speak to the mechanics of disconnection,
the five billing cycle moratorium
and what the consumers rights are.
-: Absolutely, so.
I'll go through the base case where the customer
understands that they owe
and they agree that they owe the amount
that they need, perhaps, more time to pay.
So they should call their retail electric provider and,
our rules call for a maximum of 50% down payment,
and then five subsequent payments
to eliminate the balance,
to pay that off.
That is the minimum.
The rep
is absolutely welcome
to provide any more lenient terms.
If they wanted to give
25% down payment in one year,
that would be absolutely compliant with our rules.
We had a number of retail electric providers
file letters with the Commission,
noting that they were providing these more flexible,
deferred payment plans.
And I believe, they're described in those letters.
One point, they also made that is very important
to remember is the customer should contact the provider,
work with them,
let them know what it is they can pay,
and work out a payment plan
that's specialized to whatever that customer's needs are.
So that's for when
you realize that your bill is correct,
but you need more time to pay it.
If you,
again, agree that your bill is correct,
but you just don't have the funds
to pay the bill,
even over a payment plan as described,
you can take advantage of some of the TDAHC programs
that were presented here a couple of weeks ago.
There's a
program specific to renters,
and then there's a general program
for both renters and owners.
And folks can find more about that on the TDAH website.
They can call into our customer protection division,
and get some guidance on how to access those plans.
And they can see through our website
as well how to get access.
-: And along those lines,
I'm sure our communications team will continue
to provide that information, those websites,
those phone numbers
via our multiple social media channels.
-: Absolutely.
And then to get closer to the scenario
that many of the customers
in the public comment period described today
which was,
they don't agree that they owe that bill.
That's not what they signed up for,
what they believed they were signing up for.
And they don't think it's right.
They should absolutely contact their provider,
dispute the amount.
If they cannot get proper resolution from that provider,
then call our customer protection division
or file a complaint online.
And I want to be sure
to get the exact rule citation correct,
so I have it here.
Commissions rule 25.485
subsection E2, specifically says,
"While an informal complaint process is pending",
that means you've contacted customer protection,
and they've begun investigating your complaint.
"The rep shall not initiate collection activities,
"including disconnection of service
"or reporting the customer's delinquency
"to a credit reporting agency
"with respect to the disputed portion of the bill".
So if you're concerned that you're in a dispute,
and you're concerned you're gonna get disconnected
because of it,
make sure that you have a record of your dispute
here at the PUC
and you cannot be disconnected.
Peter: That's incredibly important.
So like you said,
the first step is contacting
the PUC customer protection line.
-: That's correct.
-: And once that complaint is initiated,
you cannot disconnected.
And once that is initiated,
until it is resolved,
that customer cannot be disconnected,
they cannot be sent to a credit reporting agency,
and they cannot be put in collections.
-: Exactly.
-: That is an incredibly important point.
Thank you.
-: Thanks.
So that's the point I wanna make to the public,
is on the policy,
we at the Commission need an opportunity
to start working this problem,
and we are working the problem.
But we're doing it on a massive basis
to try to help as many consumers as possible
with these decisions that we're making here.
So as you call your providers,
as you work through the negotiations
on these payment plans,
and then as you work through with the Commission,
then that'll provide, that as the trigger to provide us
with the opportunity to speak to this
and long-term help you.
So again,
I know that we're a sleepy little agency
up until the February event,
but we are processing this quickly,
and we wanna help as many people as possible,
so just provide us that opportunity.
-: Well, put.
-: Thank you. -: Thank you, Connie.
Does that cover everything for?
-: Yes, sir.
That's all I have.
-: Thank you for highlighting those points.
Item three, I don't have anything on this.
Do you?
-: No, no, sir
-: Item number four,
review of wholesale index products
for compliance and customer protection rules.
I believe Mr. Smelser has a presentation for us.
-: Good morning, Commissioners.
David Smelser for Commission staff.
So as Connie sort of discussed with you guys before,
this started out as sort of a rule-making effort
to specifically implement the prohibition
on wholesale index pricing.
We've expanded a little bit
to include some other customer protection issues.
But as we've seen with the discussion
that you guys have been having the last few minutes,
there might be, you know,
there's more to do than just the contents
that I'm gonna talk to you today.
And so, you know, maybe that'll be a different rulemaking
or maybe, we can add some briefing questions
onto this to start calling industry for solutions.
That's, you know, whatever your preference is on that.
But I don't wanna just start pitching solutions
without having thought them through,
but I think we're definitely gonna be looking
into the matters that we discussed.
For today, the current status right now is
we wanna try and get a proposal for publication,
so we can get the rulemaking moving by July 15th.
But in order to make sure we're putting out
the best product possible,
we're gonna run a straw man out there first
or at least, that's the plan.
And so today, I just wanted to make sure
that you guys thought we were moving in the right direction
because we have, you know, a lot of this,
the legislature told us how they wanted us to do it,
but we've made a few sort of policy calls ourselves.
So I just wanted to talk you through those calls
and you guys can say,
"Yeah, this is kind of what we thought or not."
The two bills that we're implementing here,
the first one is a House Bill 16
and this has a couple of components.
As we discussed, specifically,
with regard to the wholesale index products,
which are those that vary in real time with energy,
the sort of gritty products,
is the ones that we're more familiar with.
According to the bill,
they're gonna be prohibited for residential
and small commercial customers.
And for those larger customers,
they will be permitted,
but there has to be,
there's a specific statement in the law
that's an acknowledgement of risk
that basically makes it so that we're sure
that when people sign up for these plans,
they understand that they can vary pretty widely.
And so, of course,
that is, we have the strong main language
that will implement it as described,
but there are a few expansions
that we were thinking about making on that.
At this point, since it's straw man
we sort of, we're putting them out there for comments
and we'll see what people think.
Maybe they should be stronger, not stronger,
but one expansion we wanted to do is, you know,
I mean the realtime price of energy
is not the only thing that you can be indexed
to that could vary widely.
And so we were thinking about requiring
a similar statement of risk for any index product,
just so that when people,
if people were indexing to things
that could be varying widely,
they need to, you know, deliberately make that choice.
Peter: What would an example of that?
-: For instance, you could be indexed to the NYMEX
or ancillary services, or, you know,
I mean you can index to anything,
but I guess NYMEX is your clearest example
of something that goes up and down
that plants can be-
-: Sure, any variable financial product out there.
David: Right.
-: But on ancillary service, since so many, I mean,
since that's what we're hearing on the commercial side,
where this would probably be more of a attractive target,
I mean, individual consumers certainly
could avail themselves but for a business, you know,
who's looking to squeeze everything they can
out of a product,
that would be something to consider.
-: I agree.
And I think that with ancillary services in particular,
that was the second proposal that we talked about
is to pull together.
It wouldn't be, you know,
these other ones wouldn't be written the same way,
but we have a version written out
that would require acknowledgement of risk
for anything that included an ancillary service pass through
which is a little bit different than indexing
but it creates the same,
from the customer's perspective, it's the same problem.
A lot of money that I wasn't expecting to have to pay.
And then one element that it's, you know,
it's not clear from the legislation
what the legislative intent would have been
behind polar customers.
I mean, as you know, the polar rate
is the provider last resort.
That's what you get sort of booted to
if your rep goes out of business
or in a couple of other circumstances.
Currently, the formula that they have to use when they're,
you know, the formula that is used
for some polar plans includes as an element in our rules,
this realtime price of energy.
And so we can argue whether or not
that technically counts as an offer,
but it seems within the spirit of
what we're trying to do here,
we need to get that out of the polar rate.
And so the current pitch that we have
and we've sort of socialized it with a few stakeholders
to make sure it wasn't too upset is, you know,
right now, reps have a choice
or the large service providers,
not the VA reps, but the other,
sorry, the other polar folks,
they have a choice between doing like a market base rate
which is sort of similar to their other plans
or they can do this formulaic rate
that I was discussing
that has the real-time price of energy in it.
And there are actually different categories
of customers based on size.
So there's four different categories
and the formula is a little bit different for each of them
which is sort of a,
kind of a confusing thing anyway.
And so we're proposing kind of a streamlined approach
where we get rid of the one that's contingent
on real time pricing and just go with the market base rate.
And there is some concern that, you know,
the benefit of it being keyed
to the realtime price of energy
is that have reps have to use this in their up price spikes,
the reps are protected, but as we've learned,
that's not great for the customers.
And so one proposal would be that we allow
in the formulas there to be multipliers.
And so you could use your multi-market base rate
but then you could,
based on a customer size class,
maybe there could be like a percentage multiplier
that the rep would need just to be able to, you know,
hedge their coverage.
And so, you know, maybe that's 2%,
maybe that's 10%
and it could vary based on class.
I don't know what that would be right now
but we think this is a,
it may not be the end proposal that's the final solution,
but we think it will spark good conversation
or good comments to, you know,
maybe folks out there have better ideas.
And we just haven't heard from yet.
Maybe they like it, maybe they don't.
But we think that it solves the problem
of getting these energy spiking prices
out of the polar service
and is a possible first step.
-: But at the least, it would create a range band of risk
for the consumer?
David: That's our hope.
-: Okay.
-: And so those are...
That's sort of what we want to do in this space
of the wholesale index pricing.
And, you know, I wanted to check first,
specifically with you, Chairman,
because, you know, it was one of your comments that said,
"Oh, make sure
"we're also thinking about ancillary services."
And so since what we were doing with these other rates
was requiring this acknowledgement,
we're like, okay, we'll just give that similar treatment.
Maybe that's what you were hoping for.
Maybe you wanted something more aggressive.
But this was sort of where we started.
-: Yeah, I think that's a good starting point
and also I appreciate the points you made
at the beginning of covering any index product.
And so there's,
we wanna avoid...
A customer signing up for something
that's indexed to some obscure esoteric financial products
that they have no,
that they really don't, aren't aware of,
but is essentially a work around for the provider.
So I think that's very important.
I appreciate that.
David: Okay, thank you.
-: And I would ask as we go through this,
for all of these scenarios that we're considering,
and I know this is a straw man,
this is very much the starting point,
but as we narrow down the options
and get closer and closer to
the final version of all of these different protections.
David: Yes, sir.
-: Let's make sure to go through examples scenarios.
David: Okay.
-: And consider what it looks like
from the customer's perspective.
-: I think that's a great idea.
And I'm sure there are members of the rulemaking team
that I'm working with,
who could have been able to do that
off the cuff with you right now.
I'm just not that I'm not that person.
Peter: We don't have to do it right now.
-: I'm not that person.
-: Just, as we go through the process
and we come up with a new formula or a new multiplier,
I want to be very careful that we don't caught in
and we don't get so wrapped up in the technicalities
of the rulemaking that we forget
to consider the on-the-ground reality for our customers,
both residential, consumer,
and for different products.
And so let's make sure we think through
and put numbers to what our proposals look like
in real life for those real people.
-: I think that's excellent guidance.
And we'll keep that in mind as we go forward.
Peter: Thank you.
-: The next component of HB 16
is that there are new requirements
with regards to disconnection notices
in terms of like how frequently they have to be given.
Previously, it was one.
Now, it's three.
And there's a few little requirements in terms of, you know,
how they have to be displayed on bills and things like that.
And we don't need to get too deep into the details
because, you know,
the legislature told us exactly what we needed to do
so we're going to do it.
The one policy call that we did make is
there is a requirement that just applies to, I think,
fixed rate products that requires
if you're doing it with a bill insert,
it has to be a separate piece of paper
so that the customer takes notice.
And in our draft version right now,
we expand that to all plans because, you know,
if it's a good idea for some, it's a good idea for all
with regards to, you should know when your plan's ending
and what's going to happen.
The other bill that we sort of, you know,
this started out as HB 16,
but there's one component of SB 3
that we thought we would knock out
as we were looking at this as well.
And that is section eight of SB 3 requires, you know,
the utility is to periodically notify reps
and then reps to periodically notify their customers
of a few items.
And those are sort of
information about load shedding practices,
information about how you can get some of these designations
such as like critical care designations
and things like that.
And so in terms of, you know,
just the idea that reps have to notify periodically,
the way that we're going to interpret that
at the beginning is
we have language that puts it in the, you know,
the your rights as customer document,
which, you know, you get sort of at the beginning,
so you're notified.
And then we thought the way we're interpreting,
a useful way to notify periodically
would be let's have them do it in April and October.
You know, so it's twice a year and it's, you know,
before winter and before summer.
So these shoulder notifications,
so that's our starting point proposal
for that component of SB 3.
-: Does that rulemaking contemplation
take care of all of section eight in SB 3
because SB 3, section eight was,
it was a big section.
There was a lot involved there.
The critical care-
-: I think as customers,
I don't think that it does. -: Okay, yeah.
-: I mean, we have different groups.
And so like, you know,
our critical load team is going to be working on exactly,
I think what some of these aspects are.
There are different aspects of our teams that we're working,
but since we had to open,
we're opening this part of the rule anyway.
And so it made sense for this retail customer group
to just clarify that component.
And we're sort of doing it by reference.
We're just like, you know,
reps, you also have to notify them of these four things,
whatever it is we decide to do with it here.
-: Well yeah, I mean, I agree.
Organizationally, if that's how you want to proceed.
I just knew that that section had a couple
of different policy objectives there
and they were quite, they were complex.
So I didn't know if you were going to try
to take care of it all in this proceeding.
-: No, sir. -: Okay.
-: I think various aspects of Senate Bill 3
will be included in many things we do for a while.
And then also just, you know, I have...
Yeah and so those are the discretion decisions we make.
Down here, I have two proposed timelines
and we don't need to go through the details,
but basically there's the, if everything goes right,
people are generally on board with what we're doing
and we just have to make a tweak.
It's this column on the left
which would allow us to get you a proposal
for publication by mid-July.
But if we get, you know,
we don't have to summarize comments for straw men.
So it's not like it's not like the number
of comments filed would delay us,
but should people have a lot of good ideas
or maybe something we did here
is bad for reasons we didn't think of,
I have the second timeline that would allow us
to issue sort of, at staff's discretion,
a call for reply comments, if we need to,
or maybe we need briefing questions
and then hopefully, then we would just bump it back
to the open meeting at the end of July.
And so if you guys are comfortable with the proposal
and that timeframe,
I think that's the guidance that we need at this point.
Peter: I'm comfortable with that timeframe.
-: Same here.
-: And I would also say I appreciate the process
and starting out with a straw man
to frame the discussion
and essentially, giving the general public
two chances to participate in the process
rather than the standard
one phase of public comment.
David: Thank you, happy to do it.
-: Yes, sir.
Anything else for David?
-: No, sir, I'm good.
-: Good. -: Thank you.
-: Thank you, Mr. Smelser.
That covers item number four.
Item number five.
I don't have anything for items number five through 10.
Do you? -: I do not.
-: That brings us to item 11.
We will hear from ERCOT
on an overview of this week.
And...
We also hear
some comments from them
on both on the operations and planning component.
I think we'll start with Woody Rickerson.
Man: Woody Rickerson.
Turn it on. -: Chairman?
Would you like to take a moment to make sure
that the call is going okay?
We're hearing a little feedback there.
-: Let's turn down the volume.
-: Need to check with the operator.
If the operator can hear us,
Don, could you check on that feedback please?
Don: Yes sir, I can.
Just one moment.
-: Thank you.
Don: Okay, you should be all set now.
-: Thank you very much. -: Thank you, Don.
-: Sorry about that.
Mr. Rickerson, thank you for being here.
-: Woody Rickerson, vice-president of grid planning
and operations, thank you.
Yeah, well, first of all,
I want to thank Texans for conservation this week.
I think that's shown to be a very effective tool.
A lot of ISO's use it.
And this week, we saw what we thought was going
to be a plus 70,000 megawatt peak
reduced down to 70,000.
And so all week long,
we've had the conservation alert
and we've seen good response all week.
So that has, because of those actions,
we have kept the grid in a very reliable state.
-: Excellent, that's,
a unique,
that's a new and different approach to conservation notices.
Is that correct?
-: We have used conservation notices in the past
but this is a more conservative approach
to operating the grid.
-: In a different timeline, you said?
Woody: A different time line, yes.
-: Okay, I appreciate that.
I think that has helped Texans
learn more about how much conservation can help
and also be more responsive
over the greater period of time
rather than the hourly on and off again.
-: Right, you know,
our job at ERCOT is to balance generation and load.
Conservation gives us a tool to balance
the load side of the equation,
just like we've used generation
to balance the generation side.
So it's nice to have something on both sides
of that equation.
-: Absolutely.
And it's not unlike the mini conservation
calls we hear in Texas each summer
for conserving water. -: Right.
-: We ask people not to water their lawn every day.
And when you do water your lawn, please do it at night
when it's not as hot and evaporate.
Don't wash your car every week.
Et cetera, et cetera.
Thank you.
Could you give us an overview of the week,
kind of going back to the last, I guess Saturday, Sunday,
the circumstances we found ourselves in
and how EROCT managed them?
-: Yeah, so all week long, we have had,
whether that resulted in loads
that could have been higher than 70,000 megawatts of 72,000.
In fact we set a June peak already,
even with conservation,
we set a new June peak.
So this has been hot weather
resulting in high loads.
The wind output has been relatively low this week,
over peak.
We also had an unusual number of forced outages
of thermal units.
So we're investigating that.
We're gonna try to understand better why
we've had as many thermal units on outages as we've had,
but those two factors
along with the, you know,
the high number of generation outages,
the low wind output
and just the temperature itself causing load to be high
is what has caused the concern this week.
-: Okay, so- -: Go ahead.
-: So, at a high level,
we had a confluence of three factors, right?
We had...
A record breaking amount of demand for electricity in June
that we hadn't seen before. -: Right?
-: We all know Texas is growing.
We got more people coming in hotter weather
than we've seen typically in June.
Same amount of generation.
We've got more people meaning more electricity.
The second factor was lower generation from wind
than we expected.
-: Right. -: Accurate.
And then third,
we had an unusually high number of mechanical failures,
the forced outage,
that's machinery and our generators breaking in real time.
These weren't planned outages.
-: That's correct. -: Correct?
-: And that's an important distinction
is that we have,
there are two types of generator outages, roughly speaking.
There's planned outages that we have
where generators need to do maintenance
to get ready for a season.
And then there's unplanned outages
where things just break and they have to go offline.
And what we've had this week has been unplanned
forced mechanical failures of generators.
So those aren't things that ERCOT are planned.
Those aren't things that we approved.
They aren't things that we factored, you know,
if a forced outage happens tomorrow,
that's not in our plans today for tomorrow.
Peter: Yeah, that's machinery breaking as it's running.
-: That's right.
That's like the flat tire on the side of the road.
And you don't anticipate that, but you have a spare.
-: Hey Woody, I think this is really useful
to kind of have you up here.
And just from a, as we start to try to marry up
Senate bill three
and those market directions and reforms,
I believe the legislature considered them reforms
to a degree.
And we talk about this event,
this is a great kind of a test case
to sort of see how the market could respond
or what that bill could target in terms of policy impacts.
Can you tell me just from a, as a dataset,
what was the lowest amount of wind production that we saw
over the last three-day period?
How low did it get?
-: Well, we saw 118 megawatts.
-: Okay, that's the number of records.
I think that's important.
I did not know that.
-: That was an instantaneous number.
I mean, those are very, very-
-: Yes sir, a spot in time.
-: Very the usual number.
And it wasn't over a peak period.
Will: I know, yeah.
-: But we saw 118 megawatts.
-: Well, I can tell you where I was over that three days
and you were busy fighting this fight
but I was in my office staring out
at the Moody Bank building, looking at the flagpoles
and looking for any type of movement with the flags.
And literally, just anecdotally,
that's how deep the doldrums had set in
across the state of Texas.
-: And we do see that happen.
-: Sure. -: Occasionally.
And it was earlier in the morning.
It wasn't over peak.
The load at that point was not at the highest point
we were going to see that day,
but it does show the variability
that we're subject to.
-: And so how great a fluctuation
and I'm going to take it in two parts
so for viewers watching,
I'm going to talk about,
ask questions about the thermal side of this, as well.
So this is not partisan.
This is just identifying data points
that I think we need to identify
to help marry all this together in SB 3 implementation.
But on solar, Monday,
Monday was cloudy and we saw
a bit of a solar reduction
compared to historical averages, as well,
'cause we've got 7,000 megawatts total installed.
-: We have currently,
I think by the end of the summer,
we're expecting to have seven.
Will: Oh, I'm sorry.
-: I think right now the most we have seen
is maybe a little over 6,000 or right up to 6,000 megawatts.
-: And they performed at five on Monday, then?
Okay.
-: And we have seen solar fluctuate
because of cloud cover over,
when they're supposed to be running,
or when they could have been running,
they're not supposed to,
when they could have been running,
we've seen 5,500 to 5,000 at times.
-: Okay and on the thermal side,
it was those mechanical breakages that...
When did ERCOT
really get notified of the forced outages?
I knew there were kind of, it came in waves.
So you could sort of break it down into the first wave,
which was identified
by your reliability unit commitment exercise
that you went into during the weekend.
And then it sort of crescendoed,
as we ramped up to meet that heavy load,
you know, that increased demand.
-: So we have eyes on all generation, all the time.
So we have telemetry.
So as soon as a plant is forced out
because of a mechanical problem,
we see it as soon as it happens.
The plant operator or the qualified,
the queasy will actually give us the data shortly afterwards
in our outage scheduler
but we're watching the plants all the time.
And so we have what we call a forced outage detector
that tells our operations as soon as it happens.
So that answers that part of the question,
but ERCOT relies a lot on forecast.
So we have a wind forecast.
We have a solar forecast.
We have a load forecast.
And so when we're looking at future days,
we're factoring all those forecast into place.
We also have what we call a current operating plan
which is people will call it the COP, C-O-P, the cop.
The COP actually will tell us,
you can think of the COP as a thermal generation forecast.
So the COP tells us,
so you think about, you have a wind forecast
and a solar forecast,
they also put in a COP and a load forecast.
And then the COP for thermal generation
is our thermal generation forecast.
And so we factor all of those things
into future day studies.
So if we're looking at
what we think tomorrow's peak looks like,
we put all those forecasts in and we run studies
to make sure that any reliability problems we're gonna have,
we anticipate those and take care of them
before they get to real-time.
Peter: How much?
Go ahead.
-: Our objective is always
to root out problems before they get to real time
so that our operations run smoothly.
So if there's something we can do today
to fix a problem tomorrow, we'll do that.
And the better the information we have,
the better our forecasts are,
the more problems that we can solve
before they get to real-time.
-: I know we've seen the,
wind, solar forecast,
the load forecast that you mentioned.
Warren's going to speak to that a little bit later,
and those go,
Warren can give you a forecast for the whole summer,
for a month, for a few days.
And of course, the shorter the timeline,
the more accurate. -: That's right.
-: But the forecast can extend over substantial timelines.
How far in advance does your thermal generation forecast,
the current offloading plant,
how far in advance does that forecast look?
-: It's a seven day forecast
but the data in that forecast is not very good
more than 18 to 24 hours out.
So it's not something that we can really rely on
for a three day outlook or a four day
or even a two day outlook.
So when we're looking at studies
for two days from now,
we have to make assumptions
on what that thermal generation is going to do
because if we just put in what was in the COP,
we wouldn't have enough generation to run the system.
-: Okay, so when we're looking at
wind generation, solar generation
and looking at demand for electricity on the load side,
you've got 24, 48, 72-hour week ahead forecast.
And again, the longer the timeline, the more,
the harder it is to predict
but for forecasting thermal generation,
you've got at best 18 hours, maybe 24?
-: 18 to 24 hours is, yes.
-: And after that, you don't have any visibility?
Woody: We don't have good visibility, no.
-: Okay.
-: There's some in there, but it's not,
you could not plug that COP data into a two-day out,
computer simulation and be able to run it.
And you have to add some stuff.
You have to make some assumptions
and fill in the gaps because the information's not complete.
-: That would seem less than ideal.
Will: Hmm hmm.
-: Is it fair to say that's a big gap
in our ability to- -: Yes.
-: Preplan and manage- -: That's right.
So some of the things we're looking at beforehand,
if someone wants to take an outage on a transmission line,
well, we needed an accurate generation plant
to understand if we can take that outage.
If we don't have good COP data,
then we could approve an outage on a transmission line
and the generation needed
to support that outage isn't there.
And so you have to,
it creates a problem that you have to deal with
in real time.
So that's an example of why good COP data is important.
-: So you're talking about like a planned outage,
like for maintenance?
Woody: A planned outage, that's right.
-: So you're looking ahead and saying next Monday,
if somebody asks you,
we need to take our generation down
to perform maintenance,
to make sure it's ready for July and August.
And when that request comes into ERCOT,
I know y'all try to manage that
so you don't have a lot of people doing maintenance
at the same time, obviously,
but when that information
or that request for maintenance comes in to ERCOT,
because you don't have more visibility
into the forecast of what generators will be,
what thermal generators will be running,
you don't know, you're just guessing?
-: We are, yes.
We are basing our assumptions
on what's happened in the past,
but we don't have good operating information
or as good as we could have.
-: What, how do we make that better?
-: Well, one of the things we're doing,
we have started doing more of now
is bringing, making out of market decisions
to bring new generation online.
You'll hear people talk about that as a RUC,
reliability unit-
-: Okay. -: It's not new generation.
It's existing generation that you are moving
into an operational status.
-: Well, I'm thinking, hold on, before we get to that,
I want to cover that.
Before we get into how you're mitigating that,
how would you make your forecast better?
-: Well having accurate COP data
would make our forecast better.
Peter: Okay.
-: We're also, we're heavily investing in improving
our current forecasting methods.
We've hired new people.
We put some of our top talent in positions
to help us with forecasting.
So we're developing,
we're looking at developing demand forecast.
So we don't really have an understanding
of what the demand response is,
understanding what force EP response is,
understanding the impact that rooftop solar,
that electric vehicles have.
All those things factor into that load forecast.
Peter: Absolutely.
-: So we're investing in understanding what those are
so we have a better overall forecast.
-: That's incredibly important
but when you say better data on the COP,
the better data on knowing which thermal generators
are gonna be running over the next four or five
or even two, three days?
Woody: Even two or three days, yeah.
That would be better than we have.
-: What information do you need to improve that?
You said better data.
What does that look like?
I mean, I know it's more complex
than we can list or go through here
but what, just a at a high level, what would that look like?
-: It would...
The COP data that they provide would be more accurate.
It would be a better indication
of exactly what's going to happen to those generators
over the next few days.
-: How the owners of those generators
are planning on running them or?
-: That's right.
What they anticipate doing with those generators
over the next few days.
How much are they going to run them?
That's what that current operating plan
is supposed to give us.
And it was supposed to go out seven days
in the original market design.
It was an indication over seven days
of what generators were going to do.
And there's various market reasons
why that hasn't worked out,
but only having good COP data
in the 18 to 24-hour period is problematic.
And we talked about that some during the summer assessment,
the summer preparatory meeting,
we brought some graphs out and showed that
and that's remained the problem.
-: Yeah and I think one of the,
and again, in the competitive paradigm,
everybody has been resistant
or a lot of market participants
have been resistant to change that
because again,
it affects what their competitors do
and reacting to some of those base load generators.
They're built, right, I mean,
ultimately when that nuke is running,
when it's running steady state
or when those coal plants are running steady state,
it's just layers of, you know it's going to be there
and they're going to be running either full out,
hopefully for your purposes
or at different levels.
And then the peakers start playing in,
you know, so they're all trying to hit these varying prices
especially when we're not talking about peak
'cause at peak, it's a totally different animal.
-: Right, yeah, at peak, we've been everything running, so.
-: And the market considerations are important
but just the,
they're very important.
I know we've got Carrie here from the Market Monitor,
so we can bring her in if we need to,
to make sure.
The market considerations,
both for the competitors in the market
are acknowledging and mitigated.
But also to make sure that there's not market manipulation
that harms consumers,
and when you say better data for your thermal forecast,
looking ahead to see what's running, going to be running.
so you can better manage the raw ability of the grid.
That information that comes in,
that data would be confidential.
Woody: That's right.
-: So it should not be out there.
-: Right, all of our data,
internal studies are all confidential.
No one sees those except us.
-: Okay.
That seems like we need,
something we need to improve on,
can improve on.
Is there any functional reason we couldn't improve
getting that data or-
-: There's no functional reason we couldn't.
I mean, there'll be some,
I mean, it is what it is for reasons,
but from a functional systems standpoint,
we're set up to receive that and use it.
-: Okay. -: I think issues like this,
and also, for Woody's perspective,
because there's peak.
And now, we have to think about shoulder, you know,
those seasonal outages
and his ability, because again,
for the purposes of the general public,
'cause we're also educating them with these workshops.
Good deal.
Woody, explain, again, the letter of the law
and your ability to coordinate those outages.
Re-amplify that, those planned outages.
Because again, I believe the generators,
with all these forced outages
and argument may be made
that we haven't been able to take planned outages.
It's tight.
-: Sure. -: Go ahead.
-: So when we talk about generator outages,
we're talking about when a generator,
a generator outage is when they're offline,
they're not running.
So sometimes the generators are offline
in order to work on the plants
and they have planned overhauls, planned maintenance.
And when those occur,
if generators schedule those more than 45 days in advance,
then we automatically accept them.
That's the way the rules are written.
If they ask for a planned outage
or a planned maintenance outage
with less than 45 days notice,
then we look and make sure
they're not going to cause a reliability issue
and make sure we're not having too many on one day
or anything like that.
And so we approve those
and we may call them back and say, sorry,
it looks like it's too tight on the day you're asking.
You need to wait three days
and then you can start.
'cause these other guys are going to be back.
So we coordinate that stuff within 45 days.
More than 45 days,
we don't have any control over that.
We take what they ask for.
-: So is that something that we need to reconsider?
-: I think it's worked okay.
Most of the time,
these plants are giving us notices of their outages
well in advance, sometimes six months or a year in advance
and we can fit everything else around the people
that get their outages in early.
So the 45 day notice is actually not a bad compromise there,
that we have been able to make that work.
So within 45 days, having that control has been useful.
That was a change that was made after the 2011 FERC report.
We implemented that.
The bigger problem here recently though,
has been forced outages. -: Yeah.
-: I've heard several radio shows
and read some articles where people have asked,
why would EROCT allow that many outages on a particular day?
And people who are interested to understand,
those are mechanical failures that are occurring.
Those are not planned outages.
Those are units that we expect to be there,
until they're not.
And then all of a sudden they're out.
-: That's an important point
but the bottom line is still the same.
The impact on the grid and on Texans is still the same.
And I think that's something we need to look into.
I know we had a lot of ERCOT and the PUC,
had a lot of conversations with the broader public this week
about exactly what you're saying.
What caused those outages
or the mechanical failures?
Why was all this machinery breaking at the same time?
Because it put us in a tight spot.
Woody: That's right.
-: And we're still in a tight spot.
And I understand there's
an existing rule in the ERCOT protocols
that prohibits identifying who was generating,
who wasn't generating for 60 days.
-: That's correct. -: Is that accurate?
Woody: That accurate.
-: We got that question a lot this week
and I know y'all did, too. -: Right.
-: And I know there are market considerations,
but I think it's worth considering waiving that rule.
Having the Commission waive that rule
given the circumstances
and given the challenges
we know we're going to be facing this summer
so we can see, and the public can see,
what generators were operating,
when they were operating.
And we can get better visibility
into solving some of those problems.
-: So I thought about that.
And I think it needs to be looked at.
So from the policy,
I know that competitive and confidential information
is an important nuance to the ERCOT marketplace.
I mean, by definition,
we are a competitive marketplace
and thus, everybody is trying to use any advantage they can
for their shareholders
in that environment...
I think it's safe to say the world has changed
somewhat over the last three,
well, certainly since 2018,
since the 10,000 megawatts of coal generation retired,
that base load capacity is no longer there.
We're in a paradigm, it seems,
to where it's just a tighter system than it was.
And with the degree of intermittency
that Woody has to integrate,
we depend on companies doing the right thing.
And I believe they are doing the right thing.
I believe ultimately their shareholders
have an interest
in maintaining those facilities.
But there is a policy benefit
that could be considered in transparency
on when these things go down.
I mean, you have an added interest
in getting that thing back up
or maintaining them to a degree
where it's not going to go down.
There are still, and I want both the public to understand
and legislators to understand,
when forced outages occur
and depending on where that generator is
in the bidding process,
there are financial penalties that are incurred.
I mean, that was highlighted during the winter event.
I mean, significant financial penalties.
Again, we were trying to cope
with that all through the session.
However...
Peer pressure is a real deal
and public eyes on these individual events
may have a benefit for our purposes.
So yeah, I think we should consider it.
-: I certainly agree, obviously.
And as it goes to the market manipulation,
I know private companies report to their shareholders.
And I know Carrie, we've discussed this a little bit.
And there are very good reasons for preventing the,
tremendously important reasons
for preventing or minimizing market manipulation,
but also in looking into this,
have, I want to point out that
a lot of this information has been
gleaned out by private sector information companies.
-: Right, there's an entire industry set up to dig,
to ferret out these nuggets.
-: Everything from watching smokestacks,
paying people to watch smokestacks
to see who's generating
to running thermal infrared cameras along power lines
to see where the power's flowing.
So I think,
in terms of the potential for more market manipulation
and thus, a negative impact on customers,
having this information in public
has a minimal impact on the
or almost no additional information would be made available
to market participants.
And a lot more information
would be made to the general public,
which is incredibly important.
So this is not something we're gonna solve today.
-: No, sir.
-: But I think,
it's something I'm gonna consider,
continue to evaluate, and we'll probably follow a memo on
before our next meeting.
And look forward to discussing that with you
at the next next meeting.
-: I look forward to it.
-: One more request
on the data you mentioned related
to the current operating plan,
the look ahead to see what our forecast
for thermal generation is.
Would you have your team
give us a list of what that data would look like
in your perfect world,
to get a better visibility beyond 18 to 24 hours?
Woody: Okay, yes, certainly.
-: We'd appreciate that.
And we'll take a look at that, as well.
Before we let you go,
I would also
like to hear your thoughts on,
in what was a challenging week, for the grid,
and challenging enough that we asked Texans
to conserve what they could.
How did ERCOT respond to this situation differently
than it has in the past?
-: Okay, so a couple of things that we did this week
that we haven't done,
and some of that was based on
the number of forced outages that we saw on Sunday.
That was more than what we have seen from thermal units
in the past, on a day like that.
And so all week, this week,
Monday, Tuesday, Wednesday and even today,
we have taken out of market actions
to bring more generation online
using the process we call RUC.
So that RUC process,
the reliability unit commitment,
meaning we're looking across what the market has committed
versus what the load is.
And we don't think there's enough there.
And so if we don't think there's enough,
that's partly based on the fact
that we saw as many forced outages
as we did on that one day.
And so we have committed generation
to keep the grid
in a state where,
if those forced outages were to happen again,
we would not be in a bind, basically.
Peter: Right, so that's-
-: We are more conservatively operating the system
at this point,
by making sure we have more reserves online all the time.
-: To make sure I understand this right.
So when you saw the challenges on Sunday
that we were going to be facing, going into Monday,
the decision was made to go,
I guess, above and beyond the normal operating procedure
of ERCOT to call all available generation in Texas?
Woody: Yes.
-: So we're gonna act with an abundance of caution.
And at this moment in time,
we're going to step out of the normal market operations
and say, we're calling all generation
to make sure we have that margin of safety.
We're acting out of an abundance of caution
to make sure that we have the stability we need in the grid?
Is that fair?
-: That's pretty much right,
except for it wouldn't necessarily be all generation
but it will be to a margin
that's more than what we normally kept.
So this rule that we're talking about could apply
to any day, even an off-peak day,
if we don't think that there is enough reserve
on the system, on online,
then we're going to RUC to get there.
And so it might not be every unit.
We might not be bringing every unit on it.
Earlier this week,
it has been every unit. -: Okay.
-: But if it was a 65,000 megawatt day,
it might not be every unit. -: Sure.
-: And this is gonna vary a lot with the wind
and the solar output and the forecast that we expect.
So if we have high wind and high days,
where we have a lot of generation
from those types of resources,
it won't be as critical to RUC those units.
-: Okay, well, I think it's important to highlight that
y'all went above and beyond
normal kind of standard procedure
when you saw this challenge on Sunday,
went ahead and called all of that generation on,
and in out of market action,
to make sure that going into Monday,
a challenging Monday,
Texas had all the power it needed.
I think that's incredibly important.
-: And that'll be our procedure going forward.
-: An abundance of caution.
Thank you for walking us through that.
And I think that's something to highlight
and thank you for your work on that.
-: So while I have Woody here,
I'd like to highlight one fact
and he can verify from the ERCOT perspective,
tools that we have in the toolbox, but for the public,
in terms of what ERCOT faced this week,
did we only set one record or two, successively?
-: We may have set a new weekend record, as well.
-: Exactly, yeah.
I mean, bottom line is
this was a high-load period in the history of the system.
It was hot.
The economy of Texas is kind of coming back.
We're starting to see, it's different than 2020.
COVID had its impacts on load.
Now you're starting to see new growth phenomenons
become apparent.
Is that accurate?
Woody: That is very accurate, yes.
-: All right.
And then it combined
with a high-variability period for intermittent resources,
then combined with forced outages.
So to put it in context for everybody,
there were body blows being dealt to the grid
and our systems still maintained
with only a conservation advisory notice going out,
not an alert, which is an important nuance.
And I know we're going to take great pains
over the summer to delineate
between advisory and alert
which I know folks are scared, after February.
To put it in perspective
and to kind of frame this for legislators
and the government in general and the public,
there has been a policy in Texas
to try to find a Texas way for a long time,
for 30 years,
on integration of intermittent resources, to a large degree,
married up with thermal generation so that hopefully,
they worked together to provide reliability and low prices,
to try to make those two competing forces,
possibly competing forces, work together.
Other ISO's around the country have also attempted this
and are attempting this.
Case in point,
to put it in perspective on conservation capabilities,
the California ISO
has a large amount of intermittent resource penetration
in that market.
Matter of fact, they have a lot of policies designed
to enhance that,
with policy goals at the end of that.
And from the last kind of call
where I was briefed on what they're doing,
they are trying to develop over eight gigawatts
of load resource management programs which,
that's conservation.
I mean, they are telling consumers to pull back
in order to marry up the system reliability
to the policy goals
that they have adopted.
And so my point there,
is this is a common practice
and for the people of Texas,
when you want carbon neutrality,
when you want these new technologies to come in,
we have to keep that in mind
that all these things have to act together.
And again, it's not ERCOT telling people
the system is unreliable.
It's simply, making all this work in tandem
to where the system is maintained
and the greater public good is attained.
And that's my soap box.
But when we were called back over,
that's what's being attempted to be achieved here.
-: Well put. -: Okay.
-: It's a big challenge.
It's a very big challenge.
One last question and we'll let you go.
When you said this'll be talking about
the new policy going forward into the summer,
taking a new approach,
I think this applies to both,
especially to ancillary services, but to RUCing, as well.
So getting, bringing more generation online
as a margin of safety before you need it.
I know we've talked about this
but I want to highlight what that new approach looks like
in terms of
when you establish how much generation you need to have
for that margin of safety.
In the past, it's been a preset formulaic number
based on a lot of variables,
historic demand and things like that.
Now, from what I understand, you're not only,
you're still using that tool,
but you're also bringing in
a much more updated evaluation of real-time conditions
as you look to make sure going into the next day
and the next day after that.
You're looking to make sure that real-time conditions
are being accounted for much more so
than they have in the past.
Is that accurate? -: That's right.
-: That's an incredibly important point,
I want to make sure the public is aware of.
And I know that's a big departure
from the standard operations
that y'all have been using in the past.
And I want to thank you for making that change.
That's incredibly important.
I know that's operationally different
and it's a challenge to implement things like that
but that's incredibly important
and it will serve Texas well this summer.
-: Yeah, well, as our grid changes,
we need to be able to change our procedures
and our processes and our tools
and even the training of our people
in order to meet the new demands of a grid
that doesn't look like the grid we had 15 years ago.
And so it makes sense that we're gonna
make some changes to operate that new grid.
-: Absolutely.
Anything else? -: No, sir.
-: Woody, thank you very much.
-: Thank you.
-: Appreciate your work this week.
At this point,
let's call up Warren Lasher.
-: Good morning, Chairman, Commissioner.
Warren Lasher
for the Electric Reliability Council of Texas.
Peter: Good to see you, Warren.
Thank you for being here.
Warren: Good to be here, thank you.
-: I know we've all, going into the summer,
y'all have done a lot,
always do a lot of work on the CDR on the SARA,
which is, -: Sure.
-: A look ahead
to how much electricity is going to be needed,
how much electricity we're going to have
and all of the moving pieces that go into figuring that out.
Could you give us a quick overview?
And we heard a lot about
the confluence of factors we experienced this week.
A lot of mechanical failure,
unexpected outages of generation,
record-setting demand for electricity in June
we hadn't seen before
and then less wind output than we had expected.
And wind is variable.
That's the nature of that business.
That's something we're aware of.
And I know y'all work very hard to accommodate.
I think it's fair to say that the convergence
of those three things at the same time
are what got us to a pretty tight spot.
Is that accurate?
-: That's correct.
Can you give us a quick overview on how y'all's analysis,
how y'all look at the forecast that we've heard about
and I know Woody touched on it
but just give us a quick overview
of how y'all approach those forecasts.
-: Sure, let me take a brief step back.
We mentioned the capacity demand reserves report
and the seasonal assessments
of the capacity demand reserves report
is a long-term view.
It's meant to allow the calculation of a reserve margin,
the amount of capacity above our expected usage
in the hottest days of summer.
And that allows us to track how reserves change over time.
It's a longer term view.
It's based on kind of average conditions.
There are specific assumptions in both
the capacity demand reserves report
and in the seasonal assessment
regarding the amount of wind that we would expect
on any given peak day
based on historical performance of those resources
and the same for solar,
the same for large industrial customers
who have excess energy that they can sell to the market.
We look at historical data.
The same for,
we have some asynchronous or DC ties
that connect us to other regions
where there's a limited amount
of import and export capability.
We look at historical data to inform us
on what the expected capacity
on usage of those units might be.
So the capacity demand reserves report
looks out over a long-term.
About 10 years ago,
we started producing the seasonal assessment
which really looks, focuses on the next two upcoming seasons
and allows us to look more at scenarios of,
well, what if this happens?
What if that happens?
And for the most part,
those scenarios are based on, again, historical occurrences.
What have we seen?
So going into this summer,
the seasonal assessment looked at what our expectation
for the peak day was,
given our expectation for peak customer demand
on the hottest days of summer.
And again, the amount of wind that we would expect to see,
the amount of solar we would expect to see, et cetera,
based on historical data during peak events.
There were three other scenarios, primary scenarios,
the first of which was, well,
what if we have increased number of forced outages,
these unexpected, unplanned outages on units?
So that was one of the scenarios that we showed.
The next scenario was, well,
what if we have a really hot summer?
So if you look back, the most recent,
very hot summer was 2011.
It happens to be one of the hottest summers
experienced in Texas.
And so the third scenario on that primary scenario page
was what if we have another 2011 type summer?
What will peak customer demand on those hottest days be?
That was the third scenario.
And how much reserves would we expect to have?
And then the fourth scenario was, well,
what if we have very low wind conditions
on a peak like summer day?
And so basically, we separated those conditions into-
-: What was the second one? -: Yeah.
-: You did, one, three and four.
-: No, so the first one is kind of our expectation.
-: Okay, base case? -: The base case.
The second one was increased unexpected outages.
The third was, and now I'm forgetting myself.
The third was a very hot summer.
A 2011 type summer.
And then the fourth was very low wind conditions.
And I should note,
it was that fourth scenario was the only scenario
that indicated the potential for having to go
into emergency conditions due to very low wind conditions.
And the wind conditions in that fourth scenario
were consistent with what we saw earlier this week.
So we really did see that.
And the unexpected, unplanned outage scenario, again,
relatively consistent with what we saw earlier this week.
I think earlier this week,
we actually saw higher levels of unexpected outages.
So unfortunately, we saw both of those on the same day.
-: Two worst case scenarios happened at the same time.
-: Absolutely, correct.
And both of those are,
statistically looking at historical data,
both of those are one in 20 type events.
So like a 95th percentile event.
So, you know, they are unlikely,
they would be unlikely to occur at the same time.
I think to some extent though, you know,
part of what we're seeing
is we're seeing an early June type event.
So, you know, it's a,
the seasonal assessments look across the whole season.
And so, you know, the focus,
I will say the focus of the seasonal assessment
is really July, August, and July, August type conditions.
And, you know, we're in a position
where we're still learning as we go
with some of these new resources,
especially solar, but even wind.
You know, we have a certain amount of historical data
on wind, but it's still fairly limited.
And there may be situations where it becomes clearer
over time, that in June,
the weather conditions are just different
from how they are later in the summer season.
One of the, you know, one of the issues that we have seen
in recent years
is when we have very hot summer events,
especially over Dallas,
that weather pattern sitting over Dallas
tends to extend to a certain amount
out to about Abilene.
But then when you get out into the panhandle,
that hot weather in Dallas actually draws wind
across the panhandle in certain weather conditions.
And so what we have seen is a correlation
between very hot, at the urban centers,
around Dallas and Houston,
and then wind through the panhandle
where we have a lot of wind resources.
That may not be something that we tend to see in June.
We just don't have enough data.
-: So, what is that correlation?
-: I don't have a name for it, but it's just a-
-: I mean, what's the level of correlation?
Do we know?
Is is like 0.2?
-: No, no, I don't know what the level of correlation is
but it's something that we see routinely,
in the July, August timeframe.
-: Is that correlation,
is that correlation taken into account
in real time evaluation looking forward?
So like, if you're looking ahead, if you're-
-: It would be,
the way that would take effect
in terms of the near term outlook would be
our meteorological analysis over the next seven days,
that meteorological analysis drives the wind forecast
for the seven days.
It also drives the customer demand forecast for seven days.
So, it also drives the solar forecast for seven days.
And so that correlation would show up
in the near term forecast that we have for those resources.
And then the correlation would also show up,
as we look back, we would see that on very high demand days
when it's hot in Dallas,
there's also a significant amount of wind
coming off of these resources.
So it would show up in the hindsight look
and in the forecaster look.
-: So, you're saying, it shows up in the data points,
not necessarily, but is there any point in this,
the forward looking analysis
is what is most important, right,
so we can prepare for the conditions
to operate the grid in. -: Correct.
-: Is there, you know,
call it the metroplex panhandle spread
or whatever phenomena you want to call it.
Is there any point in the forward-looking
predictions of load, of wind, et cetera,
where y'all's analysis
or someone on your team kind of raises their hand and say,
hey, the metroplex panhandle spread's in place.
Let's adjust course or is it just a,
it shows up in the data kind of, retroactively?
-: Well, it does show up
in the numbers of the forecast itself
but our meteorologist
pays a specific amount of attention to that.
He really, and specifically,
our meteorologist is kind of looking
at it the other direction.
Our meteorologist is very focused on
days where he feels like the demand is gonna be high,
wind is going to be low,
and solar may be low, as well.
So he has been focusing on that for some time.
And he's also very focused to another level,
he's focused on situations where he feels like
the forecast itself
may have a certain amount of risk associated with it.
Meaning, the demand forecast may have a risk
that it will be higher than we think.
And the wind forecast has a risk
that it may be lower than we think.
So he's looking at it from that perspective, as well.
-: So that's saying,
he's looking at it saying,
on some days, on your four day forecast,
I'm very confident, this is what's going to happen.
There's no perfect crystal ball
but some days he's saying,
I'm pretty confident this is what's going to happen.
But on other days, he's looking ahead and saying,
this is a variety of factors.
I'm really not sure how this is going to play out.
I've got an idea. -: Right.
-: Okay, how does that inform operations?
-: Well, he's in constant communication with operations
and they're looking at it day-to-day in the mornings.
And if there's a reason for an update,
that gets communicated in.
The meteorologist not only has his own, you know,
expert opinion, but he also has a variety
of different forecasts that he's looking at.
So if there is a spread
between some of the different forecasts
that he has available,
he communicates that to the operators
and we talk about our wind forecast.
We talk about our customer demand forecast.
But in reality, we have seven customer demand forecasts
and we have several wind forecasts.
I believe we have two primary wind forecasts
and then we have a ramping forecast, as well.
And so they have the option to select forecasts
that they think best match the upcoming conditions.
And you'll see the operators talking about
well, we think we should select this forecast for today,
but we need this other forecast for tomorrow
and the next day because of exactly these issues
that we're talking about here.
-: So, what did that look like on the Saturday and Sunday,
for example, as it relates to wind?
I know you can't really forecast unplanned outages so-
-: Yeah, I do know there was a lot of chatter back and forth
about which forecast should be selected
and selecting different forecasts
across the span of the day.
Just getting back to what I was saying though, you know,
we see some of these patterns
like this panhandle to Dallas
and also we see, you know, in the late afternoons,
we see the coastal wind picking up, typically.
That's a pattern that we see over the summer
but we just don't have enough data yet to know,
well, is that a pattern we can expect to see
the first two weeks of June?
Does that make sense?
And so, I think that's kind of where we were
in the last few weeks is
we have the seasonal assessments
that are based on seasonal expectations
but when you're in the early part of a season,
there may be some-
Will: It's a different animals than-
-: It could be, it could be a different animal.
-: And that's the nuance.
Like if we kind of take this to the next step
or continue talking about it,
is do we need more micro analysis
to account for your long-term
and short-term trends
for scheduling, for resource management,
for the RUC calculations and stuff like that
on a more specific basis.
And what's the line?
You know, if June is so different,
but July and August and September,
thus, the peak are more akin,
do we need to readjust that?
And that's one of those questions-
-: That's a big question.
And at the highest level,
the overarching question is,
would you say that each one of the,
kind of worst case scenarios,
like low wind,
a lot of unplanned outages. -: Where does it intersect?
-: And high temperatures.
Like each of those is a one in 20, roughly?
-: Yes, roughly. -: Yeah, broad strokes.
One in 20 chance, on any given day,
one of those things will happen, right?
-: Well, I would say across the summer that, you know,
so as an example, the low wind,
the question is are we gonna see low wind
or relatively, you know, significantly reduced wind
on a day that is like the peak, like a peak day.
And so that's the one in 20, right?
-: Right, so.
If you do say two of those things happening,
and we went through this math before,
that's one over 400. -: Yeah, right.
It's getting unlikely.
-: Which in percentage terms
is a quarter of a percent chance.
-: Yeah. -: Happening.
And I feel like this week
wasn't a quarter of a percent chance happening.
And so that's when I said my big high level question is
how can we get better at, you know,
I want to be careful about the statistics.
Like it's less than a quarter of a percent chance happening
but that resets every day. -: Hmm hmm.
-: That's not that it's only going to happen,
every so often.
-: And the other point is, is that again,
the economy is waking up from COVID
and Texas changed a lot.
And Carrie will be able to kind of speak to this
from pricing standpoint and load growth standpoints,
and you can as well,
but what does this look like in a year, after,
Texas is a manufacturing engine for the country.
Petrochemical production comes alive again, you know,
with higher prices.
What does that look like?
And to account for that,
in your seasonal forecast or a more specific basis
to account for your low probability events, I mean-
-: Well, it's apparently not as low probability as-
-: That's the question. -: As we think.
-: Yeah, one other thing I did want to mention, you know,
as you were talking about Texas coming alive, you know,
we've talked about this before.
We have a lot of resources that are under development
or planned under development.
Now a lot of those are solar right now,
specific interest in solar
and then growing interest in batteries, as well.
So as the economy comes back, as customer demand grows,
we're also seeing significant interest in resources.
But one of the interesting things, I think,
again, over the last two weeks,
and looking at this idea of maybe being
a little bit more granular in the analysis,
one of the interesting things is
as those units are coming online,
we're including them if they meet certain timeline cutoffs,
we're including them in the seasonal assessments.
But the first two weeks of June,
they may not be all there yet.
And there were some examples of some of our solar plants
that are expected to be online this summer,
but are not fully online yet
or do not appear to be fully online yet.
So that could have been another factor.
-: That's the example of me thinking
there were 7,000 megawatts when there were in fact six
and again, they're targeting July.
Well, no they're targeting August and September,
that last 26 hours at the transition
to the month when Texas is boiling, you know,
and we know that system-wide offer cap may be attained.
-: Yeah and I would argue,
they're probably coming online
as quickly as they possibly can, but they, you know,
and they may be completely meeting their targets.
But the way this month,
this way the seasonal assessment,
the summer assessment runs,
you know, they don't have to be fully online by June 15th
in order to be included in this assessment.
-: And the other thing I'd say,
what Warren works on with these things.
I mean, it plays into everything
and you could teach me a class on this,
but it is, at a high level,
it impacts the forward prices.
And again, the forward prices are what this market
and Carrie can tell us about it
but that's what pays for the maintenance.
That's what pays for everything.
That's what keeps it going.
And so whatever analysis ERCOT promulgates
on aggregated and even a more targeted basis,
that's the driving force.
And again, how we account for the intermittency.
So as that 20 gigawatts of solar comes in
and how it plays in and how you're accounting for it,
that's going to impact those forwards.
And that's very important.
-: That's very important.
And we certainly,
I think Texas is certainly
willing to compensate private companies
that generate power when we need power.
-: Right.
-: We never argue against that
but also we have to overlay and juxtapose
that with reliability. -: Right.
-: And, you know, it's Monday,
you know, Sunday, Monday, Tuesday
didn't feel like a quarter of a percent chance
and we're still working out, you know,
we're still working through that situation.
And so I want to make sure that
we're using every tool possible
to make sure that we have
not only at a seasonal level,
but we have the best possible visibility
on when the confluence of negative factors can occur.
Wind's variable, we know that,
but we had, I think, what was like Monday,
we expected six or 7,000 megawatts
out of 25,000 total installed and we got 3,600?
That's the nature of wind, that's fine,
but we need to make sure that we're looking at everything,
the correlations, like the, you know,
the DFW panhandle spread
where that's a positive correlation, right.
And that's a mathematically positive correlation
but also a positive for the grid.
And that when high heat in one area
increases demand and puts pressure,
that's offset by increased production
but there are other,
how much visibility do we have into other correlations?
You know, is there a correlation
between high heat and outages?
Is there a correlation between, you know, wind and solar?
I don't know.
Do do we have much visibility on that?
-: Actually, that's something we're starting to look at
and we are really looking for
starting off, obviously, looking for those times
when wind is lower than expected
and solar is lower than expected.
And those,
based on the limited amount of historical data we have,
it indicates that that's unlikely to happen.
Typically, the conditions that drive lower solar,
clouds, fronts, et cetera, drives more wind.
But again, I think one of the issues we face
is that you know,
the data set's very thin.
Peter: We've gotta work with the data we've got.
-: Yeah.
-: But also, I also want to be wary
of averages, relying too heavily on averages.
And that's where it's kind of a statistical trick of the,
you know, even if you have a normal distribution, you know,
some days it's really high wind or high outages,
or, you know, some days it's really low
and you overlay that distribute,
but, you know, on average,
we're kind of in the middle
and you overlay that with outages,
you overlay that with solar,
you overlay that with high temperatures
and it comes out, you kind of mix it all up
and it comes out to this, you know,
a quarter of a percent probability.
If you rely on that, I don't want to just rely on that
and ignore and not be cognizant of the fact
that when it comes to, you know,
averages only work over-
-: Longest data set. -: Lots of iterations.
-: Right, that's right.
-: Kind of infinity interactions, right.
You can flip a coin, heads or tails and, you know,
over time it'll be 50%,
but you can get five tails in a row.
And in the business we're in,
in terms of providing reliability to Texans,
I mean, the math resets every morning
and we don't get infinite flips of the coin.
Every morning, we're skydiving
and you only get one chance for it to go wrong.
And after that, the averages don't matter.
And so, I know there's a lot of serious calculus
that goes into this
but it sounds like we've got a lot of room to improve.
Warren: Absolutely.
-: On within the limits of the data,
evaluating these correlations
and also making sure we evaluate the correlations
between different factors,
but also auto correlations within the single factors
and how that can inform our improving our predictions.
And then also make sure those,
that best information, that best analysis,
informs operations.
I know, one of the highlights
I made sure Woody pointed out was that
ERCOT is taking a new approach
to making sure those real-time conditions that we're seeing
inform the margin of safety.
So we're now taking a look at
what does the next 24 hours look like?
What does the next 48 hours look like?
And that's what happened on Sunday.
Y'all looked at it,
went above and beyond the standard formula
and made sure that we had as much generation
as we possibly could. -: Sure.
-: And we still hit peak.
I mean, money was still made in the market.
And, you know, and the other thing
that's feeding into this is capital markets,
like a long term range
of revenues that can be made.
And they like stability in that.
And so, again, as you start to analyze this
and you start to analyze correlations between,
for instance,
high intermittency volatility
and forced outage rates.
You know, are things breaking
because of traumatic fluctuations in power?
Because again, coal plants are not designed
to ramp up quickly.
I mean, they get beat up that way.
And especially, the age of the fleet.
I've been pointing out to policymakers,
we do have a gas fleet that was installed
between 1995 and 2007, 2005.
So they're 20 years old.
So what's that doing to the fleet?
And how's that being baked into your outage number?
Because I know a lot of people were talking about that.
But again, how you're weighting some of these things
and when they produce,
that's gonna affect forward projections
on how much money can be made on a regular basis,
possibly over a broader period of time, not just at peak.
I think we're looking at a broader,
profitable period for the ERCOT market.
-: Yeah, I agree with that.
Your scarcity conditions aren't gonna be driven
specifically by your peak customer demand.
(overlapping chattering)
-: Anything else for Warren? -: No, sir.
-: Thank you very much.
I appreciate you being here.
-: Yeah, yeah, my pleasure.
-: All right, Carrie,
do you have any thoughts you'd like to contribute
or share on, especially, related to the outages
and potential for market manipulation?
-: Sure. -: And how to mitigate that?
-: This is Carrie Bevins with the Independent Market Monitor.
Part of our role is to detect market manipulation.
And we will study this weather event
or market event,
just like we would any market event.
You know, we look at it from the market side.
So whereas, you know,
other entities might look from a reliability side.
We're looking to see, you know,
we have tools and we have things that we look at
to determine if there is any evidence
that there was physical withholding.
So that would be entities using their,
exercising their market power by, you know,
withholding some generation from the market
so that the rest of their fleet is profitable.
I will say just, stepping back and looking at, you know,
we look a lot at incentives
and the incentives for
physical withholding are lower than they might otherwise be
because we have the low cap in place right now, right?
So it's a big risk to take,
to try to effectuate that
and you're not gonna get as much profit out of your fleet
as you might have with a $9,000 offer cap, say.
So I don't think the conditions are necessarily ripe
from that perspective,
from an incentive perspective,
but we will perform our investigation.
And if we find anything,
we'll refer it to the Commission for enforcement.
-: Excellent.
That's very important to make sure
people aren't gaming the system by withholding generation,
electric generation when Texas needs it.
Connie: Absolutely.
-: What's the rough, I know this is all in real time
and fast moving,
a sense of a rough timeline we could expect?
-: It'd probably be a couple months
because we will need to issue some requests for information.
We have to do a deep dive into that information.
And, you know, I don't want to talk publicly
too much about our methods, but, you know,
it does take some time.
Peter: Fair enough.
-: In terms of your access to,
again, we were speaking of the 60 day
moratorium on access to information.
You get special exemption to that, correct?
-: We're centrally within the ERCOT firewall,
meaning we can see anything that EROCT can see.
-: Okay and so you'll be able to see near term,
whether there were any concentrations of forced outages
as a part of this within any particular market participants?
-: Yes. -: Okay.
Do you have any thoughts on,
because again, you do, I mean,
competition is your business.
On the 60 day issue,
like what, you know, what should we consider?
-: Yeah, I think, so number one,
the ERCOT ISO has some of the most transparent data roles
amongst the ISOs.
So there's already a lot of transparency there.
And some of that had to do with, you know,
kind of, you know,
in exchange for these also high offer caps that, you know,
you are in the market,
you also have this kind of radical transparency
on the other side.
And there's definitely some benefits to that
is that, you know, sunlight is always good
and your competitors are keeping you in check
just as much as I am, right, in some respects.
So, but there are some concerns, definitely,
in the shorter term.
If you are aware of, and here,
we're mostly talking about transmission problems
but if you're aware that, you know,
one of your competitors is outaged
and won't be back for a certain number,
it's that knowledge of when you might be back
that you can use your advantage
to perhaps increase your offer,
increase your profits above a competitive level.
And that would be our concern with that.
But I can say that, as you spoke to,
there are products in the private market
in which you can get a lot of this information
and wouldn't necessarily have strong concerns
with maybe some one-off disclosures.
But I think as a procedure
as we go through time,
it's better to have that, you know,
whether 60 days is the right number, you know,
we can certainly have that discussion,
but some sort of period in which that data is not disclosed.
But for one-off events,
I think there's probably not a massive concern,
a competitive concern on that.
-: In terms of,
I'm assuming you've already started digging in,
in terms of financial analysis,
do you happen to know off the top of your head,
because it is something that we need to watch?
A lot of generators lost money this week.
The breakage was both physical and financial,
I think is fair to say.
Do you happen to know ballpark what the penalties incurred
and not any particular market participant
but on aggregate,
what we're looking at in the ERCOT market?
I mean, we just came out of February.
So I'm wondering the health of the system.
-: Sure. -: And what we're seeing.
-: I'd be happy to share that information with you later.
We are still waiting for,
it takes days after the event
for like meter data and things like that to come through
for us to get an accurate picture of net financial position.
So we're going to need probably until next week,
until we have a good point of view
and I'd be happy to follow up with you-
-: Yeah, we're still dealing with a lot of outages, today,
so we're not through yet.
Connie: We're not of the woods, yet.
-: So, obviously, take the time you need to.
Let's get through the event. -: Yep.
That's all I have. -: All right.
Thank you, Carrie. -: Sure thing.
-: I don't have anything else on 11.
Do you? -: No, sir.
-: And I don't have anything on items 12 through 16.
Do you? -: I don't.
-: Good morning's work.
There being no further business of this meeting,
we will not meet in closed session today.
-: No, sir.
-: So having no further businesses,
meeting of the Public Utility Commission of Texas
is hereby adjourned.
(gavel bangs)