(item:0:Chairman Gleeson calls meeting to order) 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 for
August 15, 2024. Good morning,
Shelah, Connie, Barksdale.
Connie, did you ask to have the air
conditioning turned off or what's going on here? I've been freezing all week.
Okay, so this is your fault. Absolutely. I just want to confirm. Melanie
just took care of it and it should be cooling down soon.
Okay. Well as I see it, if that clock back there is correct.
It's about 75 degrees and 49% humidity. So I would say
if people want to take their jackets off if they're wearing them, feel free.
I saw Barksdale leading the charge. Then I saw Eric didn't know what to do.
He took it off, then he put it back on. We don't want to confuse
anybody. Yeah. So feel free,
folks. It's rather uncomfortable in here.
So, good morning everyone. I think Commissioners, if it's okay
I know we've got Centerpoint here. I think maybe take things out of order again
like we've done in previous open meetings. Maybe take up
51, 52, and 58 first so that they
can come up and we can ask questions. I know they filed a lot of
information about mobile gen. And then I propose we take up
43 and 44 of the two rules related to the storm response.
That we have up at this open meeting, if that's all right with y'all?
Okay. (item:51:Chairman Gleeson lays out Project No. 56793) Then I would call up Items
51, 52, and 58. That is Project
No. 56793, Issues related to the disaster
resulting from Hurricane Beryl. (item:52:Chairman Gleeson lays out Project No. 56822) Project number 56822,
investigation of emergency preparedness and response by utilities
in Houston and surrounding communities. (item:58:Chairman Gleeson lays out discussion & possible action regarding customer service issues) And then 58 is discussion and
possible action regarding customer service issues, including, but not limited
to, correspondence and complaint issues. Jason,
if you want to come up and whomever else you brought.
(item:51:Jason Ryan, CenterPoint's Executive VP's update on action plan, 56793) Good morning and thank you, Chairman Gleason and Commissioners. I'm Jason
Ryan, Executive Vice president at CenterPoint Energy.
Thank you for the opportunity to speak with you today about how we use
temporary emergency generation during Hurricane Beryl. With me
today is Eric Easton. Eric is an Officer and part of
our Electric Operations, including these assets that we're going to
be talking about today. Many of you may have met Eric before
he operated our system during Winter Storm Uri and executed
the ERCOT load shed orders at that time.
Now, part of his responsibility is bringing Texans back on
line with power with these temporary emergency generation assets.
I wanted to cover three things with you today before
taking questions, if that's okay. Thought I'd provide an update
of where we are on our action plan since we
last visited on July 25. I thought then
I could provide a little bit of background on these
temporary emergency generation assets and the risks that we mitigate
with them. And then I'll provide a walkthrough
of the material that we filed on Monday in response to Miss
Corona's questions. That was filed in Project
56793, and it's Item 24
there. We did file a letter this morning. It's item
25 in that same project that does a little bit of that walkthrough.
But I thought I'd provide some context to you and the public
on what that information is. So I'll cover those three things, if that's okay.
Perfect. All right. So first, let me start with the update. Since we
were in front of you on the July 25,
we presented at that point our
action plan to address the remainder of the hurricane
season and take us to the end of the year with some field
activity, better communications, better operations more
generally. Shortly after that, we accelerated
that work. So we are now completing
most of that work instead of by end of year this
month. So we had some deadlines that we
hit on August 9, some deadlines that are today,
August 15, many more deadlines by
end of the month. And then a couple of things that continue
beyond that. I know that we need to provide
to you a complete set of
information on how we mark some of those activities.
Complete. And, and so we're also pulling that information together to
provide to you in this project. Let me
give you a couple of examples of some of the work that we're completing
this month. I'll focus on some of the stuff that's out in the communities that's
most visible to our customers and to our
communities. So, for example, we decided
to trim trees along 2000 miles of
distribution line and complete that this month instead of complete it by end
of year. We are 943
miles into that work as of end of
day yesterday. So we are on track to
meet that goal of trimming the 2000 miles of distribution lines
by end of month. Those were the highest risk miles.
So these are the miles where you
get the most bang for your buck, so to speak, on trimming
vegetation. To put that in perspective, you know, the distance between
Houston and El Paso is a
little, you know, 750 miles or so.
So 2000 miles of distribution line that's trimmed
this month is the equivalent of our line workers going from
Houston to El Paso and back to Houston and then some more.
So it's a lot of work that
the men and women out in the field are completing every day,
again proud of what they've accomplished so far with zero
safety incidents and look forward to continuing
to complete that work again with that same safety track record.
The other major thing that we're doing out in the field is replacing
1000 distribution poles that are wooden that
are scheduled for replacement this year. We're replacing those
wooden poles with composite poles and we are
640 poles into it as of end of day yesterday.
So again, well on track to complete that work.
But like I said, with respect to the 40 plus commitments in
our August work plan, we will pull together the
documentation of how we consider those complete.
Just an example, as of today is our deadline to
relaunch our right tree right place initiative. That's the initiative where
we educate the public about not
putting trees that grow really tall right under our power lines. Instead provide
them with information about planting the right tree in the right place
if they want something closer to the, to the power lines.
We need to show you guys how, how we are marking that
complete. And so like I said, we will pull that information
together and file it in Project 56793 in
the coming days. So as
part of our commitment to transparency, we've been providing your office and
members of the Legislature and the Governor's Office some updates
on that activity. We will provide you another update
tomorrow on where we are, and we'll provide an update every
Friday until the end of the month.
We then will quickly pivot to our next phase
of this work so we know that we're not done at the end of
August when we complete this work. So we'll be sharing with you our
work plan for the remainder of hurricane season,
how we're going to be prepared for the Winter season
and what we're going to do leading up to next hurricane season, and then
longer term after that for greater resilience.
Before I address the main topic of today,
the temporary emergency generation, I want to pause and see if there are any questions
at this point on that August work plan or our plan to
continue to update you and provide transparency on the complete items.
Sure, Commissioners? (item:51:Commissioners comments on CenterPoint's action plan, 56793) Jason, thank you for that update.
I've been working with Connie on the creating this framework
for showing the how the action items have
been completed, and I think that that'll make a lot
of sense so that the public and we and
the legislature know the how and the completion of the action items. So I
think it'll ultimately be a positive effect to show
if, you know, you say you're out there doing a lot of hard work and
getting all this stuff done and we're all moving to, you know,
we're all on the same mission. Right. You want to provide continuous
and adequate service for your customers. You want to sort of fix the issues that
happen after the hurricane. And we want the same thing. So this
is, this is your action plan you came up with and the,
showing the, how I think is going to be very important for everybody. So I
appreciate you working with Connie. And Connie, thank you for getting the center point and
creating this process. Thank you.
I just have one question. So on your action plan,
and you've given us a progress report on the field activity,
the trimming of the trees and then the conversion from the
wooden poles to the composite poles. And you mentioned that
these were the highest,
I guess, priority risk associated miles.
And so my question was, okay, we've obviously had those areas that were impacted
in the path of barrel, but the concern,
of course, is that we have the remainder of hurricane season. And so there
are some areas that would be at risk beyond just
that path that happened previously. And so in
this action plan, is this something that is addressing,
you know, your service area as a whole?
Yes, ma'am. And so, and that gets to the, to the point of we
need to share with you all and the public what our
plan is after August. You know, we targeted the 2000 riskiest
miles of our distribution lines. There is
more work to do after that. And we need to lay that out
transparently so that everybody knows what we're going to be doing.
And we've been engaging with customers that are impacted by that work
in a better way than we have in the past in terms of letting them
know that we're going to be in their neighborhood, that they could experience
some outages with some of this field work. And so we
can, when we provide the next phase of
work starting in September, we will be addressing
the entire area as we continue
to trim the riskiest miles that are left after these first 2000.
So the riskiest miles were beyond just the,
this initial 2000 miles was
beyond just the barrel impact as well as the poles.
So when would you anticipate? I guess again,
thinking about, you know, wanting to make sure during this hurricane season
that the entire service area, as much as we can,
has, you know, we've mitigated that risk or y'all have
mitigated that risk. So what would you anticipate in
terms of meeting that expectation during this hurricane
season? Yes, ma'am. And I may ask Eric,
he's been pulling together the next phase of our action plan to see
if he has something that he can share on that right now. I know we
plan to finalize that by next
week, but if there's anything early to share, I'll let Eric do that.
Sure. (item:51:Eric Easton, CenterPoint's VP of Grid Transformation Investment Strategy, 56793) Eric Easton, Vice President of Grid Transformation Investment Strategy,
so let me go back to just how we selected the risky
miles. So we looked at vegetation and its proximity to
our circuits. We also looked at the outage
concentrations that occurred during Hurricane Beryl and
also kind of consider where in the service territory
those outages occurred. Were they on critical circuits?
Do we have critical customers on those circuits? So that's the
prioritization process that will continue when you
look at the miles that we're trimming. So the 2000 miles are really
across our entire service territory. That's not just one particular area.
And some of that is going to continue as we go into
the next phase. So we look at how many
instances there are of vegetation encroachment for a given circuit
mile and that helps us to prioritize. So we'll keep working down that,
listen. And expanding out to the less risky circuits,
but really prioritizing across all 1800 feeders
that we have. Yeah, I think my concern is that, you know, we've obviously
had, you know, a four court press here, right. In terms
of, you know, the recovery process, but want to make sure
that we are kind of continuing that during this current hurricane
season so that we can mitigate as much risk as we can outside
of the area that was recently impacted. That's correct. And really we had
impacts across our entire footprint. So when we talk about the
path of the storm, it impacted all
of our system. It's just that some had higher concentrations
and that was usually where we saw higher concentrations
of vegetation and then also where we had higher soil
moisture. And so in those areas we saw more trees that
actually blew over because of those two conditions.
The result of the droughts that were stressing the trees and
then winter storm yury that stressed the trees and then the excess
rainfall this year. And so those are some of the areas that we focused on,
but we are continuing to prioritize those
locations. And then we are also from a resource perspective,
evaluating how many of the resources that we have on hand today
will stay and that's what's going, going to come out in the next portion of
the plan that Jason was talking about. Good. I think that's
very important that we, you know, we continue to focus on this and
that we get, you know, as resilient as we can in
this current hurricane season. Right. For the areas
that are potentially impacted, that are kind of left over after the
action plan is resolved in the first phase. Thank you.
Are we asking about anything except for mobilegen right now?
So I think, yeah, anything private that they've gone over. And if it's not a
part, I would say if it's not a part of their prepared remarks and you
want to touch on it, go ahead and talk about it. Now.
(item:51:Commissioners questions for CenterPoint on rate payer costs, 56793) Couple questions.
I'm worried a little bit about how the costs
that right payers are going to see are
validated, audited, understood to be
fair, and that
might be as a result of if you all are going
to file a securitization or your next base rate
proceeding, how do
you all audit these third party costs? So if you're hiring,
if you've got 3000 veg management crews out
there, how are you auditing that to make sure that
those costs are within the parentheses that you put
on that? Or is that a blank check that says
trim, go trim, we'll pay whatever.
Yes, sir. So maybe I'll address it in two different contexts.
One, mutual assistance for a storm,
and then maybe the current activity that
continues to use crews external to our own.
So, and I'll speak directly
to the de Racho in May and to Beryl. So as
we get invoices in from the men and women that
came into the Houston area to help us restore power,
our internal audit department will
help us come up with the right process to review
that. We will review it for things that
look excessive to us and
we won't pay those costs that look excessive to us. But you have to realize
in that situation, there could be hotel rooms that were more expensive,
things that might, in an emergency context,
you might spend money on that you wouldn't in a normal context.
So we take that into account, but we won't pay unreasonable
costs to those men and women that came and I
in to help us. So we will have our internal audit department
leading a process. We will also hire an external audit firm
to look at our work and provide
testimony in the proceeding to determine
what costs are reasonable ultimately. So you'll have that two
layer check. Our internal audit team, which reports
to our board, not to, only to management,
and then the external audit firm as well, that we're going through
a process right now to select as
it relates to things like food and lodging
for those crews where we provide that,
we will scrutinize any food or lodging expenses
beyond that and whether or not we should pay that
and whether that was reasonable. So that's an example of some of
the things that our folks will look at. We do
have some mutual assistance crews that are self contained
where they provide their own lodging, their own food. It's important
that we have both types of mutual
assistance crews. And so for those crews that we do not provide lodging
and provide food, we would expect them to submit
invoices for that. And we will look at that tomorrow, make sure that we think
that those were reasonable costs. Ultimately, it's not our judgment,
though, on what's reasonable. Even though we're going to have internal audit, external audit.
We will then have a process here at the commission for
intervening parties and the staff to look over that and
get their opinion on what's reasonable in this work
that we're doing right now.
Some work that we're doing is still related
to hurricane barrel. So, for example,
you could have a distribution pole that's leaning but didn't cause
an outage, but we need to fix that work. So we
did continue some external
crews to help us complete that work.
But maybe let me speak to the vegetation work that we're doing right now.
A very similar process to mutual assistance during a storm.
We have staging sites set up. We have arranged hotels
for some of them. We have arranged meals for some of them,
but not all of them. Right. So you're still going to have those two types
of crews, some that are self contained, some that we're providing things
for. And so we will go through that same process to
review costs before we pay them. And then to
the extent that any of these costs are recoverable, most of them will not be.
To the extent these costs are recoverable, they would go through that same kind of
review process. And what I mean by that, we know that
there is not a vegetation management tracker that
exists right now. And so for a lot of the vegetation
management work, that is on our dime. So that's
why I say for the stuff that's ongoing, that's recoverable, there'll be
a process for the stuff that's ongoing that's not recoverable. We're paying
that. I appreciate that.
I hope the audits are separate
for like the directo and
barrel so we can look at those in terms of very specific amounts
associated with those events.
I have heard twice that that mutual assistance
companies have created their own man camps and brought in their own
food and all of that. And I'm not here
to say whether that's right or wrong, but I think the
ratepayers deserve to know if those costs are in line with
what you're expecting from the guys that come in from Michigan and the guys that
come in from Louisiana. And so I hope
that you all will be looking at holistically.
We don't. When we want mutual assistance, folks, gosh knows we need
them now. So we don't
want to do things that make mutual assistance harder.
But the ratepayers deserve every audited, every component,
every nickel scrutinized so that we
can ensure that they're getting the best service. Yes,
sir. And we do plan to file separately the
Mayenne de Racho costs versus
the hurricane barrel costs. So we won't be
conflating the two events.
Most likely that de Racho storm cost
proceeding occurs or begins
Q4. But we're still getting invoices from that
event. So it will take us a while
longer to get the invoices and go through the audit process,
both internal and external, for the. For hurricane barrel.
So I wouldn't expect that to be until well into next
year. I'm sorry, I think I cut you off. Oh,
no, no. I was. But I do have a follow up question,
actually, because Commissioner Glotfelty, he did raise a good point on the cost
impact of all the actions in the plan. Obviously, they need to be taken to
get us through hurricane season safely.
And so. But with respect to costs for
technologies like the automated
devices, AI, all of that, are you following a similar process
and ensuring that, you know, you're evaluating costs and picking
the most effective but also cost effective solution from that standpoint?
Yes, ma'am. And then that will also be the subject of, you know,
we have the burden of proving that what we're doing
there and investing in technology wise is prudent.
And so the time that we come in to seek
recovery of those investments, we bear that burden of proof.
Folks like my colleague Eric will be providing testimony to explain
how we chose, what we chose, why we think that was the
right solution, and what the benefits are
versus the costs of adopting those solutions.
So typically, you don't do that in a DCRF unless
the presiding officer orders that the prudence
be determined in that case. So it could be as early as
a DCRF filing. It would be no later than,
you know, the next rate case where all that capital
is looked up for prudence and the actual cost.
Right. So the actual cost of all of these measures that
will ultimately be read for prudence. That's right. I think it'd also be good to,
if you included in that cost that you denied in
some way. So if you found excessive,
it doesn't have to be line item. But, you know,
it would be good to have an understanding of how maybe
it's a metric on thoroughness of the audit function that you're finding some things
I don't know, but that might be a good thing to add.
Yes, sir. So this entire process ought to be very transparent,
and I think that it's consistent with what you just said. We should line
item the things that we did not pay because we didn't think it was reasonable.
We should then make sure our external auditor is doing the same thing
when they're reviewing our homework internally so that
everybody can see the work that's already done. You don't have to trust us
that that work was done and we agree.
We'll be very transparent in those proceedings. Thank you.
Okay, Jason, go ahead. And before I move on to the emergency generation topic.
(item:51:Jason Ryan gives information on CenterPoint Open Houses, 56793) Let me just do a plug, if I could, for the open houses that
are starting this Saturday. We're hosting 16 of
them around the greater Houston area to get customer feedback,
to demonstrate our new outage tracker, to help people sign up
for power alert service if they're not already, and get a lot of other information
at the same time that we're getting their feedback. I appreciate
the Commission seeking feedback as well.
And so I think all of that feedback brought together will help
us ensure that it's not just our ideas that we're implementing,
but we're getting that feedback from our customers so that 16 town
halls open house events in
August and September and so we'll report back.
I know that many of you will attend as well. We'll report
back in our status reports how those are going and
obviously make any changes that are needed. If this is not convenient
times for our customers. We did split them, some on the weekends,
some on weekdays, some during the day, some in the evenings. We will
pivot if we need to, if this is not meeting the needs of our customers,
to make sure that they can give us that feedback. And the locations are spread
throughout your service territory? Yes, sir. There's at least one open
house in every county, so we cover twelve counties
and then we're doing a number of them in Harris county. As you
would expect, we may decide
that we need to add some over time.
So I wouldn't take this list as a
set list. That is never going to change. If we need to
continue doing them past September, we will. If we need to add
more coverage in particular areas, we will.
And we will report on that along with our other activities
that we report on. Can I ask a question about that just
real quick kind, did you have something you want to add? Before we go
into the mobile general discussion, I'd like to recap
the work that we're doing with Centerpoint on their commitment list.
I was just going to ask, so when you have these open meetings
and a customer comes up and complains or
says, tells their story, what do you do
with that afterwards? Do you like Chevy
Chase at the Grand Canyon and go, okay. Or do you take
that and have their address and tie it into a system where you
know what their challenges were and you can geo reference that and
go back and talk to them? Or do you aggregate all that
and try to figure it out and normalize it? What do you do after that?
Yeah, so I suspect we'll get feedback
in at least three different ways at these events.
Some of them will be through more informal discussions as
we interact with our customers. Our entire leadership
team and several hundred of our employees will be
attending the to help both guide customers
through the various
stations to get information and also the various places to provide their feedback.
So I suspect it'll come up in conversation that's less formal. But there
will be at least two different ways of formally providing
feedback at those open houses. One through actually
writing down or entering in comments if they want to formally
lodge comments. There will also be
a less formal but still documented way of providing
feedback in a more interactive way at
some of these stations. And we will obviously,
for the conversations, we will be following up with our
employees and our leadership to get downloads of
generally, what was the topic, what were the ideas?
But these more formal ways clearly are documenting addresses,
more information about the customers. Those are more formal ways, very similar to
what you all are doing in terms of formal written comments.
We want to make sure that we're getting all of that. We also will
have interpreters at many of these open
houses so that for people that speak Spanish or Vietnamese,
Houston is a very diverse community. We want to make sure we're not leaving out
members of our community, so we'll have that
option as well at many of the locations.
I think back at my time when we were building transmission lines and we were
doing right away work, talking with different landowners or having
public open houses, and we
strived or strove, I don't know what the word is,
to get as much information as we possibly could from everybody,
and we geo referenced that in a database so that we
could go back and actually look at them and see if we solve their
problem and then let them know if we solve their problem.
I just. I hope that you all can be thinking forward like that in a
way that keeps that customer involved and
up to date. Yes, sir. As opposed to just they come
and complain and don't hear anything. Understood. And very similar to
how we run these kinds of feedback sessions
for transmission lines. We do want our customers feedback,
just like we want landowner feedback when we're
talking about transmission lines, so that we can change our
route based on that landowner feedback. So we really do want
that feedback. That's why we make sure that we have both
informal ways. If somebody doesn't want to actually write something out or type
something out, but if they do, we welcome that. And if they
do these more interactive ways as well,
and one of the good things about helping them
sign up for things like power alert services, then we will have their contact
information and can follow back up with them. So we
definitely. One of the reasons why I want to pitch this while I have the
microphone is to make sure that people know about these.
There's been some local media coverage today about these kicking off,
and we'll continue to use our social media channels to make sure our
customers stay aware. Nextdoor apps, things like that. Stay aware
as these things occur over the next 45 days. Thank you.
(item:51:Connie Corona, PUC Executive Director gives recap of their work with CenterPoint) Thank you. So, just to recap what we're working
on, we've heard testimony from
Mr. Ryan and others here at the Commission, at the Legislature.
They provided some progress reports
in writing. There's a website,
and all of that is a lot of information.
And what we are seeking is to have it compiled
into a single list with an
expected completion date, a progress report,
and a description of how
the progress was made and how the completion was
measured. So our Staff is working on that with
Mr. Ryan and the company. (item:51:Chairman Gleeson confirms the Commission's Open Meeting in Houston) Thank you,
Connie. And now is probably maybe a good time to mention we
too are going to hold an open meeting, a Commission
led work session in Houston. I believe, Saturday, October 5.
I think at this point, after all of your open houses are done, where we'll
hear from invited guests as well as the public
relating to the issues from barrel. I know.
Do you know Barksdale or Connie? Do you know how many responses we've
gotten from the public at this point in the portal we
opened? Good morning, Commissioners. The last
time I checked, it was approaching 15,000.
So firm agenda and date and
time still to be determined. I think we're working with the Mayor's office in Houston
to figure all that out, but we'll be providing that information as it
becomes available. All right. Jason, if you want to continue.
Yes, sir. Thank you. (item:51:Jason Ryan on CenterPoint's temporary emergency generation assets) And I'll be brief, but I do think it'd
be helpful to give a little bit of background about
the temporary emergency generation assets that we have and the
risks that we're mitigating with them.
So, as you know, we've leased small,
medium and large temporary emergency generation
units to mitigate a number of
risks that I'll go through subsequent to legislation that passed
in 2021 in the aftermath of Winter Storm Uri,
and then that legislation was clarified in
2023. So one of the
risks, obviously, that we mitigate with primarily the large
units is load shed. Again, this legislation came
in the aftermath of Winter Storm Uri,
where we in Houston had to
turn off 5000 customer usage
during that event. There are a couple of unique characteristics
of Houston that I think are important to
understand the fleet of generation assets
that we do have. One of them is we have the largest
petrochemical complex on the planet in Houston, and we
do not rotate outages to those large
industrial customers for public safety and other reasons.
So when we have to shed 5000
load, that burden falls completely on residential
and small commercial customers. So you've got a fairly large
number of amount of usage that is not subject to load
shed. Right. We don't load shed transmission level customers, and we have a
lot of those. So that
helps to explain, to some extent,
the amount of these assets that we have. And Eric can speak to
how we reanalyze how many megawatts of these
large units we need to have to mitigate the risk of another
load shed like winter Storm Uri.
We'll talk a little bit about how we used our smaller and medium sized units
during barrel, but maybe I'll talk about
how some of the other risks that we
mitigate with these large units, because that's been the focus of
a lot of attention. So we're
relatively small, right. We cover less than 3% of the area of
Texas, but we consume 25% of the
power in ERCOT in Houston,
and there's not enough power in Houston to power Houston.
We have to import power from other parts of the state and
bring it into the Houston area because there's not sufficient generation
in Houston to power Houston. Those large
transmission lines go well outside of the greater
Houston area. So to the North,
we go more than halfway to Dallas. To the
Southwest, we go well past the Colorado River.
And so if there were a tornado,
a wildfire, a de Racho, even a hurricane that
didn't hit directly into Houston, that took out
those large transmission paths into Houston,
we would have a Houston area problem.
ERCOT might have enough generation to serve Houston, but if you take
out those transmission lines that we used to import about 60% of
the power that that Houston consumes, we've got a problem.
These large units mitigate against that risk as well.
So what this means in reality, is that when these
extreme events happen, you're not
likely to ever use every asset in our
fleet of temporary emergency generation during each
one event. Just like you don't use every
tool in your toolbox at home to do a project, but you
need all of the tools because you might do a different project the next
weekend, right? So if we think about these as tools in our toolbox,
they're all there to mitigate different risks. Some of them are quite
substantial in terms of the impact,
if they occurred because of some of those unique characteristics
of the Houston area, in terms of a
disproportionate number of our residential customers bearing load shed
because we can't turn industrial customers off, the fact that we import 60%
of our power on power lines that extend well beyond
our area. So we have not,
and I guess maybe one other risk is if we
can't import 100% of the power into Houston on these transmission lines,
we don't have enough capacity. If there was a significant loss of generation in Houston,
a fire at a traditional generation facility,
for example, again, you could have a localized load shed
event in Houston that could
last for some time if that's a catastrophic loss of a
generation asset. So we have not done
a good enough job of articulating these various
risks that these assets are there to mitigate.
So I wanted to lay those out here today, and as we do
our work to communicate
better and more transparently, you'll see
us talking more about this in a more consumable
way.
We are constantly assessing the risks and
making sure that we have the right sized fleet. Again, ERCOT can
go into more detail about that as
we go forward. We make a filing every year to adjust the
cost of these assets, but we don't include this analysis
that we constantly do to determine what size of the
fleet. It's our commitment to start including
that, and along with an independent
assessment, if stakeholders think that that would be helpful as
well. ERCOT and his team does look at this,
but we don't share that. So we
can't assume that people will believe us, that we look at it and have the
right size fleet to manage all of these risks, we need to start sharing that.
So it's our commitment to start doing that on a
go forward basis. Including, like I said, with the independent analysis.
And then as the Texas Energy Fund generators
start to come online, you know,
it's our hope that we won't need the same size fleet of
large generation assets that we currently have.
This lease ends in 2029.
These energy fund generators should be coming online before
then around that time. And so we
need to take that into account in our periodic analysis
as well. And if we need to end those leases early, that's what
the analysis shows, then we'll work to do that.
Also, since affordability of
what you can think of as an insurance policy with some of these larger units,
affordability is something that we always
want to continue to have a dialogue about. So we
extended the recovery period of these assets,
I think, twice now, to again lower the monthly payment
that's impacting customer bills. And we
continue to remain willing to engage
in those conversations if we need to. Again,
based on all of the storm costs and other costs
impacting customer bills, if we need to address the amortization period of this
cost recovery for these larger assets, very willing
to engage in that discussion in our next periodic update
as well. We're also supportive of having a
policy discussion on whether or not we should be the ones to continue to mitigate
this risk. Obviously, post Winter Storm Uri,
we were given the ability to have these tools in our toolbox.
We think we have the right tools in the toolbox for the various risks that
we uniquely face in Houston, but we're open to having that
dialogue on whether or not we should continue to mitigate those
risks with these tools. So,
in summary, and then I'll move on to the material that we provided.
We want to be more transparent about why we have what we have. We will
file our periodic analysis every time
we adjust the rider that is associated with this or on whatever frequency
you all think is helpful. Happy to have an independent assessment
as well to validate or contest what we think
about. Happy to continue to update that
as energy fund assets come online or get greater clarity
on when they will come online. Happy to talk
about the amortization period, and then happy to talk about more holistically,
should we be in this business of filling
the gap to mitigate these risks? With that,
I do want to talk about what we filed on Monday, but happy to
pass pause there. First, why don't you go into what you filed and we
can finish up with questions. Yes, sir. (item:51:Jason Ryan on their filing under Project 56793) So again, in Project 56793,
Item No. 24 is
about 250 pages of information that we filed in response to Miss
Corona's five questions. And then Item No.
25 is a letter that we filed today to make
that information a little bit more consumable. It is a lot of information.
So let me walk through what's there. Most of
the 250 pages relates to question one, so I promise
not to spend as much time on each of the five questions. It'll go pretty
quickly after I walk through question one.
But the initial 232 pages
of that are the leases for the assets that we've been talking
about. The first pages,
four through 52, are the short term
lease and any amendments to that lease that
we entered into right as the law became effective
in 2021 for the large and medium sized
units, we wanted to make sure before
we went through a full long term lease process that
we had units in place that could be helpful both during the
remainder of the 2021 hurricane season and as we
got ready to be prepared for the next winter
season, which was the one immediately following Yuri. And so
that short term lease allowed us to start getting these assets
in hand. We used one of them a
couple weeks later, Hurricane Nicholas hit. In mid September of
2021. We used one of the first assets that we took possession
of down in Brazoria County,
and then we took possession of some of these larger units and got them ready
at our substations in the event there was another load shed event
like Winter Storm Uri, we then entered into a longer term
lease. That's what's on pages 53
to 174.
That long term lease is the lease that I mentioned that goes to
2029. You will see a
number of amendments to both the short term lease and the long term lease,
and I'm happy to walk through any questions around that.
But I'll give you an overview of what was going on that caused so many
amendments. There were really two key things.
Number one, the units
that were leased under the short term lease ultimately needed to
move to the long term lease. And so sometimes there
are amendments to the short term lease removing assets,
and then there's a corresponding amendment to the long term lease
adding those assets to the long term lease. So we essentially took that short term
fleet over time and moved it under the long term
lease as the vendor that we leased from was
able to prove to us that they had clear title to those units
because we wanted to make sure that we and our customers had the protection
that these units were going to be there when they were needed
and that the vendor had clear title to them. So as they provided
clear title, we amended the short term lease to take it out from there,
added it to the long term lease there are a number of other
protections, letters of credit, escrow accounts,
things like that, where we were holding the vendor financially
accountable to make sure that they could perform to
our expectations. So you see various amendments over
time, increasing or decreasing those
letter of credit and escrow amounts
to make sure that this vendor could financially
perform and operationally perform, because we had remedies
under the contract that allowed us to draw on that letter of credit
or take money out of the escrow account and even seize
the assets ourselves if the vendor didn't
perform. So that, at a high
level, explains why there are so many amendments and some
of the topics that they, that they cover.
The third set of leases is for the smaller units that
we entered into when the legislation
was amended in 2023 to make clear that these could be
used for storm response. So that starts at page 175
and goes to 232. These are
the much smaller units that we'll talk about that did use
during Hurricane Beryl. We also used a
number of the medium sized units that are under both that short term and long
term lease. So I know it
takes me a while to get oriented with all of the leases and the amendments
and follow all the paper trails. So happy to talk about any of that,
but that gives you an idea of the first 232 pages.
And then it gets easier from there. Starting on page 233,
we answer the questions that Miss Corona asked,
unit by unit, for certain information about
all of the fleet. And so there's a spreadsheet that starts at
page 233 that provides the answers to
those questions. Those questions
include the duration of the lease, the date we actually took possession
of the unit, the costs associated with each
unit, and whether
we used that unit in response to Hurricane Beryl.
So a lot of information on that spreadsheet.
We did also upload the native version of that spreadsheet. I know
my eyes can't read it very well in the PDF form,
so the native Excel spreadsheet is in the
folder in Item 24, in Project 56793
as well. After that,
question two asks for the same kind of information for
any of these units that we own, and we
don't own any of these units. Under the law, we have to lease them.
So that answer is pretty straightforward. And that's on
page 239. On page 241,
we answer question three, which asks us for the same kind of information for
any unit that we got through mutual assistance. For Hurricane
Beryl, we did get twelve additional
units through mutual assistance during the hurricane.
Eight came from Oncor, four came from AEP.
And so on page 241, we provide the details of when
did we get them? Who did we get them from? What were the sizes and
how we used them?
Question four, which we answer on page 243,
asks for incremental costs associated with using
these units during Hurricane Beryl. We are still
awaiting some of those final invoices, things like
fuel. So most of these units,
while they may be dual fuel, primarily run on diesel.
And so we are awaiting the final cost. But we did show you on page
243 the internal labor costs that we have
associated with these units that were used during barrel.
And as we get the final invoices from all of the costs
associated with these units, we'll update this answer. But we provided
you what we've got right now. And then question five asks
for more details around the process generally
for deploying these assets, where generally
we deployed them during Hurricane Beryl. So starting on page 245
and then completing the packet all the way to 250 is
narrative information about that. That again, we can go into great
detail. Eric provided that response,
so we can walk through that as well.
That last spreadsheet shows that we operated these units for about
3000 hours in total during Hurricane Beryl.
So definitely made a difference
in the lives of those people that were served by these assets during
the event. So maybe with that, again, I'll reintroduce
Eric, as the executive at our company that
manages these assets, deploys them during
events like Beryl deployed them during Beryl,
and pause to see if there are any questions about this particular part.
Thank you. Commissioners? Eric,
so based on Jason's update about
the URI and the 5000 MW that were
rotated out, I guess, ERCOT's direction during
Winter Storm Uri. CenterPoint received direction or rotate out 5000 MW.
Since Uri, I've visited with the company multiple
times and I think with you yourself about the
improvements that have been made to the distribution system and the
company's ability to rotate more customers effectively.
Since Uri, how many customers can you effectively
rotate now based on all the improvements and investments you've
made on your distribution system? (item:51:Eric Easton on CenterPoint's circuit segmentation, 56793) Are you including the use
of the temporary generation in that? No. Okay. Without,
without the generation. Okay. So one of the major
changes that we've done is around the circuit segmentation
or ability to use intelligent grid switching devices to
segment off parts of our system that
we couldn't during Winter Storm Uri. A lot of that was
attempted manually and we did successfully do that in some cases,
however, with the road conditions, that made it very difficult to
do on a wider scale. So we have
installed intelligent grid switching devices that allow us to autonomously
rotate that load that we couldn't before that
gives us about 400 capacity.
Obviously, it depends on load conditions at the
time. It's going to be a very dynamic number,
but roughly additional 400 MW
that come through that part of the automation
process. We continue to study those.
So we have the upcoming circuit segmentation study
that we're doing for ERCOT. And through that study, we identified
another set of devices, I think about another 40 devices
that we would install. I don't have the megawatt number that's associated
with those devices, but we can follow up with that. So that'll be
a further enhancement. Some of the other things that
we've looked at. So that's what's implemented. So we've added
about another 400
load. And to put that into context, the load that we can typically
rotate manually is about 3000 MW. So that left us
about a 2000 megawatt deficit during winter storm yuri.
So we've closed into that deficit
by about 400 MW, depending on system conditions.
Okay. And the reason I'm asking is because, you know,
based on the premise that Jason has provided,
the decision to acquire that many mobile generation units
was largely based on preventing a load
shed or ensuring customers have power during a load shed event. Should you have to
rotate 5000 mw? Since Uri, there have
been tremendous improvements, both from
the company side with investments in the distribution system to
be able to more effectively rotate customers out through
intelligent grid switching or devices,
technologies that, you know, the company has made investments in, the ratepayers
are paying for. And on our end,
we have made improvements through weatherization and
dual fuel capability, and overall winter reliability
and resiliency has tremendously improved since
Erie. So that
I think that we all recognize, and we
have to rethink about how we approach this
entire dialogue because of the fact that there
have been a lot of significant
facts that have changed. And so I
think it's going to be important to understand those megawatts,
a total megawatt amount. Yeah, no, I agree.
We have typically used Winter Storm Uri's benchmark,
and then this year, we will also be redoing that analysis based
on the 19,000 megawatt number that ERCOT is studying.
So it's a slight change, doesn't affect our
calculations significantly. The other thing
is that our load ratio share changes on an annual basis. So we also
have to factor that in. And then with the potential
for large industrial loads coming into our footprint,
we also obviously factor that in as well. So there's
some level of uncertainty. And what we're
also seeing is that some of these larger loads are able to come on much
faster than what they could in the past.
And so, because the industrial load is still counted
in our load ratio share, we include that in our analysis when
we're looking at how many megawatts do we need need. And then,
as Jason mentioned, the other scenarios that we have looked at
are the tie line capacity challenges
that we could experience. We're seeing increases in
wildfire risk. And so those wildfires,
similar to 2011, where they threaten the north
to Houston interface, could drive a load shed
condition in the Houston area, even though the rest of ERCOT
may not be affected. So those are some of the things
that are going into the calculations that we're making to try to determine
if we still have the right number of units and
also the speed at which we need to be prepared to deploy those units,
which could require either changes to our processes,
where those units are located, the staff that we have available.
So those are things that we're doing on an ongoing basis and
evaluating those continually.
One thing I would ask. So, Jason, you committed to providing
those analyses on a go forward basis. I think it's also important to know how
we got to where we are today. So I think it would be helpful to
also provide the previous analyses that Eric and his group have done. So
we can see how the initial decision was made and how the subsequent decisions.
got us to where we are today. Yes, sir.
And to add to that, because we have heard in
prior discussions that the decisions were made based on load shed and
hurricanes and localized outages, but we
need to understand if your analysis took into consideration the loss of major transmission
lines into the Houston area as part of your analysis of low shed.
Yes, ma'am. (item:51:Commissioner Hjaltman's question to CenterPoint on stackable generators, 56793) Are these generators
stackable? Like you said, you purchased the big figures
for loadshed, and you couldn't necessarily
use those to go power something smaller.
But now that you have the smaller, could you get rid of the bigger and
you can add them together? Is that a possibility?
So we can parallel units, the five megawatt
units, we have multiple five megawatt units at
a given substation. So the 32 megawatt units,
each one is at its own substation. It's connected to the bus,
and it's ready in case we have a generation adequacy
or any of the other scenarios that we just talked about.
The five megawatt units, we can parallel those units
through the substation bus. For the smaller units, there's a
significant drop off. We go for from 5,
quote unquote small would start about 1 mw.
So one of the challenges with trying to parallel
that many units is, it's going to be the physical space. So the units.
We wouldn't have enough space in the substation to
parallel that many units and connect them to
our distribution system. So in that case,
it's not very feasible to parallel
the smaller units for those use cases.
Yeah. Just for context, the smaller units are about the size of a U Haul
truck. The five megawatt units are kind
of a tractor trailer, and then by the time you get to the 32 megawatt
units, those are requiring us to use a crane to assemble
them.
Are you finished? For now. For now.
Okay. A couple questions here.
(item:51:Commissioner Glotfelty's question on canceling lease agreements, 56793) I read all 200 and some odd pages.
I didn't have, like, a map to figure
out which way was which, but there are some things that stuck out
at me that I wanted to ask you about.
One of them is amendment five to the
lease agreement. Now, I don't know if this is to the long or the short,
but it talks about termination
of the lease. It's on page 145.
Yes, sir. Termination of the lease. And it talks about a
regulatory proceeding. And if we disallowed it,
what would happen? And I've seen in two different places in these documents,
one of them say that you would pay something like this,
says that you would pay $53 million.
And there's another place that talks about 25% of the total cost,
which I think was $125 million. And I'm trying to get my
understanding of this. If you canceled these leases today,
what would be the consequence?
Got it. So I'm looking at 145 and 146 of
the packet. And this is an amendment to the long term lease.
The long term lease had a termination provision in
it in the event that when we
went through the prudence determination here at the commission,
this was determined to not be prudent in
whole or in part. And that was the six months that they gave you two?
That was on page 55, termination of release. Yes, sir. 2a. So,
yes sir. Originally, I believe that that termination provision
expired in March of
2023. Correct? March 31.
And this amendment extends that termination
right through, I believe, the end of 2023.
And so once the prudence determination
proceeding was over and nobody appealed
that decision,
it's my understanding that this provision is no longer a
live provision of the contract that would allow us to terminate
under a determination by the commission that these were not prudent
had there been an appeal. And so we extended it,
because that prudence determination case was still pending.
So we worked with the vendor to make sure that that right that we negotiated
at the beginning, remained through that proceeding
had that proceeding been appealed. We're talking about speculation at this point,
but we would have attempted to continue to maintain the right
to terminate under this provision that you're pointing out,
since there's not a live appeal of that.
We did not ask to continue this termination right.
Based on prudence of the assets. So it's my understanding that
we could not trigger this clause today.
Is there any other termination provision that you could claim?
Let me turn to the long term lease itself,
because there are events
of default if the
vendor did not perform,
that would allow us to exercise certain rights.
So if you look at
page 76 of the packet,
there are certain things that would lead to an event of default by
our vendor, including failure
to provide 94% availability
of these assets. So if they do not operationally perform when
these assets are needed, that triggers an event of default.
There are other things that trigger this, too, right? It's a through g
on that list. I won't go through them all. But in the event that the
vendor defaults on its obligations under this lease,
that would trigger remedies that are on page 78
that allow us to draw on the letter of credit,
take all the money in the escrow account,
take possession of these assets ourselves,
and execute a number of other remedies as well.
It's not the same as termination,
but it's pretty close to it. And so that's the only real,
my understanding is that's the real remedy that's left
once we got past that regulatory provision
that expired at the end of last year. So,
Jason, are you basically saying that Centerpoint entered into a lease contract that
they can't terminate at this point unless there's vendor non performance?
That's right. The termination provision expired
once the proceeding at the commission was over. I mean,
I don't. I mean, I personally have never heard of a
lease contract I can't terminate. Have you?
I mean, it seems like the contract is. I mean,
you entered into a contract you can't terminate unless there's a vendor on performance.
And of course, these large units seems like largely
haven't been run, so we'd have to. It may not ever be run, so we
don't even know they'll not perform. So it
just seems like we're in this circular place where I,
y'all are coming across like, your hands are tied to this contract,
but yet there's been so many changes that have occurred,
and I think, and I don't know if you were asking this,
Commissioner Hjaltman? But like,
can you switch units in and out? Like, can you go take the
big ones back and get some smaller ones, like, trade them out?
Yes. So we do. And Eric can
talk about this greater than I can in terms of the testing that's required.
So these units, assets aren't sitting idle and never tested.
So. And that counts towards the performance of the vendor as well.
So I let him talk about that. We obviously
can reach commercial terms with the vendor on
changing out assets if we believe we don't have the right asset
mix. That's not a right. We have
to terminate the deal. Right. But we can always
work commercially with our vendor to
reach a constructive outcome that works for both of us.
Again, this is. It's not exactly like this,
but the way I view it is we made
an investment in a relatively long term
asset with kind of
like we do with transmission lines. Right. Once you determine that it's
needed and it's prudent and we build it, we have it.
And so that's the same construct under these leases.
Once it's determined that this is the right thing for us to have,
we made the payment and
we prepaid this lease to get a discount on what it costs.
So financially, we have made the payment,
we have the asset that after we went through
the prudence determination, then we don't
have the right to terminate anymore. We have the asset for the term of the
lease. We do. Eric can talk about
the performance obligations of the testing, which is how we know that these
would work or not during the
load shed event. Yes. I think there's a couple ways that
we evaluate performance. The same
folks that would be helping us to deploy the 30 mw,
also help us deploy the five megawatt units. And so they did
do that successfully during Hurricane Beryl.
So we did deploy some of the five megawatt units.
And so from that regard, we did get an opportunity to see how they would
perform in a live situation, how they
transport the unit, how they get it connected and
up and running. And then in addition to kind of
that live scenario with Hurricane Beryl,
as Jason mentioned. We also pull maintenance on the units to ensure that they
are ready. So they've done that. And then
also we have readied the units in preparation for deployment.
And that's something that we typically, if there is maintenance
that's upcoming, we coordinate that with any type of
readying of the units for an ERCOT
potential EEA event. And so we've seen the performance that
they have provided in those three scenarios.
And that's what's really giving us the ability to evaluate whether
or not we think the units would be ready to perform. Yeah, but I
think we're all talking here about the large 15 that weren't used during barrel.
Right. We know the midsize, smaller ones were deployed.
You didn't have enough of them. You borrowed about
twelve or so from other utilities.
So it's the 15 units we're talking about here. So.
And to be clear, that's the 15 are the ones that I'm referring to.
So we readied the 1532
megawatt units. Not all of them, but we readied some of those units
in preparation of ERCOT eevtainous events, because that's the scenario
that those units would be dispatched for. So those were conditions where
ERCOT had said, we have a potential for an EEA event
as part of being ready for that. We do
ready those units so that they can be utilized.
Are these the 115 instances you're referring to that ERCOT has come close to
EEA events that we know is nothing factually on
point, because that would include every OCN and AAN that's ever
been issued in the last since Uri. Yeah. When I'm talking about. Eric, real quick,
will you move the microphone a little closer? Yeah. (item:51:Eric Easton on CenterPoint readying units, 56793) When I talk about readying
the units, it's really for those that progressed all the way to
EEA level that we may not have gone into load shed.
So it's not the totality of the 115,
but it's where we got closer to an
EEA event, which has been
how many times since Uri? I can think of one in September.
Yeah, I don't. I don't have that. But we can. We can pull that in
terms of how many times we ready the units. I do know that was four.
It was four. So we've got a process of readying the units which can
contribute towards their performance. But you
also, you know, talked a long time about this
initiative to go out and kind of see what's the right mix and to do
it on a continual, ongoing basis,
and also to bring in this third party consultant.
So what's the line of sight if you get this assessment?
It says you need a different mix. So how are you going to get
there within your current commitment to this
larger, I guess, asset?
Yes. So, obviously, if you
take the scenario of Texas Energy Fund
generation coming online in the latter
part of this decade, it corresponds pretty well with the
end of this lease already.
And again, we don't have the right to terminate
early, but we can reach a commercial
arrangement under with
the vendor. If we needed a fewer number
of the 32 megawatt units,
maybe for a longer period of time, you could reach
an agreement where there was no incremental cost. You return
some, have some for a longer period of time. Right. This is just a
hypothetical scenario that could occur. So we
do have the ability to take action after that
analysis, short of returning all
of them. But I don't think the analysis would be that
that's the right way to mitigate these risks. Now, again,
we're happy to have the conversation from a policy perspective if we should not be
mitigating these risks. But under current law, we have that
ability to mitigate the risk. We don't see others mitigating
the risk in all of these situations, but we're happy to have
that conversation more holistically.
That might include us getting out of this altogether. And again,
then we'd have to figure out what the right path forward is for that based
on where we are. Jason, I'm just having a hard time understanding
how all of a sudden the lease that ends in 2029 is
somehow correlated with the Texas Energy Fund power plants.
Yeah, and I shouldn't suggest that.
I'm just using that as the example.
Another thing you'd have to take into account in various scenario planning
that we do take into account is the growth in our
load ratio share.
And again, a lot of that growth comes from industrial
facilities as they electrify. As that occurs,
we get a greater amount of load shed from ERCOT in the event we're
in that situation. But we have an even greater amount of customers
now that we can't rotate outages across. So again,
you continue to disproportionately impact our residential
and commercial customers in load shed events as the industrial
sector gets bigger. And that should
impact also our determination on how many assets.
So I mentioned the energy fund as just an example of a scenario to
think about, because I think that will impact how much we
should have. It's not the only moving part, because as
those units come online, we've got growth in the industrial sector,
we've got growth in the residential sector. When we talk about the analysis and
being more transparent about what Eric's team does, we will
show all of those scenarios. So I apologize for focusing on the energy
fund. That's not the. All these correlations being made to
potential load shed events. And I understand that's part of the law
that you all went out and bought those units for, but I guess
what I'm trying to get at is there's I mean, if you want to think
of Armageddon for why you need the load shed events, we could sit here and
come up with a list of why you might need them for a load shed
event. But the fact of the matter is, again, there have been tremendous improvements on
reliability and resiliency both. Bye. The state effort of legislation that
was passed by the legislature, signed into law by the
Governor, we implemented all of that Legislation,
and tremendous improvements and investments have
been made by the transmission, distribution utilities on their distribution and transmission
systems. We're in a different place now.
And, I mean, you're not in the business of power
generation, right? So the Texas Energy Fund, I mean,
yeah, we all want those power plants built. We need that for load
growth. But we really need to think about
what's the optimal fleet that you should have in
mobile generation fleets at this day and time, given all of these factors?
And what are some pragmatic ways of moving forward given
your lease contracts? What do we have to work with from
a practical, pragmatic standpoint at this time? Because there's obviously,
as you know, there's tremendous concern about the mobile generation units,
this 15 units that cost a lot of money and were not used and
the ratepayers are paying for it. And so how are we going to get to
a place where, you know,
we have the inadequate, you know, either there's a law change, you know, like you
said, maybe there's, there's a paradigm shift in the policy.
But in the meantime, you know, until then, we have to do
our due diligence and understand, like, what do we have practically at
our disposal right now to rethink what we're doing here? Because it's
just not like you just said, you guys really
went out of your way to plan for load shed events. The other utilities did
not, right? The other TDUs
that went out and bought mobile DGD seem to be
a little bit more pragmatic. I mean, and so in
terms of. But you're saying you have unique circumstances in your service territory
to justify these big units. But the fact of the matter
is facts have changed and we're trying
to assess, like, what do we have at our disposal right now, and what does
these contracts say that can, that can help us out? But it doesn't sound
like there's much flexibility in the contracts is what you're saying.
So we're just trying to understand that that's right.
Maybe the right next step is for us to provide that
past and current analysis.
Transparency should start now. Is what I'm taking from your comments
and so we can work with staff to
figure out the right place to make that filing so that
I think that will help us advance the discussion.
Reasonable minds will differ with our analysis and I think
we welcome that discussion with the right stakeholders.
So we'll work to figure out where to start providing that
information. I have a couple more
questions.
Could you find out what the market
rate for an SMT 60 generating unit
is today? I've been told by folks in the market that
it's 145 to 160,000 per
month, but the CNP contract says 220,000
a month. So I'm just wondering,
was there, it makes me believe that there
was a, we got to get this done quickly. And whatever cost it is,
the cost was there. So if you would please just get
us that as best you can. You don't have to do another RFP, but if
you picked three or four folks, okay. Now the
other thing in this contract that I don't understand,
who is Goldfinch Energy?
I may, we have other resource witnesses that might. So let
me tell you what I think, and you all can come back and tell me
at a later date. So I think that in
these contracts, lifecycle power was
owned by a private equity firm and they
didn't have the resources to go procure the generators that you needed
them to procure. So they went and created this.
They either life cycle or the private equity farm created another
entity to backstop that.
And then your prepayment of 460 million
or whatever it was, became the collateral for them to go for
their loan to their private equity firm, that they went and bought the generators and
then gave them to you.
It seems kind of strange. I'm not convinced that I
don't know Goldfinch. I hope you can confirm that
for me because it was a new name in there that didn't,
that kind of stuck out. But that's what I see. I don't know
if that's right. (item:51:Commissioner Glotfelty's question to CenterPoint on performance metrics, 56793) And then
I get, there are a lot of performance
metrics in here that Lifecycle Power has
to abide by in order for these to happen.
And I just, what I've looked at online,
be it, it's online, Lifecycle Power didn't have that many employees.
I don't know how they're going to perform unless they have contracts
behind them that are going to set
up, move all of the things that you required in the contract
for these generators, whether they be small or large.
And was there any exploration of that behind
Lifecycle Power on? Would they be able to perform, or is it
just a commitment like we got it?
Yeah. We have not had those performance
issues with them in the times that we've used the units.
I know that was one of the reasons why we had the letter
of credit, the escrow account, and the various other protections
for us and customers in the event they weren't able to perform. I don't know,
Eric, if you know the size of their employees that help us
with this. No, I do not. I know that they have brought in resources
from out of town when we've needed them. So in terms of having
the resources in Houston when we needed them, they've been able to
fulfill those obligations. I know that they've flown people in at times.
So where are those resources? What the contractual
agreements are, I don't know, but we would
tell them how many units we needed to be ready to operate and
they would have the resources available to operate those units.
Okay. If you would just get me some better
understanding of how that transaction works, because it leads
me to believe that you did a transaction with a company that didn't actually
have enough revenue or enough resources to actually
buy the generators without you giving them the money to
satisfy that lease. Got it.
The other question that I have is, again, a little
research here on the Internet. We don't know if that's always true or
nothing. It seems like the CEO of
Life Cycle Power is in litigation with his old firm.
Are you all involved in that? So, John Tuma versus
Life Cycle Power? Are you involved in that litigation?
I'm aware of the litigation. I don't know whether
we're a party to it, but can follow up with you
on that. And can you let us know if
any of that has to do with any of this mobile
gen contract and if so, how that might
interplay? Yes, we'll follow up.
And let me just turn to make sure none of our colleagues know whether we're
party to that. I just don't.
Okay. Okay. Yeah.
The head of our procurement tells me that we're not a party to that litigation,
but we'll get a, we'll pull information about it.
I am aware that it exists. I don't know the current status, but we'll pull
that information and provide it. Okay, I think I just have one more question,
and that is no, two more questions. No, three more questions.
No kidding. One day we're going to hold you to that number.
Yeah, these are kind of
yes no answers, so they're fairly quick.
One of them is so,
isn't it? Right. That you all went and procured these generators,
these generation leases prior to the Commission
completing a rule on how and what is
prudent in that under that program?
Yes, sir. Okay. Is that a normal practice for
a utility across the
country that gets their rates paid for?
Do they normally say $800 million? Oh, we'll go spend it and figure
out the rules later. I think it depends on
the type of asset.
And we operated under the expectation that
if the tool was available, we should
have it, especially before the next
winter. And that's why we had the protections
in there of, we can undo this if
there's a determination that it was imprudent.
It's one of the reasons why we wanted that provision in the contract,
because we were doing this not in necessarily
the ideal order, but didn't want to have
a repeat of load shed where we couldn't
rotate outages.
And we had a tool that we could have had and we didn't have it.
Okay, so two very quick things. One of them is,
I think ERCOT told me that your load ratio share is now determined twice
a year. Can you all make sure that that is right?
And if it doesn't include, if it includes
all of your industrial generation that can't
be shed, maybe we should look at that and consider that as it's,
as a fairness component across the state for load share ratios for
load shed. So it is calculated twice a year and
it does include our industrial load. It does include all the industrial load.
Maybe we should consider that and see the components
there. I think the
final question that I have is it deals with
distributed resources on your system.
In light of this, and actually, prior to the event,
we've seen a lot of distributed resources that want to connect to the distribution system.
We have, quite frankly, heard of very good
tdus and very mediocre tdus. And I hate
to say it, but you all are in the mediocre category. Not because.
Well, primarily because of some of the things that you all are
doing and costs that you incur on that that are not uniform.
One of them that I've been told about is a transfer
trip device. Okay, I understand a transfer trip device.
There's no argument that they're needed because they're required for safety
of linemen. But the question is, at what level
and how is that a fourth level of protection or not? Can you
all educate us a little bit on this? Why they're needed,
what the component is, and why people
that want to put generators on their own system or in
the system are having a problem with
you all on this issue? (item:51:Eric Easton on distributed generation, 56793) Yeah, I can
speak to that a little bit. So the transport trip is put
in place, as you mentioned, safety concern.
If you have a distributed energy resource that's connected to
the network and we trip that circuit, that resource
could then go ahead and back feed that circuit.
So typically, depending on the load. So what that means is
you all take a line out of service in order to be not
energized. And if there's a generator on it
somewhere, it could still be generated. It still could be energized.
Yeah, it could be that we don't take the line out of service. It could
be a faulted condition. So you could have a line that was
down, and our relay would have potentially
isolated that circuit, isolating the down power line.
And then this generator could back feed the circuit and continue to
keep that energized. So now it's not only a risk for.
For folks that might be working on our system,
it's also a potential risk for the public. And it could cause
other unintended consequences, such as wildfires,
et cetera. So as a result,
typically there's a ratio between the load on the circuit and
the size of the generator. Depending on
that ratio, the generator may trip offline on
its own because there's too much load for that generator
to sustain itself. And therefore,
in some cases, people will accept not
having transfer trip based on that ratio.
And the assumption that that generator is going to trip off at
centerpoint. We don't make that assumption. And we say
if the generator is of a certain size and we still look
at some of those conditions, but then we want to provide transfer
trips so that we can ensure a signal has been sent
to that generator to isolate it such that public
safety and our crews are safe. So I think this is an issue,
obviously not an investigation issue, but I want to talk to you all about it.
I understand that it's even more challenging as more and more folks are
looking to put their own resources at their
locations, at commercial sites in Houston.
That the load numbers get changed and varied
with recloser devices and things
as you go further down. And that means what used to be a whole line
at, say, 50, you put a recloser on
it, or whatever the device is, and now it's 25. Then it gets lower and
lower and lower, creating a problem. I would like to solve this as part of
the effort here, as we
are trying to create resiliency in this system
and in your system and in all the utility systems to allow consumers
and businesses to do what they want to ensure that their businesses can function.
So, yes, sir. I think on as
we have that discussion, we should include,
you know, if we, if in our judgment and
you all agree to we need to have these devices, I think we
could talk about how do you remove the barrier to individual customers,
then, you know, who pays for it, essentially. That's right.
Especially as we think about the societal
benefits of these local distributed generation
assets. If there are societal benefits,
then perhaps society pays for these devices.
And so I think we're happy to have that conversation. We should have that
not part of their investigation, but part of the other distributed
resource discussions that we have and we'll have more of. Thank you.
Yeah, and I want to come back because chairman Gleason asked for
previous and ongoing analysis of your decisions. I really
want that number of how many megawatts you can rotate out today. You've made a
lot of investments in your system. I had an answer
that Eric, you gave me an answer that was a non answer. I want the
total amount of megawatts you can rotate out today.
Not by ERCOT direction, not just how many can you rotate out effectively
today. And I want to also reemphasize
this, Jason. Because you've talked a lot about load shed today.
But the fact of the matter is, is that CenterPoint did a significant testimony.
And from my understanding, I wasn't at the legislature
at the time or staff or anything like that. I was actually at the Commission.
But you guys really sold this mobile
generation at the legislature and submitted a lot of testimony
here in your DCRF docket, the underlying docket.
Talking about how these mobile generation units could be used for hurricanes.
And the fact of the matter is the majority of them
cannot be used for hurricanes. So, you know, you can focus on
loadshed all you want, but you guys made the case for hurricanes. And now
we're at a place after Hurricane barrel where there's been devastating
impacts in the service territory. People died.
And so like, we're having to understand,
I'm trying to understand why we're so focused on load shed today when hurricanes
was a big part of your testimony, your position
in various venues. So I just wanted to say that,
and I don't expect you to have an answer, but that's.
I just find it, you know, I feel like there's
a lot of kind of talking out of both
sides of your mouth on this issue, doing little dances,
pointing to different facts to justify your decision. But the fact of
the matter is, we're here and we need to figure out what we're going to
do with this fleet. Sure. Now, I can provide a couple of responses.
So, on the. I don't want an answer. I'm done. I just.
I'm done with the discussion. It's just the last statement I wanted to. I thought
you were asking. No, I just want the megawatts from you. How much? Okay.
1700. That's all you. Even rotation is 1700.
The mobile gen makes up the rest of it.
Because in order, as I said earlier, the 3000 mw that
we have is the manual load shed number. And then
we added to that about roughly 400 more megawatts
with the IGSD devices. So that gives you
roughly 3400. And so if you take half
of that in order to do even rotation, so that's a predictable
rotation, so that we can tell customers how many,
how long they're going to be out before they come back on. It has to
be a 50 50 ratio. So that's how you get to the 1700.
And then if we had a URI type event
or deeper load shed than that. Then that's where the
temporary generation fills that void. Okay,
well, I. I don't
know that that completely answers what I'm saying.
What I'm trying to get here is how many thousands of megawatts
can you now rotate out? You can rotate out more than 5000. Now,
when you say rotate out, do you mean shed? Shed. Yeah, we can drop
as many as we have. I mean, that's the honest is, if ERCOT
directs us to shed all of our load, we'd have to shed all of
our load. Well, but you can't. Right? Because of certain restrictions with
critical load. So there's a difference between the shedding of load
and the rotating of load. So when we shed load,
that's where ERCOT gives a directive in order to maintain system frequency.
And whatever number that they give us is what we shed. They give
you 5000 last time. Our ability to rotate
necessitates that we have some load still online so that we can rotate
that load. And so during Winter Storm Uri, the issue was that
we had a directive to shed more than that 50% ratio.
And so that's why we could no longer rotate the load, but we could still
shed. If ERCOT had told us to continue shedding, we would have
had to continue shedding. Otherwise we would have had a blackout across the entire
ERCOT region. And so we continued to shed even
though we could no longer rotate. And the
temporary generation is what solves the rotation problem.
But the shed is the shed. We would shed whatever ERCOT
directs us to shed. Well, I want something in writing that explains this in
the issues related project. We will definitely have it. Because I want to make
sure that the information you all have been providing ERCOT in
various forums on your ability to rotate matches what you provide us
in this record. Thank you. Yeah. And I think one thing
that might be helpful, I think, you know, the large units.
I think, were procured in large part because we have an order that says,
don't rotate any customer for more than 12 hours. And so that's
part of that determination. So I think what would be helpful is,
given that order, has that number changed?
And so I think it would be helpful to talk to staff and come by
and brief the offices. Because I think that was a large reason as to
why those large, those larger units were procured. And so has that number changed
since that initial procurement?
Happy to do that. Okay. I think those large generators, the way
that they propose to use them, from an engineering perspective,
increase the flexibility for all the consumers in Texas on how to shed
load, especially those in your territory.
It's just a solution to one problem
that's been superimposed on another problem. And I think that
the discussion, like you said, Jason, needs to happen on,
is this your role in the system that
was set up by the legislature, or is it not?
(item:51:Commissioner Jackson's question on managing risk, 56793) But either way, we need to manage the risk. Right. And so what I'd be
interested in, because you mentioned, or you laid out, like,
three areas that you are, three distinct areas that you have to
manage the risk on. So it's not only what you're dictated
to do by ERCOT, but also the fact that you have 60%
of your powers input to Houston,
as well as any risk associated with your traditional
facilities that are now operating in the Houston area.
So it's three areas with
different levels of risk that at some point in time, you have to come together.
And I'm assuming that's part of what is going to be part of this study
and this independent an
assessment that's going to be done. And so, I mean, at the end of
the day, we want to make sure that the lights stay on in Houston,
but we want to do it in a way that, you know,
manages risk effectively and in
the most cost effective way we can. You're absolutely correct.
And those three don't even cover the electrification issue
that Jason brought up earlier. So our residential
customer growth is not going to parallel
the load growth from electrification of industrial
facilities in the Houston footprint. And so to Commissioner
Glotfelty's point, we've got to think about how
do we handle industrial load in the load ratio share?
As we talk to our industrial partners in the Houston footprint,
we could see two to three times the industrial load that we have today,
which means essentially the residential customers that are left
are going to have an even detrimental position from a
load shed perspective if we don't address the
inclusion of industrial load in the load ratio share.
One last thing. Going back to the lease,
it is odd that there is no way for you to terminate it. I think
you can always go back and renegotiate. I think you should look at those options
and see what is available, see if subleasing them to others
is available, because I think you need to have those options ready to present to
the Commission and the Legislature most likely as well.
Understood. I just have three more questions.
I'm kidding. I'm done.
So Jason and Eric, thank you for being here. Thank you for answering our questions.
You know, there's some follow up to do. Work with staff in the offices to
get the information and we'll continue to be in contact. Yes,
sir. Thank you. Thank you. So we are
getting dangerously close to needing to give our court reporter a break. I think we're
still waiting for a second court reporter to arrive. That is right. So let's
try to at least get through. Let's go to public testimony,
and if we have public comment, which I think we do try
to get through that, and then we'll take a break so we can give our
court reporter a much deserved break. That sounds
good. So then you would like to take up Item No. 1
is that correct? Yes, take up Item No. 1. Shelah, do we have anyone signed up
for Public Comment? (item:1:Shelah Cisneros, Commission Counsel, confirms 3 people have signed up for Public Comment) Yes, sir. We have three people that have signed
up for Public Comment. The first person that signed up is Bruce
Sorgen.
And just to clarify, is it the usual three minutes? 3 minutes.
(item:1:Bruce Sorgen, TX citizen, concerning Windermere Oaks WSC) Hello, Commissioners. My name is Bruce Sorgen. As you may remember,
they're looking for a job opening. Maybe I'm down here so much.
But anyway. Windermere Water Supply is a
water co op in the Spicewood area,
285 water meters,
since for the last nine years, it's been in full turmoil
mode. In 2020,
a rate appeal that you are quite familiar with was centered around a 71%
rate increase. This increase was implemented for
one purpose, so the board could spend over $2 million in legal fees.
Legal fees to cover an outrageous land deal where the previous board sold 3.8
acres of water co op land to a sitting director who
is a realtor for one 6th of its value, mind you, that the board chose
to aggressively insert themselves into this legal battle.
Why am I here today? I am here today to ask this
Commission, where is our PUC ordered audit?
I am here today to ask this Commission,
where is our PUC ordered $886,000
rate refund that you guys ordered?
We have many retired people in our community that need this money just to live.
I have yet to find one member of our community who has received any of
this money. I'm here today to ask this Commission
how it is that a water board, a water commit.
A WSC board can spend $75,898
on legal fees in the last four months alone.
We've yet to see Julys.
Mister Carleton is a law firm who has billed our
community 75,000 plus dollars.
July is going to be even worse anyway. For the
last four months, I mean, for four months
alone, this Commission ordered
$3,000 a year legal budget for the. For the entire year
anyway. The wind. Tomorrow, the Windermere Oaks Water
Board is paying a lawyer to write boards, agendas and minutes.
In the last 16 months, there have only been one set of minutes produced.
If we're going to pay a lawyer to do this for this kind of outrageous
waste, why do we need a board? Why is there no system
in place for this great state of ours to make a board comply with this
Commission's orders?
The current board is not concerned with anything this Commission has ordered.
The proof of that is can easily be seen in their filings
to the Commission. Oh, wait, they don't bother to do
their required filings, do they? Instead, they are
focused on one thing only. The quick sale of a remaining six acres
of co op land. They've even
fired the entire real estate committee because these ladies were pushing
them to slow down and property market the land
and get an appraisal. In closing, I am asking this Commission
to install a manager to run this co op. We are quickly approaching a
decade of this three ring circus.
Thank you for being here. The next person that signed up
is Danny Flunker.
(item:1:Danny Flunker, TX citizen, on behalf of rate payers of Windermere Oaks WSC) How are y'all doing this morning? It is morning still
alright, you know. Here we are again. We're back. Thank you for having
us. I'm here on behalf of many of the ratepayers
in our community who feel utterly voiceless on the ongoing issues
with Windermere Oaks Water Supply Corporation. And as
Bruce mentioned, for 16 months, they have one set of minutes produced.
The lack of transparency is unacceptable.
At the last WWC meeting, Windermere Water Supply Corp.
Meeting with the new attorney being present, the members were
left outside in the scorching heat while the board and the attorney went
down the street to the directors house in their air conditioned home for nearly 3
hours in executive session. Upon the return, they voted
on only one of five agenda items and
adjourned, completely ignoring the other agenda items.
Among those disregarded items were critical issues.
The IR's investigation. Nothing. They didn't table it.
PUC compliance matter 56167.
Didn't table it, didn't talk about it.
PUC enforcement compliance matter Docket 56272 didn't
talk about it. Didn't table it. And then the
CCN application. PUC application Docket 55840
didn't talk about it. Didn't table it. Nothing. And again,
despite spending nearly $76,000 in legal fees in just four months,
and they haven't given us July's invoices yet and I've requested them,
these matters all remain unaddressed. Furthermore,
the water co op has been operating without a president, secretary or
treasurer since March, and they have three directors,
so that each one of them could take one of those roles, which is a
serious governance failure. We're just
asking for relief, some form relief. This is an untenable situation.
And as Bruce mentioned, we have a decade of corruption and it
just continues. That's it. Thank you. Thank you,
sir.
And the last person to sign up was Allen Hicks.
(item:1:Allen Hicks, TX citizen, concerning Windermere Oaks WSC) Good morning Commissioners and thank you for allowing me to speak.
I spoke before y'all, right, before y'all ruled on our rate
appeal. Just giving y'all a little bit of a personal touch to
the hardships that. That 71% rate appeal
or the 71% increase
they put on us to pay the legal fees. After y'all's ruling,
I wanted to come for you all first to thank y'all for that.
I'm a retired police officer with fixed
income. And as a result of y'all reducing our rates,
I'm seeing $130 more a month on my.
Less on my month, $130 more a month less on my water
bill, which is coming in pretty handy right now in these hard economic times.
And I'm not using any more water than I was using before.
Y'all ruled for them to roll our rates.
And our community is a group of. There's quite a few
retired people, and I'm sure they really appreciated
y'all lowering our rates down because it's helped us all, because we
all are on the. Well, a lot of strong fixed incomes out there.
But going to just touching on what Danny and Bruce have said,
however, this current board, under the leadership of Jeff Walker,
they're going down the same path. The land sale that Bruce just talked about,
not only are they trying to emulate
this original land sale, that char that started the lawsuit
that caused the rate appeal, there's a lift station on the there.
And against advice from attorneys, they have
not surveyed the land. They have not got an appraisal of the land. So we
don't know what the plan is with the lift station for our water corporation,
if that property is sold. And at
this point, I don't even know if we do have a legitimate board because since
February, when we had our board elections, we had a full board.
Then folks started leaving the board. There was
a lot of disagreement on the way things were run.
We've had several meetings where members were picked
from the meeting
to come up and set to be a board member so we'd have a quorum,
so they could talk about things and vote on things. That's how I
don't even know the correct word to say. But that's how bad things have gotten
involved. Windermere, that we are asking
for volunteers to come up and set it so we'll have a quorum
to cover agenda items. And the reason folks don't
want to sit on the board is, as Danny and Bruce
had said, I think they're afraid to
sit on it because there's a continued violation of the
Texas Open Meetings act. They're ignoring your
PC, PCU filings.
They haven't made any of the PCU filings, the deadlines on those,
just a couple of those has been mentioned is
the compliance filing, the CCN filing.
And so a lot of folks don't want to get saddled with possibly
doing something illegal. And there
has also been talk about coming before you all to ask for an emergency
rate of bill to raise the rates and set assessment.
So we're back to paying the rates that we were. So I just echo
Danny and Bruce's thoughts and asked you
step in and help with possibly an emergency manager.
Thank you, sir. Did you say you're on a fixed income as a retired police
officer? Yes. Yes, sir. Thank you for your public service to your local community and
thank you for being here today. Thank you,
Shelah. I think maybe a 20 minutes recess so
we can switch out Court Reporters? I am just looking
around the room. I'm not sure the court reporter has arrived yet. She has not.
You're welcome to take a recess for a break. Or we could do the consent
agenda. Why don't we roll through the consent
agenda then? (item:0.1:Shelah Cisneros lays out Consent Agenda) Okay. All right.
Commissioners recusal memos were filed in Project No. 527611.
Chairman Gleeson is recused from Items 817,
20, 22, and 28. Commissioner Hjaltman is
recused from Items 5, 20, 21, and 22.
By individual ballot, the following items were placed on your consent agenda:
Items 2, 4, 7-16.
Let me back up. Hold on. I think there's a discrepancy here.
2, 4, 5, 7-16,
18, 21, 24-27.
And also by individual ballot, the Commissioners voted to place Items
on the consent agenda where no one signed up to speak in those Items,
and those Projects are 30, 31, and 56.
(item:0.1:Chairman Gleeson asks for motion to approve items on Consent Agenda) I would entertain a motion to approve the consent items as laid out by Shelah.
So moved. I second. Motion and second. All those in favor say aye. Aye.
Opposed? Motion prevails.
And sir, if you'd like to take the 20 minutes break? I think during that
time period, the court reporter is expected to arrive. And we can do the switch
out and be ready when we resume. Perfect. (item:0.1:Chairman Gleeson recesses open meeting) We'll stand in recess until
11:45.
(item:0.1:Chairman Gleeson resumes open meeting) We will call the meeting back to order at 11:47.
So I was informed I made a mistake.
I prematurely closed down our Beryl discussion.
(item:52:Chairman Gleeson recalls Project No. 56822) So we're going to call back up Items 52 and
58. So that's Project No. 56822,
investigation of emergency preparedness. (item:58:Chairman Gleeson lays out discussion & possible action regarding customer service issues) And 58, discussion and
possible action regarding customer service issues, including, but not limited to,
correspondence and complaint issues. Connie, go ahead.
(item:58:Connie Corona speaks on customer complaints concerning CenterPoint, 56822) Thank you. So since Hurricane
Beryl, our call volume and the
informal complaints that our consumer protection division has taken roughly
doubled. We had 1320
complaints against CenterPoint as of
the close of business yesterday. 65 of
those are what I'd like to talk about today.
They were related to meter reads that were estimated
while customers were actually not receiving service.
In general, the pattern is that the customer cease
usage was recorded on days when they still had
not yet been restored. I'd like to ask CenterPoint to walk through
how this problem was identified and resolved, and then
I'd like to hear from one of the reps
who experienced this issue with their customers. I'd like
to invite Christina Rollins with NRG to address this from the rep
perspective and for Centerpoint to sit the appropriate personnel.
Good morning Chairman Gleeson and Commissioners. Jason Ryan, Executive Vice President with CenterPoint
Energy. I have with me today Tony Gardner, our Chief Customer
Officer. I'll turn it over to Tony. (item:52:Tony Gardner, CenterPoint's SVP Chief Customer Officer on the estimated meter process, 56822) Good morning, Commissioners. I think it's
still morning. And mister chairman, my name is Tony Gardner. I'm senior vice
president and chief customer officer at Centerpoint. Energy. I guess
I'd like to start by providing some context to you all about how our estimated
meter process works and its totality.
So, if a customer has power on at their
home, and we're unable to communicate with their meter, what we do is
we look at our meter data at a 15 minutes interval
level. So, think 96 intervals in a 24 hours time frame.
If a customer's power is on, our system says the power is on, and we're
not able to communicate with our meter. We will estimate
a customer's usage at the 15 minutes interval level every
day that the power, it shows that it's on, and we don't get
a meter read, meaning we can't communicate with the meter.
The second part of that scenario is, if our system shows that a
customer does not have power at their premise, and we cannot communicate
with their meter, we do not estimate usage for
that timeframe that the customer shows that they did not have power.
So any customer that our system shows that they did not have
power, we put in zeros in those intervals
and transmit that information over to ERCOT, which sends it to our retail electric
providers. To provide you some additional context, for the
month of July's billing period, we issued more than
2.9 million transmittals, or inverse invoice
data, over to our ERCOT and our retail electric providers.
Of that 2.9 million meter usage
interval data that we sent over to our retail lecture providers,
96,000 of those showed some form of estimation,
whether it was an estimated meter read because we couldn't communicate with the meter,
or we zeroed out information in the interval
level so that customers would not receive inaccurate bills.
Of that 96,000, we looked at 74,000
of those meter reads where our usage for that
30 day timeframe was 30%,
on average, lower than it was at this time
last year. So far, we've received 1300
meters dispute requests that have come from our retail providers.
We've done our due diligence and make sure that we have reviewed each and every
one of those requests. Turns out there have
been 16 of those requests that needed
to have the charges reversed and rebuild for
customers. So we reversed out the charges, we sent back
new meter reads through ERCOT to the rep, so that they could
re invoice customers at that point. But that is the extent
of how our estimation process works and kind of what we've experienced
during Beryl so far, and I'm open to any questions that you guys may have.
Commissioners?
(item:52:Connie Corona's question for CenterPoint concerning the modification of their standard operating procedure, 56822) So what you've described sounds
like the process that staff understood
to be the standard operating procedure.
But we're curious at what caused some of these anomalies and
whether you're able to modify your processes to prevent
this from occurring in the future. For example,
in some cases upon our investigators found
that usage was not only attributed
to customers while they were out of service,
but that estimate was actually higher than their reads for the previous month.
Yeah, absolutely. So we'll continue to fine tune the equation
that we built in, which is a model. So our system takes a look at
a customer's usage from the past three months, and typically it would
create an exception that would come out to my team. We would take a look
at the exception before we released that billing usage to make
sure that it did not exceed what we expected
that customer to see or wouldn't cause an issue in the next month
when they had a true up for their estimated usage. We'll continue to
fine tune the model, but like I stated, so far we've seen 16 of
those. But we always look for a way to make sure that we can always
refine and fine tune that model. Some of the degree days
when you have storms that push in that create some of these anomalies,
that the model just needs more time to digest and continue to
evolve and grow and make sure that it catches more of these.
Thank you for that explanation. No problem.
Christina, I have a couple questions for reps.
Can you just describe for us how NRG,
as a rep can communicated with its customers who receive
the types of bills we're talking about?
Sure. And I think it might be helpful to start with kind
of where customers were first seeing this issue that y'all were talking about.
So, Christina, will you say your name and who you are? Oh, sorry. (item:52:Christina Rollins, NRG's Assistant General Counsel of Reg. Affairs on communication with customer, 56822) Christina Rollins,
assistant general counsel of regulatory affairs for NRG.
And so the TDUs send usage to reps,
which are also known as lses, in more than one way. So there's a daily
interval usage file that the TDU send us. They also upload
that to the smart meter Texas portal. And that's really where customers can
see their daily usage consumption, what they're using during different intervals.
Reps also use that information for, you know, customer tools like
weekly summary usage emails, which customers, you know, find helpful.
And so customers can see their usage history. That's pretty much where customers
were first starting to see an issue. Right? So Hurricane Beryl makes landfall on July
8. Customers start seeing usage on the portal, or they
start seeing usage in these weekly summary emails when their
power was out. And so once we realized that was occurring,
we contacted the tdus, and I think Centerpoint,
it was really mostly an issue that Centerpoint, I think, also already knew about.
But it took about a week for that gap to close
where customers were then seeing zeros on the SMT portal
when they actually were out of power. So that took roughly
by July 29, I think that was fully resolved by the time
you go to bill a customer. There's also an 867
transaction, and that's like the periodic monthly meter read that you get
from the TDU. And if there are estimates in
that, then the bill that the rep issues to a customer based upon
that 867 will indicate that it's based on estimated
usage from the TDU. So kind of with that background,
by the time you got to the 867, I think most of
these issues largely had been resolved. But we did know that customers
had questions from that daily usage file.
So we prepared our call center agents to be able to explain what was going
on. We let them know that the TDU is aware of the issue and
that they would be correcting it and that they would not be charged for usage
for the time periods in which their power was actually
off. And in addition, we made an update to their online
account maintenance portal, which is where some customers prefer to
interact with us instead of calling the call center so they could receive
information electronically. Additionally, we have
weekly summary emails, which we included that information on as well to let them know
that there was an issue. We're aware of it. As far as the call center's
ability to field calls, we're happy to say
that during the period of the crisis, our average wait time to get to
a live agent, less than a minute. In that we
fielded a large number of calls during the
hurricane barrel recovery effort. I think the highest call
volume we had in a single day was something like 44,000 calls.
Thank you both for that update. Commissioners, do you
have any questions? I think one question.
Have we seen this before with estimated meter reads in
previous hurricanes or like during Uri? I can't remember. Yes,
we have. And our investigators
were on the lookout for it as customer complaints came in.
(item:58:Commissioner Hjaltman's question to CenterPoint & NRG on communication with customers) Is there anything you can do as
CenterPoint and or as the rep to allow the
customer to know this might be occurring so they don't immediately have that concern
of, I can't believe they're going to be charging me. I had no power.
Yeah, absolutely. We can do a better job of making sure that we educate our
customers on kind of what they see to the point they
were making earlier. We upload those files daily to Smart Meter
Texas. So customers have gotten prone to go out and look at Smart Meter Texas,
but sometimes it can take up to two to five days to true
up some of that meter usage in smart meter Texas as customers are
going out and looking for that information. So absolutely we can do a better job
of educating customers to be on the lookout for some of this on
top of the preventive measures that we take as a TDU and a retail
electric provider to make sure that they know that we're going to
make sure we do the best job of getting them accurate invoices.
Commissioner Hjaltman, we have a few ideas on that one as well.
I think we could shorten the time it takes to move from
the communication between the TDU use estimated reporting
sequence to their outage recovery sequence. Right, because rightly
so. I believe the TDUs all have a different method of doing this, that when
you're missing an interval, they'll estimate it for smart meter Texas
because it's really by and large you don't have a large scale outage happening.
So that makes sense that you would do an estimate that when there is a
large scale outage happening, closing that gap from
which you continue to estimate to reporting zeros would be really
helpful because here that gap stayed open for several days, which caused some
of the communication issues, having more frequent market calls
about what's going on. So we can also help communicate with customers.
You know, we're in this market together and we're in these communities together.
And so armed with information, reps can also help communicate. We have
extensive call centers, we have lots of resources. We communicate with customers
every day. So we're definitely here to help. So yes,
with information and we're going to be able to communicate with
customers together. Yeah. Good comment,
we appreciate that. During Beryl we hosted, we do
try to host a call every day with all of our reps just to let
them know where we were in the restoration effort, what was happening, those types
of things. But I'm gladly to work with them to see what else we can
add to that agenda to make sure that we get out the right information.
Thank you Commissioners for allowing staff to, to bring this
discussion where folks can
hear about this issue and understand it a
little bit better. (item:58:Connie Corona recaps discussion) And I would just recap it by
saying for the vast majority of customers,
when you go online to check how much you've used so far this
week or this day,
you know, that's where the vast majority of customers saw the problem.
But by the time the monthly bill was calculated and
sent out, by the retail electric provider. It was fully resolved.
So if you still have any concerns about your bill, please call
the retail electric provider that sent you that bill or you can always get
assistance from our Consumer Protection Division.
Perfect. Thank you. Thanks. Thank you all. (item:52:Barksdale English, PUC's Deputy Executive Director concerning reports due to the Legislature & RFIs, 56822) Commissioners,
last week Commission Staff issued a series of
voluntary requests for information from folks
who were participating in the recovery
from Hurricane Beryl so that we could inform the reports of
the Legislature. That's due at the beginning of December and
those responses are due at the end of the month. Earlier this week,
we issued mandatory requests for information to
about 90 different utilities that were in the impacted
area, which was kind of defined as any county in
which disaster declaration declaration was issued by the acting governor.
The 90 utilities received those requests for
information directly from us and we also posted
those RFIs online in our
interchange. Unfortunately, we had about 10%
of the utilities. Their contact information was
not good. And so this might be a
nice little public service announcement to
just have all of those utilities make sure that your contact information
is up to date so that we can be in touch and get the information
that our citizens and residents really need.
Of the 90 utilities, we sent RFIs to
about 30 co ops, about 30 cities,
17 water utilities and nine telecommunications
utilities. As those
utilities review the questions. You know,
staff just wants to reiterate that if there are questions
in those RFIs that don't appear to apply
to your operations, to your business model, then simply you
can respond with this does not apply. And that's a
also, there have been some questions about if a
utility did not receive a direct communication from our staff,
whether or not they need to proactively respond to those rfis.
And I just want to confirm for anybody out there who was maybe
hoping to get rfis, who didn't get them, you are
not responsible to answer questions if you did not receive a direct
communication from Commission Staff.
I guess the last two things that I wanted to update you all on are
the responses to those mandatory rfis are due on August 30.
And like everything that we've committed in this investigation,
all those responses will be filed publicly under Project No.
56822. And my
last note here is to thank the investigation
team that's been working really, really hard overdose the last
two weeks to get this investigation stood up and moving
very quickly with a tremendous amount of information that's being
researched and sought for. We've got nearly
a score of individuals in the Commission, from Cisrom
to Consumer Protection, our enforcement group, infrastructure group,
public engagement, and the rules and projects team.
It's a great effort that they've undertaken.
Undertaken.
And I know hopefully
I can speak for Connie, but I'm certainly thankful for their work and
we've got a lot more work to do and we'll
be leaning on them heavily to do that, as well as all
their kind of normal day to day stuff. So thanks for that. And I'm happy
to answer any questions about the status of the investigation. Absolutely. A tremendous
amount of work done already, but as you said, a lot more to do.
And so if any companies that received rfis have questions or
concerns, feel like there are portions that they might have problems
filling out, this is a staff led effort. So their
best course of action would be to contact staff. That's correct. Perfect.
Commissioners, any questions for Barksdale? Just one.
So if I happen to be one of these utilities in the area
that was canvassed, which was at least for some of
the RFIs, I think were in the extended declaration
area. Yes. Okay. So,
and if my, my utility was not impacted,
do I need to respond? My utility was not impacted. What's your
expectation there for that utility? Right. So if,
if your utility received a direct
communication from Commission Staff asking for responses to the request
for information, we expect you to answer the questions.
And if the questions imply that there was some sort of
impact to your area, simply just, you can respond that there
was no impact to my area or, no, I did not
use mobile generation or, you know,
you know, the questions that you're asking are not applicable and that's
okay. But we do need a response. Okay. Thank you.
Thanks. Okay. Thank you.
Thanks, y'all. Okay,
(item:43:Chairman Gleeson lays out Project No. 56897) So now let's go ahead and call up Items 43
and 44 together. That's Project No. 56897,
electric utility outage trackers and hazardous condition reporting.
(item:44:Chairman Gleeson lays out Project No. 56898) And Project No. 56898, provision of emergency contact
information to transfer transmission, distribution utilities by retail
electric providers. So I think these are two,
the reason I wanted to bring these up. I think these are two good examples
of what we committed to that issues that we could deal with quickly,
we would look to deal with quickly. And so I want to thank staff
for getting to these two, which came up in both legislative
hearings that I testified in. So, David, with that, if you want
to lay out the PFPs. Yeah. (item:43:Commission Staff's David Smeltzer on communication & outage trackers, 56897) Thank you,
Commissioners and Thomas. I think that our first
slate of rulemakings that will come out of the Beryl investigation
focuses on attempting to increasing and addressing some communications
and coordination issues that came out of barrel and other
incidents. The first of these is to require
tdus to have an online electricity
power outage tracker. This is an essential tool that allows customers
to go online and find out updates about, you know,
power outages in their area, how it could affect their community and neighbors,
maybe check on relatives. And so we've laid out some basic
requirements that we think that these trackers should have,
and we're interested in comments on additional features and functionalities
that they could and should have. This rulemaking also
addresses another coordination issue that can occur where electric
utilities have the ability to temporarily
stop providing electric service if it's needed to address a dangerous or hazardous condition.
And so, of course, with any situation like this, they need reliable
information that's accurate. And one
way to get that is from state agencies with areas of expertise in this,
such as the Railroad Commission or the State Fire Marshall,
the Public Utility Commission. So we're working on coordinating between
those agencies on a staff level. And what this rulemaking asks
utilities to do is to establish a process, to be
able to work with staff, to establish a process to be able to receive
information efficiently from these state agencies so
that they can determine whether or not they need to shut off power so that
a hazardous condition can be safely addressed.
(item:44:Commission Staff's David Smeltzer on emergency contact to TDUs by REPs, 56898) The second rulemaking that we have to do has to do
with individual communications that customers receive during these outages.
And I know that one of the frustrations that folks had during
Hurricane Beryl was lack of reliable information
about what was happening to them in particular. And so essentially,
we are going to sort of flip the script on this. And right
now, customers have the ability to opt in to receiving communications
from their TDU. And essentially, we're going to change the default to opt
out. And the way that we do this in the rule is we're requiring
retail electric providers, who are the primary folks
who interact with customers today. You know, they handle most of the customer relationships.
So they have all the information to provide this information to
the transmission and distribution utilities so that they can issue
emergency contacts. And so we're very sensitive whenever
a customer, private customer information is involved.
And so we're very narrowly tailoring the uses that this can be
put to. It can only be used for communication of power outage
statuses and restoration timelines and updates across
both of these rules, you know, whenever, just because we want to move quick to
address these problems doesn't mean that we don't really want to get it right.
And so, you know, we really welcome comments from all the entities that would be
involved in the exchange of these information. And one favor that I have
is if you're a utility or a rep, that's responding
on either of these rules. If you file comments,
include in those comments a short description of your current capabilities.
So you know, this is how we currently share information. This is what our electric
outage tracker is currently capable of, just so that
we can make sure that we are,
have all the correct facts and we can present you all those facts so that
we can adopt the rule, the best possible rule,
you know, in another month or two when we get to it. Very good,
and thank you to you and again to the rule team for getting this done
and this PFP put together so quickly. Commissioners,
any comments? Questions? (item:43:Commissioner Cobos lays out her memo, 56897) I had a memo in each of those projects.
And so with respect to Project No. 56897 related to
the electric utility outage tracker, I proposed
two changes for our consideration. The first one being that the outage
tracker provide information both in English and Spanish where applicable.
The second one being that the utility would
be required to immediately notify the commission of the outage tracker unexpectedly goes
offline. And those are the
two changes that I think would help enhance the rule for better
communication with the public and also
so that we're aware when the audit tracker's down with
the utilities. Commission Staff
agrees with these recommendations. They're very thoughtful and fantastic and so
we would, we would advise today that you,
that you would approve us to publish the rules as filed,
but with the added concepts,
we'll go back and put them into the draft before we, before we publish.
Perfect. Thank you David. One thing you mentioned
about asking the commenters,
the utilities, to provide information about their current outage tracker.
It would be helpful to get a link so that you can click
on it and go look at the outage tracker as they
provide that information or comments. (item:44:Commissioner Cobos lays out her memo, 56898) So the
next project, Project No. 56898, related to the provision of emergency
contact information to the TDUs. I propose one change,
and that is to recommend the proposal be
amended to require the tdus to provide the affected customers
with information about power outages, estimated restoration times and
restoration updates in both English and Spanish. And I'll
leave the flexibility there for you to coordinate with the
reps and the tdus to figure out what the best practices
are there. It's my understanding that sometimes the
Reps customers state that they have a preferred language and
maybe it's more feasible in that regard. But I think that
to the extent we can get to a place where we can provide the information
in both languages, that would be helpful. I think that's a great idea.
So under our consumer protection rules, a rep has
to provide communications to a customer in the language in which they were
enrolled. So this makes sure that, you know, whatever you solicit their
business in, they get all the communications from that. I think we're interested in
comments from retailers and customers on whether or not that practice should be extended
through to the way they receive information here, and then whether or
not tdus are, you know, to what extent they're logistically capable of that. So comments
on how to appropriately handle these issues, I think,
would be well received. Anything else? (item:43:Motion to approve proposal for publication, 56897)
Okay. (item:44:Motion to approve proposal for publication, 56898)Then I would entertain a motion to approve the proposals for publication
in Project No. 56897 and 56898,
consistent with Commissioner Cobos memos and our discussion.
So moved. Second. I have a motion and a second. All those in
favor say aye. Aye. Opposed? All right. Motion prevails.
Thank you. Thank you, David. Okay, so now
we're going to go back to the top of the agenda with the contested
cases. So item two
was consented. So Shelah, will you lay out Item No. 3
please? Yes, sir. (item:3:Petition by Outside City Ratepayers appealing the water rates by the City of Leander, 53063) Item No. 3 is Docket
No. 53063. Petition by outside
city ratepayers appealing the water rates established by the
city of Leander. Before you is a SOAH proposal for decision.
The ratepayers and Commission Staff each filed exceptions. The ALJ's
declined to make changes to the PFD. The Commission heard oral argument
from the parties at the June 13 meeting. And Commissioner Gleeson
filed a memo in this docket. (item:3:Chairman Gleeson lays out his memo, 53063) So in my memo, I think,
in summary, you know, I agreed with the result of the
proposal by the ALJ just for slightly different reasons that are outlined in
the memo. Happy to take any comments or questions
on the memo. I'm in agreement with your memo.
Okay. (item:3:Motion to adopt PFD with modifications & deny appeal, 53063) Then I would entertain a motion to adopt the PFD
with modifications, and deny the appeal as outlined in my memo
inconsistent with our discussion. So moved. Second. I have a motion and a second.
All those in favor say aye. Aye. Opposed? Motion prevails.
Shelah, that'll take us to Item No. 6. We lay out Item No. 6,
please. Yes. (item:6:Application of Onalaska Water Supply Corporation to amend CCN in Polk County, 54820) Item 6 is Docket No. 54820.
The application of Onalaska Water Supply
Corporation to amend its certificate of convenience and necessity in Polk
County. Before you as a proposed order. No parties filed exceptions
or corrections. And Commissioner Gleeson also filed a memo in this docket. (item:6:Chairman Gleeson lays out his memo, 54820)
So I believe we should grant the good cause exception for the reasons outlined in
my memo. Happy to take any questions or comments. I agree.
I'm in agreement. Okay. (item:6:Motion to approve the good cause exception, 54820) I will entertain a motion to
approve the good cause exception as discussed in my memo in direct OPDM to
modify the order approving the application consistent with my memo.
So moved. I second. Motion and a second. All those in favor
say aye. Aye. Opposed? Motion prevails.
Shelah, that will take us for my portion before I hand
it over to Commissioner Cobos. That will take us to Item No. 19.
Will you lay out Item No. 19, please? Yes. (item:19:Petition by residents of Grand Lakes M.U.D. No. 2 appealing water rates by the District’s Board of Directors, 56589) Item 19 is Docket
number 56589. Petitioned by
residents of Grand Lakes Municipal Utility District number two.
Appealing the water rates established by the district's board of directors.
Before you as a proposal for decision.
Exceptions to the PFD were filed. The ALJ filed
a response that did not recommend any changes to the PFD. And Commissioner
Gleeson filed a memo in this docket. (item:19:Chairman Gleeson lays out his memo, 56589) So I agreed with the outcome in
the, in the PFD. But really filed the memos to make changes
to the order to provide guidance and more fully explain what
I think the right decision is, which is to say we have a lack of
jurisdiction, therefore should dismiss. Happy to answer any questions.
I'm in agreement with your memo. I'm as well.
Okay. (item:19:Motion to modify the PFD, 56589) I will entertain a motion to modify the PFD consistent with my memo.
So moved. I second. Motion and a second. All those in favor
say aye. Opposed? Motion prevails.
Shelah, I think that takes us then to Item No. 23. Will you lay
out Item No. 23, please. Yes. (item:23:Joint Application of Southwestern Public Service Co. and City of Lubbock, acting by and through Lubbock P&L to Transfer CCN, 56142) Item 23
is Docket No. 56142.
The joint application of Southwestern Public Service Company and the
city of Lubbock, acting by and through Lubbock power and light to transfer
certificate of convenience and necessity right. Before
he is a revised proposed order. And Commissioner Gleeson.
Chairman Gleeson filed a memo in this docket. You could
have gone with what David Smeltzer did and just call me Thomas. Yes.
(item:23:Chairman Gleeson lays out his memo, 56142) So you know the way I feel on this.
I want to grant this application. I thought. I thought the record was a little
light and unclear. And since the applicant bears the
burden of proof to explain compliance with the statute, I think we should remand this
back to OPDM as outlined in my memo.
So happy to answer any questions.
Supportive. Supportive. Supportive. Okay. (item:23:Motion to remand proceeding to OPDM, 56142) I will entertain
a motion to remand the proceeding to OPDM as outlined in my memo.
So moved. I second. Have a motion and a second. All those in
favor say aye. Aye. Opposed? Motion prevails.
Okay. With that, I will hand it over to Commissioner Cobos.
All right. Thank you, Chairman Gleeson. Shelah, can you please lay out Item
No. 17? Yes, ma'am.
(item:17:Rate-Case Expense severed from Docket No. 50788, 56273) Item 17 is Docket No. 56273.
Rate case expenses severed from Docket No. 50788.
Before you as a proposal order. No parties filed exceptions or
corrections. Commissioner Cobos filed a memo in this docket.
Thank you, Shelah. (item:17:Commissioner Cobos lays out her memo, 56273) So my memo basically sets forth the
basis for modifying the proposed order to
grant Windermere's request to recover zero and rate case expenses.
Windermere is the applicant seeking to recover reasonable rate
case expenses that incurred in the underlying appeal in Docket
No. 50788 and
granting Windermere's amended request to recover zero instead
of denying their request. And so
if you agree with me, that would mean that we would also
amend ordering paragraph number one to reflect that decision.
I think you've done this in a good way. Thank you. And move
this even further towards certain. So I support the memo. I support
the docket consistent with the memo.
I do as well. Agreed. All right. (item:17:Motion to approve proposed order with changes, 56273) I move to approve
the proposed order with the changes that are laid out in my memo.
So moved. I second. All right. All in
favor, say aye. Aye. All right, no opposed. Motion passes.
Okay, that moves us to Item No. 19. Shelah, can you please lay that one
out? I believe it
was. Oh, No. 20. I think Chairman Gleeson already did that.
We're off to Item No. 20. Can you please lay out that item? Yes,
ma'am. (item:20:Application of the City of Lubbock acting by and through Lubbock P&L to change rates for wholesale transmission service, 54657) Item 20 is Docket No. 54657.
The application of the city of Lubbock, acting by and through Lubbock power
and light, to change rates for wholesale transmission service.
Before you is a SOAH proposal for decision. The parties
filed exceptions and the SOAH ALJ filed a response,
declining to make changes to the PFD. Commissioner Cobos filed a memo in
this docket. All right. Thank you, Shelah.
(item:20:Commissioner Cobos lays out her memo, 54657) So, as explained in my memo, I would move
to adopt, or my recommendation is to adopt the
PFD in part and reject the PFD in part.
The changes to the PFD that I would make are with respect
to the debt service coverage ratio and the payments in lieu of taxes.
With respect to the debt service coverage ratio, I would
be in favor of approving a 1.5 ratio
for the reasons set forth in my memo. I agree that the whole
harmless payment should not be included in the company's calculation
of the debt service coverage ratio, but for other reasons
set forth in my memo, I believe that the commission should
approve a 1.5 debt service coverage ratio so that the
utility has the ability to make their payments for
expenses and debt owed
and not violate their bond covenants. And then the second area that
I would modify the PFD on would be
to reject the ALJ's recommendation that LP&L's
payment in lieu of property taxes are appropriately included in tcost.
I believe that these payments should
be disallowed under PURA 35.009.
Based on the reading of that statutory language,
the utility should not be able to recover those payments
as they are, you know, governed in by the city of Lubbock.
So with that, I'll open it up for any questions, comments, additional feedback?
Just one question, maybe clarification. There also
was the issue of whether they could recover their franchise fee under
pura 35.09. I'm assuming,
since that's in the order, that an agreement that that's
approved. Yeah. I would be in favor of adopting the ALJ's recommendation on
that issue. I am as well.
Okay. All right.
If I don't have any more comment on that one. (item:20:Motion to adopt in part & reject in part the ALJ's PFD, 54657) I would move to
adopt in part and reject in part the ALJ's PFD,
consistent with the recommendations I made in my memo.
Second. So moved. I second. All right. All in favor,
say aye. Aye. None opposed. Motion passed.
Takes us to Item No. 22. Shelah,
can you please lay that item out?
Yes, ma'am. (item:22:Commission Staff’s Petition for Declaratory Order regarding opt out of securitization uplift charges by Transmission-Voltage Customers, 56125) Item No. 22 is Docket No. 56125.
Commission Staff's petition for declaratory order regarding opt out
of securitization uplift charges by transmission voltage
customer. Before you is a proposed declaratory order that
addresses the request for relief in this proceeding. And Commissioner
Cobos filed a memo. Thank you, Shelah.
(item:22:Commissioner Cobos lays out her memo, 56125) So my memo would recommend that
we approve the proposed declaratory order with
the modifications set forth to remove a conclusion of
whether TIEC's issue should be addressed
in the declaratory order. And so
that would essentially lead to making a determination that
or a clarification that the opt out by transmission voltage
customers is not transferable to another entity and not address
TIEC's issue at this time.
(item:22:Commissioner Glotfelty asks to delay decision until next open meeting, 56125) Madam Chairman, this issue's a little confusing to
me about how and when these uplift charges
should be and when they can be passed
on. I'm wondering.
I'm a little torn on this, and I'm wondering if we could delay a
final decision on this until the next meeting, if that's
acceptable, Shelah?
Yes. The other Commissioners are amenable to that? No,
if you need more time, I'm fine with that. I'd appreciate that.
All right, we'll put a pause on that and defer it to the next open
meeting. Okay,
moving on I guess, to Item No. 28.
Shelah, can you please lay out that memo? Yes,
ma'am. (item:28:Application of Energywell Texas, LLC for a Retail Electric Provider Certificate, 56651) Item 28 is docket number 56651.
the application of Energy well, Texas, LLC,
for a retail electric provider certificate. Before you is an appeal
of Order No. 2 filed by Energywell. And Commissioner Cobos
filed a memo in this docket. All right. Thank you, Shelah. (item:28:Commissioner Cobos lays out here memo, 56651) So my memo
is just straightforward in respect to.
I would recommend that we deny energy wells appeal of order number two,
which denies energy wells motion for a good cause,
to 16 TAC 25.107(g)1 for the
reason set forth in my memo. And those reasons are the fact that after
winter Storm Erie, we adopted the rule that
put out very straightforward language that said
that in no instance, and we went out of our way to add that language
in there. And so I think, based on the rule
language in this particular circumstance,
that we would not be able to grant a good cause exception,
and that would result in the denial of
energy wells appeal.
(item:28:Commissioner Glotfelty's thoughts on the memo, 56651) Madam Chairman, I think I
find myself coming down a little bit different place on this. There's only
two sides to it. One, either you grant the good cause exception or you don't.
One of my questions was,
were these rules in 25
107 promulgated after or
as a result of the legislation that prohibited
companies like gritty from forming?
That was as a result of Winter Storm Uri and in the incidents that happened
with gritty at the time. And I think my heartburn here is just that.
We're doing a look back. We're basically saying, no,
you can't. Let me just tell you, I talked to a lot of people who
were customers of gritty, and they loved gritty up until winter
storm Yuri, and a lot of people want it back. That's not going to happen,
obviously, because of legislation. The question becomes to
me, if you are doing this,
if we put the rule in that prohibited
anybody from participating as
an rep who had been in that spot before we did that after the
gritty experience, should we not give that exception
to allow these folks in it? This is not, I don't believe, a widespread
issue. And I don't know, I just,
I sense that we need more competition in the retail electric market,
not less. And I just throw that out for discussion
of thought. Yeah, I hear what you're saying, Commissioner Glotfelty.
After Uri, we took a lot of actions to
ensure that we fixed issues that occurred during
Yuri. And this was one area that we focused
on. And our commission found that, you know,
griddy violated some protocols and rules. And that's why ultimately,
ultimately, there was language added to that rule
that said if you're a rep that has to go through a polar and your
standard form agreement at ERCOT gets terminated. That under those specific circumstances,
if you're a principal within the last six months to the
transition and the specific facts there, that in no instance
would you be able to come back into the market. And maybe
we. Right now, the rules are written the way it is.
And I don't think there's a whole lot
of will room, but we can go back and
reconsider kind of, you know, now we're past Yuri and
think about role amendments in the future that might make sense.
But, you know, at that time we
went through extraordinary measures to add that specific language
to prohibit principals from reps under those
specific facts from being able to reenter the market.
And I believe ERCOT has taken action on their end
with protocols, et cetera, to not allow that
sort of, you know, reentering of the market, too. So that's where I came
down on it. You know,
we put that language in there for a reason. And that's. That's basically
where I think that I would go
because of the specific language we put in there that added a
strict prohibition. Madam Chair?
Yes. (item:28:Barksdale English with clarification on memo, 56651) If it's okay, I'd like to just provide a quick clarification.
And it's not appropriate for me to weigh in on the deliberation,
but just as a clarification.
Commissioner Glotfelty, you're correct that the wholesale index rule did come about
after Winter Storm Uri.
The retail electric provider rule 25.107
did contain provisions prior to Winter Storm Uri
that would prohibit a principal whose rep
certificate had been revoked from serving as a
principal or a controlling member of a new rep.
Following that revocation, the amendments to 25.107
did contain some clarifications, or I think staff
would call them clarifications about what control means.
But the concept that principals whose
certificates had been revoked should not come back into the market that
existed prior to Winter Storm Uri. Okay, that's helpful. Thank you very much.
Okay, any more comments? Is this the first time this rule has
been brought before the Commission thus far after Uri?
I think so, but I would ask staff if they recall any other instances.
I don't believe we've had another set of principles from a company that
was subject to those facts. Come back before to try to get a
rep certificate with a different rep. I believe thats
correct. This is the only such application we've received.
Okay. Any more feedback, Mister Jackson?
Okay. (item:28:Motion to deny Energywell's Appeal of Order No. 2, 56651) With that, I would move
to deny Energywell's Appeal of Order No. 2.
Second. All in favor? Or
do I need to move? Did you move it? Well, I moved to. Yeah,
please. It's been a long day. Go for it. I moved that
we deny the appeal consistent with your memo, or for the reasoning behind your
memo? I second. All right. All in favor, say aye.
Aye. All right, none opposed. Motion passes. Thank you.
All right, I think that takes us through the end of the contested case docket.
Now, we'll now hand the gavel back over to Chairman Gleeson.
Thank you, Commissioner Cobos.
So that'll take us. So, 30 and 31 were consented.
(item:33:Chairman Gleeson lays out Project No. 55999) So I'll take us to Item No. 33.
Docket No. 55999, reports of ERCOT.
And I believe ERCOT has an update on the RMR
MRA. And I think we also have representatives from CPS here as
well. If they'd like to come forward, if they have any comments.
Good morning or good afternoon, everyone.
So, I don't think anything's being asked of us today. This is really
just informational to talk about the RMR associated with
the Braun egg plants. So, Davita,
if you'd like to begin? (item:33:Davita Dwyer, ERCOT's Sr. Corporate Counsel on the RMR process & ERCOT workshop, 55999) Davita Dwyer with ERCOT.
And with me is Woody Rickerson. And thank
you Chairman, Commissioners for the opportunity to come and speak with you
all. I'm amending my comments to be a little bit shorter
in the interest of time. I'll note that we filed
in Project No. 5999. Two updates
for you all regarding the RMR process. There are interchange
Items 52 and 53, and an issue
that we wanted to bring to your attention was a timing issue with respect
to potential RMR service by CPS Energy's
Braunig Units 1 through 3. CPS Energy gave
us advanced notice about their intention to indefinitely suspend
these units, which we've appreciated that
retirement is proposed to take place on March 31 of
next year, which poses a timing issue because we understand
that the unit cannot be run after
their proposed retirement date unless and until they are inspected
and potentially repaired. And ERCOT is
proactively planning ahead for next Spring,
next Summer and all of the following seasons as well. And we are
evaluating whether or not we should
contract with CPS Energy to have them take earlier outages
before potential RMR service in order to potentially
have those units in place if the board determines that they are
needed for RMR service, and also give the board better information for
at least one of those units when making the decision whether or not to enter
into agreements for RMR service, must run alternative service
or address this reliability need in other ways.
And I'll note that each unit is anticipated to take
approximately 60 days, barring unforeseen circumstances,
and each unit has to be done separately. So part of the
issue is the need to thoughtfully plan
for this service. We also highlighted for you all some
cost considerations, and CPS Energy provided
a letter and attached cost estimates that we attached
to our filings to help you all understand some of the important considerations.
Davita, you are hosting a workshop this afternoon?
Yes, sir. Thank you for raising that. So, we're holding a workshop on the must
run alternatives. That's the process in which we are seeking,
under the Commission's rule and under the ERCOT protocols. Lower cost alternatives
to potentially entering into RMR service with the Braunig units.
And hopefully, we get active engagement participation in
that as well, to help drive down costs. Yes, sir. We're seeking all
sorts of. Of different types of little r resources, including demand
response, including other types of entities that are smaller
than large generation resources, registered with ERCOT. And we're hopeful to
find some lower cost alternatives.
(item:33:Carolyn Shellman, Law Firm of Enoch Kever, Lawyer for CPS Energy concerning RMRs, 55999) Good afternoon. My name is Carolyn Shellman. I'm a lawyer
with the law firm of Enoch Kever and I'm here today representing
CPS Energy. And I have Gabriel Garcia here with
me, who's Regulatory Counsel for CPS.
And my law partner, Andy Kever is here. And we have
several of the CPS Energy executives
who've been working on this project with Davita
and the ERCOT team. To try to figure out whether there's a way that these
units, if called upon could be available.
So, I don't want to repeat the what Davita has said. But I want to
make sure that the Commission is aware that CPS Energy is
here, ready to support ERCOT if
it's determined to be necessary and there's a feasible way to do it.
The units that she has described, the three
Braunig units, have been part of a
long, broad, long term plan that CPS Energy has.
They are aging fossils units. The decision was made
over a period of time to retire them next
year at the end of March. And so they made an announcement of
that and notified ERCOT with plenty
of time, knowing that it's a lot of capacity to retire.
This is a total of 859 mw.
These are old plants, 50 plus years old, and gas
fired projects that CPS no
longer needs, but does plan
to run them until their planned retirement date in
March. And so that's what we have worked with ERCOT on,
how this could be done. And we commit that. We will be prepared
to coordinate with ERCOT as
needed if the plants are selected for an RMR contract.
But what I want you to understand is that CPS has been
done everything that's necessary to keep these plants running safely
and reliably. But we have not undertaken
the major repairs that you would do if you
were going to extend the plant life beyond that
planned retirement date. So our engineers,
I think, are very comfortable that the plants can continue to
run through the time plan to operate them. But prudence dictates
that if we're going to commit to run them after that,
and not just prudence, just engineering practice, it dictates that
we would need to inspect those units. And that's a big process, opening up
each of the three units separately, inspecting them, doing whatever
maintenance is necessary, and making decisions about major
repairs that would need to be done. So that is what we
have tried to estimate and
explain to ERCOT all the details of that.
And I know that there's information that they are sharing with you so that
you can understand what we believe our best estimate
is of what's going to need to be done and the
cost that would be involved in doing that. And so we, Gabriel and I,
are prepared to answer questions if you have them. And if we need to,
we'll call. Call on our folks who can get down in the weeds on it.
(item:33:Chairman Gleeson's question concerning notice of suspension of operations, 55999) Do you know when you all provided ERCOT with a notice of suspension of operations?
Yes. March. Gabriel knows.
Was it March of this year? It was
a year prior to even the requirement, is that right?
March 13 of this year.
So you said, you know, you stopped doing kind of the big maintenance
that you would do if you were going to keep this going. How far in
advance of that notice of suspension of operations did you stop doing the required
maintenance on these units?
I think, I wouldn't describe it that way and subject to
being corrected by my counsel here, but I think
that what we have done is all the necessary planned
work that you would do to keep plants running. We have
since looked at some life extension studies to
see what it would take to extend them longer.
But I think that this has been part of a plan to close
those plants over several years,
but nothing has happened that would
decrease their reliability and safety. Up till now,
we just haven't done any major life extension.
I would add that five years ago, we did
an investment to extend their lives for five years through March
of next year, hence their retirement date
of March 31, 2025. Okay.
Well, Commissioner Jackson, I think really what we're talking about here is risk
mitigation. I know you're big on identifying and mitigating risks.
One thing I think I would also say is, depending on how
the MRA process goes,
it may be worth looking at having staff work with ERCOT to look
to see if there can be improvements to this process
to provide low cost alternatives. I think we're going to see, with our
aging fleet, our dispatchable fleet, we're going to continue to see
notice of suspension of operations. And so I think that probably deserves a look
at what that process is and see if there can be any improvements.
(item:33:Commissioner Jackson's question on management of risk, 55999) And I guess, just from a management of risk standpoint and
looking at all the alternatives, one of the things that I
think ERCOT is thinking about is, you know, going in
and doing an early look see, maybe trying to see if there's an opportunity to
take it down in the Fall so that at least we have a better idea
prior to, you know, getting into,
you know, the Summer months or the next Winter, and possibly
considering taking it down in the Fall. And as you noted,
it would take 60 days, and the strategy would
be to look at the newest unit first, which would be unit number
three. The largest unit. The newest, yeah, exactly.
412. You know, one of the questions
I had was, you know, knowing kind of like the
history that you've laid out in terms of the maintenance, the fact that
you didn't do the life extension repairs five years ago,
you probably, you know, have somewhat of an idea of what you're going
to go in and find, whether you would do the look see
early in the Fall or whether you would wait and do it, you know,
closer, you know, or after the March 31 time
frame. But is there a way to go in and,
you know, not necessarily take the whole 60 days,
but do like a cursory view, particularly if you're
going to find something major to help you make that decision
quickly, because I guess the option would be, you go in, you take a look,
you say, okay, this is major. This is x number of dollars. You weigh that
cost versus the benefit, and you'd say, you know, that's probably not
the option we want to take, going to look at going down a different path.
But that might give you an opportunity to make the decision quicker, get back
online and still have it available until the
end of the commissioning date, which would be March 31.
I think we would meet the assistance of one
of our experts to answer that question in
an accurate manner today. But, I mean, I think that that might be something we
should. We can certainly provide that information.
And I know that ERCOT is,
you know, is looking at this as well, and looking at
it from the standpoint of, you know, come March 31,
you know, we've had the option. We either make the investment or March 31,
we have to do something else. Oh, I'm sorry.
Aren't there some opportunity, you know, what is the benefit of getting an early
look at what we're dealing with and then having more
time to do some of the things that you talked about with having,
you know, alternative sources again to
meet a pretty significant shortfall in dispatchable?
Yes, I agree with Gabriel. I think exactly
what we could do when we opened them up and whether we could do just
a little bit is something that we'd need somebody else to
speak to. But I would, you know, one of the things that I think CPS
is concerned about is that in order to get this done
in the fall and not wait until next April,
contracts would need to be, the contractor would need to be
procured. And there is a cost in getting everything ready
and getting the crane there and getting. Opening it up. So there are
probably significant expenses just in doing that.
But I do nothing. I can't answer whether you
could get in and just look at it a little bit and we will explore
that, make a quick decision, you know?
Yeah. Yeah. It sounded
like it was up to 60 days. So you might be able to
go in there after the plan is open and have a really good
idea. Yes. Earlier than 60 days. Because I think
that the concern I have is the, you know, obviously it's
going to be expensive. Expensive. Right. Just to even open up the plant and go
in there. But also the lost opportunity costs
that we're having, you know, the repairs, the loads are having to
pay for the plant being down. I understand it's a
necessary part of this whole evaluation because of the.
For safety reasons, but ensuring that we
minimize that if we can.
If there's an opportunity to get in there and get it done in 30 days,
if there is. Right. We don't want to rush through something like that, but if
there is, and also to make sure that
the lost opportunity cost is
calculated in a manner that everybody feels comfortable
with, the amount of money that would be paid for that. Yes. So we
understand that. Certainly agree.
(item:33:Commissoner Hjaltman's question on outages, 55999) Have the outages you've taken in the past five years that you've come
up with the plan differed? Have you stopped taking as
many outages because you thought you were going to not be
using these plants anymore so that we would be expecting to see more damage to
the plants coming forth? I don't think that would be the case.
From my understanding of it, I think that we
have done all the maintenance that would be usual and planned
in order to keep those plants running in accordance
with the five year extension. And, you know, if you
go in and find out you have to replace rotor blades and a
lot of tubing in a plant, we wouldn't be opening up to
do that. But, yes, I think we have done the safety of those plants,
both for the operational necessity and just the employees that work.
There is something that CPS pays a lot of attention to. So I'm
sure that what has been done has been prudent and necessary all
along. I would add that of the three plants,
unit three is the one that runs the most.
We've had problems, you know, with unplanned
outages because of the age
of the units, you know, which is to be expected,
so. But unit number three is the one that is
utilized the most of the three units, and it's the
largest.
Do you know anybody who has some mobile generation for
lease?
I say that in jest, but I don't know, maybe it's.
We can introduce you to Jason Ryan behind you.
Woody, I have a question for you on this. And that is this.
The total cost of this RMR package, including the
future or the potential maintenance, is like $150
million, is that right? (item:33:Woody Rickerson, ERCOT's SVP & COO on RMR analysis, 55999) Yes. That's Woody
Rickerson with ERCOT. Yeah, that was the estimate,
roughly.
That's hard. I mean, this is one of those hard decisions that
we got to make for the good of the system or, you know, to spend,
you know, that much money on old plants. It's not easy.
I just wonder, you know,
I know this
is a transmission issue. We've had these discussions. The question becomes,
how does the system look
today and over the next twelve months,
with the addition of more solar and more batteries on the north
side of the constraint? Are these,
does any of this transmission
issue get solved as a result of that, or does
it continue to fester?
Yeah. So the analysis we used took into account all
known new resources that were coming online. So if something's coming
online next Summer, it's already in the interconnection queue. That has already
been factored in into the RMR analysis.
Even with those factored in, we still show IROL
overloads on that Pawnee to spruce line. So there
could be new generation show up that we haven't
accounted for. And you don't know what. You don't know yet,
but that could happen. And anything north would help.
A new big data center north of the constraint would
hurt. And those can come online just about as fast as
the new generation. So additional
resources in the south will make the problem worse.
And the IROL is.
I don't claim to know a whole lot about that. But is
that like, when that is designated?
Right. So it's basically a,
it's basically a line that if you let it overload
and the contingency were to happen, it would result in cascading
outages. So you have to avoid the cascading outages so
you don't let the line overload.
Right. Obviously, we don't want cascading outages,
nor do we want an overload on that line, according to, according to ERCOT.
I guess the question, I just, maybe I should
just table this and talk a little bit more with you about it later
on this week. I guess we're not going to finalize anything today.
No. I think this is going to come up at the ERCOT board meeting next
week. And then I think you all indicated you may
need to take the fall outage. You may need some exceptions
to your own, your rules, some of what we've done in the past. So that
I think might come up at the August 29 open meeting. So we'll have other
opportunities to talk about this as well. So I'll reserve everything else for you.
(item:33:Gabriel Garcia, CPS Energy's Regulatory Counsel on costs, 55999) Commissioner Glotfelty, I'd like to provide a little more context. Gabriel Garcia, for CPS
Energy, regarding cost. With regards
to what we call the pre RMR cost, which are
taking these outages in order to inspect them, we estimate
those costs to be about 22
million for unit three,
about 15.8 for unit
two, and 17.3 million for unit one.
And that would, that includes the outage opportunity
cost and also some repairs to
extend the life of the unit. So the
larger number that Woody referred to are
the best estimates right now, which clearly are,
without doing an inspection for,
you know, for entering into an RMR contract. But the pre
RMR outage inspections are the numbers
that I, that's, that's our best estimate of what those costs would be.
Thank you. But you would only take one unit at a time and your
thoughts take the newest one and the largest one first.
Correct. So if the one
idea would be to do one unit, unit three this fall,
and we may or may not do others after
March or sometime into next year, but just
want to give you an idea of, those are our best
estimates right now. Of course, once you open them up for inspection,
then we'll have a much better idea as to what
the repairs would cost and also how
long it would take to conduct those repairs.
I mean like Chairman Gleeson, I would really encourage
you all to, and resources out there. To take
advantage of the MRA process. I know you all are having a workshop this afternoon.
I don't know how many resources you all ultimately get. And I think
that looking for ways to help mitigate costs
is really important. The MRA is one. One avenue on
doing that. The other one is,
and this may be more of a question for you, Woody and
David. So CPS has provided
their lost opportunity costs based on their calculation.
Are you all in agreement, or are you all looking for ways to
further explore how lost opportunities should be caught
calculated? We're still working on understanding
the assumptions that were made and what elements
of those assumptions might be things that would be subject to true
up after the fact versus what are things that are essentially unknown.
And we're talking with CPS about their calculations
because obviously that's an important component of this. Yeah,
I think that that's really important to look
at that specific cost component like you described.
Maybe some kind of an ex post review or a clawback provision
evaluating the capacity factors of the plants,
just to make sure that we're not, you know,
want to be fair here in terms of opportunity costs, because you're taking the plan
out, but we also have to be cognizant of, you know,
the load cost as well. So I encourage you all to
continue to work on a process that makes
sense on addressing both issues. I'll note that's consistent with the RMR
construct. For example, it includes estimates of
what the costs of repairs would be after the fact.
We would know what the actual costs were, and those could be trued up.
All right, thank you.
Hey, Woody, can I ask you one other question? When you all do the
IROL limit, is it based upon certain.
Does it look at 8760 hours of the year? Or is it just
like, between certain times when there's the likelihood that that line
could trip and then create a
cascading outage? So,
first of all, we're calculating it in real time, obviously, right?
So we're controlling to a real time limit,
but when we do the analysis, it's an 8760 type analysis. So we're looking
at. We're doing it a summer. It's going to have a summer rating, a winter
rating, that kind of thing. Okay,
thanks. Okay,
thanks, y'all. Thanks for being here. Thank you very much.
So I don't have anything on 34. (item:35:Chairman Gleeson lays out Project No. 54584) So that will bring us to 35.
That's Project No. 54584, reliability standard for the ERCOT
market. Werner and Chris. Werner,
I want to thank you for following a memo that elicited no calls from any
market participants to my office.
Very much appreciated.
Yeah. (item:35:Commission Staff's Werner Roth on changes to final rule and memo, 54584) Werner Roth for Commission Staff. And I'm sure all of
you received plenty of phone numbers, calls. I know our leadership on staff side received
phone calls on this, and I received a couple myself. So,
yes. Anyway, so what about the commission staff? So,
ahead of filing the proposal for adoption that will be up for approval at the
August 29 open meeting, staff has identified several key issues
that were raised in the comments. Responding to the approved proposal
for publication, staff member provides a brief summary on each of
these issues or initial recommendations, and today we seek guidance
from the Commission for any direction as we work to incorporate the necessary changes
into the final rule. So the first one
in the topic that prompted most of the phone calls, I would imagine, was the
application of the reliability standard. As there's always been
on this topic, there was a split within the comments, with some parties advocating
for the standard to be a target and serve as the report card of the
health of the market, and other parties stating that the standard should be boarding that
requiring action when the ERCOT region is deficient of meeting the reliability standard.
But more than anything, commenters were insisting that the commission needed to provide clarity
on how this standard would be applied in the PFP.
The current language requires that ERCOT performs its assessment every two year or
every five years, and if it finds that the region is deficient at
the reliability standard, they would provide recommendations to the Commission on actions that would alleviate
this deficiency. However, within the rule, while the
commission would be expected to review the assessment, the rule language does
not require the Commission to take any specific action on these recommendations.
And that was done intentionally. In staff's view, requiring the
commission to take immediate action on the results of the assessment absent
allowing for the Commission to consider potential cost implications and review
alternatives, including non generation alternatives, is not consistent with the requirements
to balance reliability and costs.
And I'm happy to go through the others if you want? Yeah. Why don't
you lay out the whole memo and then we can go back. Perfect. Okay.
So, second, there were requests around establishing the standard
through either expected unserved energy or normalized expected unserved
energy, EUE or MEUE. The positions of
these commoners included that an EUE metric alone effectively captures
all of the three metrics, frequency, duration and the magnitude
of events, and that using the newly updated estimates for cone and volume would
allow for an EUE standard to be set at the economically optimal value.
Staff continues to recommend the three metric reliability standard that has been reviewed through
the ERCOT process for the last year. Having individual metrics for each
of the three criteria provides a clear policy objective that can be understood by
the broader public. Like the rest of the industry, we aim to
avoid loss load events, the frequency one in ten standard, but on top
of that, we are putting additional emphasis on avoiding long duration and high magnitude
events well. Additionally, staff continues to oppose
establishing a reliability standard where it would be possible for the target to be
less reliable than the industry one in ten standard, and basing the standard solely
on the economically optimal amount of EUE would result in
that happening. Third, the PFP
included a question about whether the explicit exceedance tolerances
should be enshrined in the rule. Again, commenters were split on this,
with some preferring clarity around the defined risk thresholds and others
wanting the flexibility in evaluating future assessments.
Ultimately, staff believes that there is value in continuing to have the exceedance
tolerances of the tried in the rule. The tolerance provide a clear policy goal
to limit how frequently high magnitude and high duration events are
expected to occur. And because they are in the rule, they would be set by
the Commission and would require a formal rulemaking with input from public comments to change.
Fourth was the allowance for public comments. While the commission
always has the ability to allow windows for comments,
several parties pointed out there wasn't anything explicitly in here. Staff agrees that
that probably should be enshrined, and so we've recommended 230 day
comment windows. One after ERCOT provides the list of assumptions that would
go into the assessment that they perform, and then a 30 day comment window
after ERCOT has provided the results and recommendations to allow for public comments
on the results as well. Fifth was
the frequency of the review of the assessment. Again, not much to talk about here.
We originally proposed five years aligning with the what's already in our
rules requiring the system wide offer cap programs
to be reviewed every five years beginning in 2026. Because system wide offer caps
could be something that could be changed to meet the
or beat the reliability standard, most commenters expressed concern that this
was too infrequent, and staff agrees and we are proposing
to modify this to a review every two years, as we believe this
would provide a sufficient snapshot of the resource adequacy picture while
not overburdening ERCOT or Commission Staff with an annual review as was requested
by some parties. All right, just two more.
All right. 6th there were concerns around the magnitude metric.
Some of these concerns included a lack of clarity and transparency on how
the sum value was determined and how this metric was the most
sensitive to the modeling assumptions, where a few extreme hours could drive high
cost outcomes. Staff acknowledges the concerns around the
volatility and the sensitivity to the modeling assumptions, and we've proposed relaxing the
exceedance tolerance on the magnitude metric from the original 0.25
proposed in the PFP to 1%. We believe this strikes a more
fair balance between the continuing to express the importance of planning to
avoid these really high impact events while avoiding expensive
outcomes driven by modeling assumptions. Staff also recommends
adding a requirement for ERCOT to file an updated megawatt value
for the amount of load shed that can be safely and effectively rotated, which would
set this magnitude metric at least annually. And then prior to
2026, the first assessment, we're encouraging ERCOT
to work with the transmission operators and other stakeholders to memorialize the
detail on how this number is calculated to provide better clarity and transparency
within this protocols or wherever else is appropriate. And then lastly,
but certainly not least, there were concerns around balancing
reliability cost. And I admit this was an oversight on my part.
The PFP did not include an explicit requirement for including costs
estimates in the results of the assessment. So to address
this, we will be adding a requirement to the rule for ERCOT to include
their estimate of the cost to comply with the reliability standard.
And because we will allow public comments on the results of the assessment and recommendations,
there will be an opportunity for parties to provide alternative estimates of the costs
if they disagree with their cost methodology. So that summarizes the
current staff recommendations on those issues. Again, no formal action is
going to be needed today, but I'll be diligently taking
notes during this discussion, and I'm happy to answer any questions. Thank you for
that layout. Commissioners. Questions, comments?
(item:35:Commissioners thoughts and questions on memo, 54584) I have a couple. Just appreciate
the hard work. You know, these things since Winter Storm Uri
are confusing, commingled. A lot
of them work together and I appreciate all the staff.
Just two things. One of them is, I'm totally supportive of the target.
I think tying our hands on what the levers we change
to add capacity or to understand how
we address market mechanisms to add generation
should be left up to us, not totally triggered
by this standard. So I'm totally supportive of the target.
And then the other one is on EUE. I continue
to look at things at NERC. NERC is moving
away from one in ten. They say that one
in ten does not create a reliable system.
Let's move to the next metric. So all
I would. I'm not trying to move away from the three legged stool that has
been created. All I'm trying to do is see if we can, when we talk
about that standard we can add an EUE number with it,
since it's just math from. It's a mathematical equation
from the three legged stool. So we can calculate the EUE
as well. Yes, that was included in the PFP
language originally, where EUE would be a reported result from the assessment
for each of the system configurations they're looking at. So, yes, we will absolutely make
sure that is included.
Since we referenced the word target, I really think. Can you
give some definition to what that would look like if we
were to run and adopt this target,
which we already have, sort of a target set? So how is that different than
what we're doing now? What happens if we find that that target is not
being met? What will the commission then do? Game plan that out is what
that looks like. So the difference between what
we do now and what this would do is that it would effectively require
a review every two years. And ERCOT. Report back to us.
Okay, this is like. This is the current health of the market. This is what
the resource adequacy picture looks like now. This is what we expected it like in
three years that is currently absent from the process here.
So we do have the CDR and we do have the SARA reports.
We do have certain documents that do come over here every so often. But this
is a targeted report on this, just showing. Do you meet this reliability standard,
yes or no? If no, ERCOT would
be required to provide recommendations. It could be moving levers on
different ancillary service products, increasing volume. I mean, there's. I'm not.
I can't give an entire list of all the possible solutions, but essentially
providing the commission with possible ways to address that deficiency,
the commission would consider that they could decide,
okay, we like that solution, that we can move forward with that. If we
look at the solutions, the costs associated with all of them to address a small
shortfall is billions of dollars. It might say, okay, that's not reasonable.
We can defer it a couple of years to the next and see if
the issue persists and address it. Then.
There's. We're trying to provide some flexibility in how the
commission would address these deficiencies without tying the commission's hands on how they would
necessarily resolve it. I think that's appreciated. I'm just wondering if
there's word different than target we might be able to
identify, get out Arthasaurus
and see if there's something different. So I.
I'm fairly certain we did not put the words target or mandatory or anything like
that in the rules. We just had the request and the,
when we had got the comments on the PFP and we wanted
clarity on the staff position on what this currently is. I mean, we would not
put target anywhere in the rule and there's no plan to do so at
this time. And I think everyone I talked to agreed for
95% of this process until if
the analysis shows that we are short generation,
I think there's one camp that believes that we get
those options and then we decide if
through a cost benefit analysis or whatever, whether or
not we want to do anything. I think there's another side that believes if
the equation doesn't work out and we are short generation,
this rule needs to say we will take action and we will
make the math, math. And if we're 3000 mw short,
will find a way to incent the building of those 3000 mw.
So I think, you know, I don't know what y'all's calls were like, but that's
basically the gist of where I think a lot of this,
again, the way you just talked about that, that's building of
capacity. And as we move towards what ERCOT has
said, as we're moving towards an energy based system,
that adding that capacity is not always the
way. We've seen that one in ten. It hasn't worked in TVA
and PJM. Last winter, I think during winter Storm
Yuri, we were probably well over a one in ten standard.
So I'm with you on that.
I feel like we should have the discretion to figure out what the tools are
that we utilize. Besides,
ORDC is already in there as a mechanism that can
help solve this issue. And, you know, Dr.
And others that will be coming in the future if we don't even know what
tools we have yet, what they look like,
I'd say keep the target until we know what the toolbox looks like.
Chairman, excuse me, please. Yeah,
so I agree with Commissioner Glotfelty that we should
also use the EUE as a metric,
not surpassing the three legged stool, as he called it,
with duration and magnitude. But EUE is important. I think
other markets are looking at it. SPP looks
at expected unserved energy, normalized expected unserved
energy might be a little bit better of a metric, just so that
we know what EUE is as the system load changes.
So I think it is a helpful additional perspective on the
reliability standard with respect to Chairman
Gleason's comments about,
you know, what are the two camps saying and some of
the questions from the other two commissioners.
It's complicated, right. Because if you're deficient.
And we're required to go out there
and move around ancillaries or the ORDC,
or the ancillary service demand. I mean,
we could go do that. And we've done that, right? We've made
changes to the LRDC to try to incent investment in
generation. We added a new ancillary
service, ecrs, that's put, you know, additional money
in the market. We're going to have drs,
obviously, real time popularization. But the fact of the matter is that
even if we go make these adjustments to whatever
existing market mechanism we have in the market, currently in our energy
only market, and we add more revenue, that does not
necessarily mean we're going to get more capacity.
And I know that the answer is, well, in that case, you want a regulated
market, but not even in a regulated market can we force capacity
to be built. So I guess that's the part where
it's like, and I appreciate your statement. Your statements is like, we can't tie our
hands because we often do go
in and make changes and all the changes have
some kind of consequence, right? So we start turning the ancillary
service market into a capacity market because all of a sudden we're deficient 2000.
We're just going to start buying more ancillaries and removing more
megawatts out of the market. Then the real time energy prices
will increase. There's just, there's a lot, a lot there.
If you just turn to the ancillaries ORDC,
we've done a lot to the ORDC in the last several years. And the ancillary
service demand curves, they're still in flight right now. So I'm
not real sure and open to hearing about
what some of those changes could be or
how it could be implemented in a way that makes sense.
But I come at it from the perspective of like,
I don't want to tie our hands in a process either.
And, you know, tie our hands, tie future
commission's hands. And we need to remain cognizant
of the fact that it's tough in this,
you know, in a capacity market. You know, and I've
covered MISO and SPP, different versions of capacity markets
than PJM. If you're wanting to try
to create an opportunity to get more capacity built, well,
then you go and increase
or add planning reserve margin requirements,
or create a demand curve like the reliability
demand base curve. We have what we have in our market with
more tools to come. But it's just, I don't
know that we can be in a position where we're just constantly turning levers
with the existing tools and expecting to get that deficiency
because it is a competitive market and we can't,
even if we put more money in the market, that doesn't necessarily mean we're just
going to get more power generation. It doesn't always equal
that. So, anyway, just some comments.
So, you know, for me, it's a process, and I look at it from
a process standpoint. And, you know, our starting point,
you know, further to your question, you know, about what's changed and what's
different is, you know, the standard that we are developing,
you know, is 3d. It's much more robust with
the intent of not having the big fluctuations
that we saw in the past, the scarcity market, something that is,
you know, is more stable.
So our starting place is better. You know, the staff putting
the two year timeframe in, which provides that
appropriate amount of time to gather a data set that
is representative and something that we feel confident that we can look at
and get a good timeframe and a good representative
sample, if you will. And then, of course, the ERCOT
then would go and publish the
proposed modeling assumptions, but then the staff
interjecting the next step, which is providing
the opportunity for the market participants to come in and have
input over those modeling assumptions, which impacts the
final outcome. ERCOT does the assessment,
and then, of course, as part of this assessment,
ERCOT would look to see, okay, are we meeting the standard?
And if not as part of that assessment, we'll then provide the recommendations and
then interjecting another opportunity for stakeholder
comment on the recommendations. And then with all that,
including now reporting the, the unserved
energy, which is another data point,
it comes to the commission. And, you know, from my standpoint,
you know, that is the human intervention part, that is the part
of engagement and leadership by the commissioners.
And what, quite frankly, I see as my
job to be able to take, you know,
this data that has been established, that has been gathered,
the assessment that's been done, the recommendations that have been provided,
and take thoughtful and deliberate action. And so,
you know, I'm more focused on the process. Is the process
robust, which I feel like it is,
is the process something that is clearly outlined
and has all of the necessary steps, which I feel like it does,
and, you know, use that
as, you know, what we are really kind of
focusing on as the key to our success. Now,
I have heard, as many of you all have, from a lot of people who
have commented on this, and some of the stakeholders have
said that they are concerned that if this last
step, this requirement that we actually take
it up and look at it,
it needs to be something that is specifically
required by the rule. And so,
I mean, my only suggestion at this point would be,
do we need to maybe clarify
this final step in the process and the rule? I know that we've got the
language in there right now that we typically use in terms of when the Commission
will consider something and then determine whether or not they want to take action,
but that would be my only thought. And again, it is, because that is
what some of the folks that I've talked with have said,
at least in their mind, would give them more confidence,
I guess, in the process. (item:35:David Smeltzer gives clarification on memo, 54584) Yeah, that's correct
Commissioner. When we were discussing this in briefing, I think you were asking
if there were different words we needed to use. And I think that right now
it says the commission will determine whether or not market changes are necessary.
And I think that folks that are used to reading statutory language
might like to see a shall clause in there. And so with the commission's
drafting practices, we use may and must when we're talking about other folks,
and we use may and will when we're talking about ourselves.
If we can do something, we use may if we are going to do
something, we use will to reflect fact that the Commission intends to do
something we don't use must or shall with regards
to ourselves, because you guys could always just good cause accept out of the requirement
on yourself anyway. And so when folks read, the Commission will
determine that is read in the same way that you
would read some other party shall determine or whatever. So to
the extent that there's concern that the numbers would just come in and we would
never look at them, this rule is designed to have the Commission at
the end make a proactive determination about whether or not
market changes are going to be required in response to
recommendations from our CoD if there's a shortfall. So commission
staff believes that it's taken care of, but we are happy to take another
look at the language and provide any recommended edits to really
button that up by next session if we, if we think, or by next open
meeting if we think that it's necessary. Thank you. And as part of that
process, you talked about, you know, cost benefit
analysis, I guess, being done by ERCOT. Right. And that being subject
to stakeholder comment as well.
I think it's important that the IMM is also involved in the cost benefit analysis
evaluation in that process.
Just to clarify, are you wanting a joint cost benefit study from ERCOT?
And IMM, or separate, like, two separate views on the cost of the
different solutions. I mean,
in some ways, I feel like you need another pair of eyes looking at the
cost in that analysis that's being prepared. So,
yes, joint. I mean, we're having them do a joint for the
PCM cost updated cost assessment.
The cost benefit analysis is a critical component of this
entire process. So I want to make sure that it's a developed
in a robust manner and the opportunity for. Stakeholder comment.
I will say, you know, we have a lot of changes happening in the market,
a lot of loads coming on, and the market's in flux. So I think
two years makes sense to be going through this exercise. But I'm just
wondering if ultimately, the commission's going
to end up on a two year resource
adequacy on a cadence of a two year resource adequacy debate
going forward, you know, because, I mean,
I could see that happening. And if. I'm just wondering if that's
the ultimate result of this process, I have
that question, too. Just how long these studies will they take
to. Will you finish one and start immediately again?
Are you going to be constantly tied?
So, I mean, I'm happy to punt that question to ERCOT if they have someone
here, but my understanding is that, I mean, this entire cycle would be completed
well within a year. It's not as if it would roll over into the next
year. I'm almost envisioning if we started this in 2026,
we would have final results and something that could even be included in the legislative
report, in particular,
for the first cycle, I would think you'd want to do two years.
(item:35:Barksdale English on PCM cost benefit analysis, 54584) Excuse me, Commissioner Cobos. Just want to clarify
something. The PCM cost benefit analysis are being
run concurrently, but independently by the IMM and
ERCOT. So we'll get two sets of analyses from that. And so,
just for clarification, for our edits here,
are you seeking to have ERCOT and IMM
collaborate together on one analysis, or are you asking
for two separate analyses? That same process sounds right,
yeah. The parallel. Okay, thank you. The same process you're using for PCM. I appreciate
that clarification, and thank you for the clarification. It's been a
while since I thought about that, and we'll have time between now
and next open meeting when we have to adopt something. We can talk to IMM
as well and see what their thoughts are.
Anything else? Not on this one.
Werner, Chris, David do you all need anything else from us?
No, I think we have what we need to get a PGRR drafted.
Okay. Thank you, all of you, for your work on this.
Truly.
Okay. (item:36:Chairman Gleeson lays out Project No. 55837) That'll bring us to Item No. 36, Docket 55837,
review of value of lost load in the ERCOT market.
I will just note we'll probably have to take another short break
here, like 130 ish for
a few minutes, probably 10 or 15 minutes, and then we'll pick it back up
if we're not done by then.
Hello again. (item:36:Commission Staff's Chris Brown with update on VOLL study, 55837) Chris Brown, Commission Staff.
Just a very quick verbal update on the ongoing VOLL study.
So, the survey of customers in the ERCOT region wrapped up earlier this
summer. Brattle has been working on the report
and the results of that survey. Staff has received a draft of this and we're
working through it. And we'll plan to file a memo
next week for the August 29 open meeting, reviewing the results
of the survey and providing some recommendations on where to
go with the volume value that will
be used for ongoing studies and cost benefit analyses,
planning models, things of that nature. In kind
of your first look at what came in, was there anything surprising, or did it
pretty much fall in line with our expectations?
Nothing surprising. We're still working through more, some of the more
technical details, but we'll definitely have a
better review at the next open meeting.
Questions? Okay,
thank you. Thanks, Chris. (item:37:Chairman Gleeson lays out Project No. 55000) So,
Item No. 37 is Docket No. 55000.
Performance credit mechanism. Werner?
Welcome.
(item:37:Werner Roth on PCM design parameters, 55000) So, because my reliability standard memo didn't cause enough controversy and
phone calls. I figured we would also file recommendations on some
of the PCM design parameters for this open meeting.
So, to allow for the Commission to have multiple meetings to discuss
the design parameters, staff has provided its initial recommendations on what the
final values for these design parameters should be.
I don't plan to walk through all 37 design parameters today,
but I did want to flag one recommendation in particular that will have notable
ramifications on the outcomes of the PCM, namely design parameter number
20, which is the framework utilized to comply with the net cost cap.
So, throughout this process and in the workshop that E3 held
at ERCOT, E3 has been determining the net cost by calculating
the difference between a world where the PCM is in place to incentivize sufficient capacity
to meet a reliability standard, and a non PCM world
that has been that where we've added or retired enough capacity to be
at the long run market equal of the market design as it currently exists.
From a peer modeling perspective, it's a reasonable way to determine
the net difference between the cost of the PCM and one without it. And if
I were in their position, I probably would have recommended a similar methodology.
However, the very first PCM guardrail statute requires that
the commission ensure that the net costs to the ERCOT market
of the PCM does not exceed $1 billion annually.
Any counterfactual non PCM world will rely on several assumptions
which make will make ensuring compliance with this provision and statute extremely
difficult in staff's view. The only way that we can ensure
that we are able to satisfy this provision is to cap the compensation for
performance credits at a firm $1 billion annually, with the allowed adjustments
for increases in that peak and inflation.
This does come with a couple of downsides. It does potentially leave
money on the table, as we are not accounting for the energy and ancillary service
savings from having the PCM versus not having it. And most notably,
it would limit the ability of the PCM to achieve the reliability standard by itself.
So further actions may be needed to do that in the future.
Again, no formal action is required today, but we will need
for the Commission to make its final decision on the 37 design parameters at the
next open meeting so that we can give ERCOT and the IMM sufficient time to
conduct their respective benefits cost assessments.
My understanding is that ERCOT and E3 will be filing their report at their
recommendations soon, within the next week or so, and commission
staff will file its final recommendations prior to the August 29 open
meeting. With that, I'm happy to take any questions. So I'll say that
in the last week I've heard the term counterfactual more than I
had heard in the previous rest of my life, and so
appreciate that. So just to talk about the statute.
So the statute requires us to ensure that the net cost does
not exceed $1 billion, and what you're saying is the best
way to do that is to put a gross cap on the PCs of a
billion dollars. I'm saying that from the staff position right now, that is the only
way to ensure that we are complying with that, because any counterfactual is
going to have assumptions that could be people
can poke and prod at and pull apart, and then, oh, is that really what
the world would have looked like if the MPCM hadn't been in place? And while
the report isn't finally at, I just look at the counterfactual from the market
equilibrium and what e three's final report is going to be. That assumes the energy
only world results in a lole of 3.0.
Not 0.3, but 3.0, essentially resulting in about 30 loss
of load events per decade. I cannot envision any world where the Commission
would allow the market to achieve that level of reliability in
the long run. And so the idea that we wouldn't make any changes to
avoid that outcome makes it more that quick. That counterfactual
example is questionable, and I
think that would come with any counterfactual example where you're comparing what
we have versus what we might have had if this hadn't been in place.
Can I just ask, like procedural? So, next meeting,
we're going to approve these. Are we going to approve them as a,
like, take staff recommendations and do we approve it like that,
or are we going to go piece by piece, or how are we.
Yeah, I think my preference would be, we'll have their recommendation.
If there needs to be any change to what they're recommending, I think that's where
we'd focus our conversation. Thanks.
Yeah, I mean, I don't have any real specific feedback.
I think two areas that I discussed with staff was just the allocation of 12
hours to both the Winter and the Spring. It seems like you'd want to allocate
more hours to the Winter, and that's just something we can
talk about next open meeting. You know, Winter seems to
be the riskier part of the year and having the
same allocation there. Just had some questions
about that and then the hours
with the metric used to determine the PC hours. Hours with
lowest surplus of total available generation capacity relative to load.
You know, that's an area that I had some questions about as well, just because
our blueprint really focused on net peak
load. And I'm just wondering if there's any unintended consequences.
If you're looking at the
lowest surplus of total available capacity is, you know, you have
maybe some potential power or power plants that are not available.
What does that mean? For various reasons, but, you know, we can
have a conversation about that. Those were two areas that I just had some questions
on and with staff.
But other than that, the rest of my commentary can wait till next
opening.
Thanks y'all.
Do we need to take a break or are we? 30
minutes?
(item:38:Chairman Gleeson lays out Project No. 56896) So that will bring us to Item 38,
Docket 56896. Texas Energy Fund,
an ERCOT loan program reports and filings. We have an update
from Staff. (item:38:Barksdale English with update on Texas Energy Fund 56896) Good morning Commissioners. Oh wait,
it's not morning anymore.
So staff filed a memo laying out its process for
how we will bring to you at the next open meeting.
Recommended Portfolio of Applications for the Texas Energy
Fund in ERCOT loan program for your
consideration to invite those applications
into the due diligence process. In the memo, we outlined
that we've received more than 70 applications seeking
more than $24 billion of funding, with over 38,000
potential new generation. As we go through those applications,
we will be assessing them on the each application on
the more than 60 questions that they had to answer through the application process.
We've kind of compiled those 60 questions into
four basic categories, the first being related
to project technical and regional attributes, the second,
project financial attributes, the third,
application sponsor history, and fourth, the application
sponsor financial characteristics. We will assess
each of those applications individually, relative to all the other
applications on each of those four metrics. And then,
in individual conversations that we've had with each
of your offices, we've gleaned some common
overlaps in public policy priorities that your
offices have identified, which will include the diversity
of the applicant types. Diversity and I siting location,
the speed to market that the project is proposing,
the ability of that project to relieve known transmission constraints,
and the diversity of generation technology types.
And so we will take each of those five policy priorities and layer
them on top of those four basic categories in order to develop
the recommended portfolio. Next week, we will present
you individually with binders,
either in paper or in electronic format,
that will show you the assessment of this information. And I will note
that all the information that's been provided in those applications are
confidential by law. And so we're not,
you know, able to disclose a whole lot of information publicly about
the, about those applications at this time.
But we'll go through and gauge your feedback
on, on the recommended portfolio that we'll present to you next week.
And then at the August 29 meeting, we'll consolidate
all the feedback that you've provided and present publicly the
portfolio for your consideration. Happy to talk about
any other process questions that you'd like and any
other questions that I can answer. So, at the 29th
Open Meeting, how do you envision the approval process going? Will we be
to Commissioner Glotfelty's previous point.
Obviously, a lot of this is confidential, so I imagine we
won't be going project by project. So how do you envision that process on the
29th working? Thank you. So we will have
a portfolio of applications presented for your approval
in the meeting. We'll disclose the name of the applicant,
the megawatts that the project represents,
the general location of that project designated
by load zone, the ERCOT load zone.
And then we'll also have some basic kind of ranking criteria
and just kind of how that application satisfies each
of the kind of four basic criteria, as well as the remaining
policy priorities that you all have identified for us.
Our hope is that you'll be very happy with the portfolio
that we present to you and that you can approve an order that
would delegate to connie the ability to enter
into a loan agreement with those applications,
provided that the project and the applicant satisfies
the due diligence requirements that they will be
invited to enter into following that vote.
So a delegation, similar to what we do for contracting purposes, it would be exactly
like that. And I was just to clarify
for the public, once we go through this process,
the other applicants that were not selected are not just sitting
there waiting. If one of them falls out, this is the
end of this process. If the commission
would have excess money or the legislature asked us to do it again,
we would go through another RFP process. Correct. So the
action that we contemplate you all taking at the August 29
open meeting would not make a formal designation
or declaration on any of the applicants that wouldn't be invited to
due diligence. So because the legislature
has appropriated five of the $10 billion,
we're looking for the most amount of flexible, both from the
applicants as well as from the commission, in order to
kind of keep the trains moving as quickly as possible, because we
have a lot of statutory deadlines that we're trying to hit here, as well as
a lot of legislative intent
to try to optimize the number of megawatts that
we're getting into the ERCOT region through this program.
So, Barsdale, on that, you know, we've been
given, I would say, some guidance that I think
it's likely we'll get the other 5 billion. Is there a timeline
for where, you know, approving the most,
the maximum amount of megawatts and dollar amount? We would need to know that
that money is coming to the commission in order to make those awards.
Thanks, chairman. It's probably
the end of February. Beginning of March is probably about the last
time that we can really make any substantive pivots.
And I arrive at that date for the following
reason. We know that the due diligence process could take up
to eight months, and our consultant
has advised us to leave about 60 days
for execution of a loan agreement, as well
as kind of the back end administrative processing in order for the
first loan distributions to be made by the end of the year. So that really
kind of backs us into that end of February, beginning of March
timeline.
Okay. Any other questions? Thank you Barksdale.
(item:41:Chairman Gleeson lays out Project No. 53911) So that will bring us to Item 41. That's Docket
No. 53911, aggregate distributed energy
resources ERCOT pilot project. And Commissioner Glotfelty,
you filed a memo. (item:41:Commissioner Glotfelty lays out his memo on ADER ERCOT pilot project, 53911) I just wanted to say,
obviously Commissioner McAdams is not here anymore. We are.
This is a valuable, potentially a really valuable product
in the market. This is. This memo is to keep
the trains running. We don't know what on time is. This is not a directive
of staff. This is a directive of like, how are we going to keep this
thing going? So I put these questions out there, not for
resolution today, but really for the
task force to keep working, to come back to us with answers to these questions
and to figure out how we could, you know, keep utilizing
this pilot project or have it become an official part of the market.
Okay. Yeah. Just kind of keep us apprised of what you may need from us.
Yeah. All right. Thank you.
So next, I think that takes us to item 49.
There's no docket number. It's discussion possible action on electric reliability,
market development, power to choose, ERCOT oversight, transmission planning, construction and cost
recovery. So Connie, I think you
had an update maybe on Permian. (item:49:Connie Corona gives update on Permian workshop) Yes, there just
a reminder of workshop on August 22,
one week from today in this room at 9:30 to
review the plan for the Permian basin.
Okay, thank you for that. Did you have a 47?
(item:47:Chairman Gleeson lays out Project No. 41210) Okay, we'll go back to Item No. 47.
That is Project No. 41210.
Information related to the Southwest Power Region State Committee.
All right. (item:47:Commissioner Cobos provides update on SPP RSC, 41210) Thank you, Chairman Gleeson. I just wanted to provide a brief update.
On August 5, the SPP RSC meeting or
committee met, and the RSC and ultimately
the board of SPP approved an increase
in the summer PRM that would take effect in summer
26 from 15% to 16%,
and then established a winter PRM of 36%
that would take effect the Winter of '26-'27
and would apply to '27-'28 Winter seasons.
These PRM decisions were
passed overwhelmingly by the majority of the RSC.
Texas and Oklahoma opposed. And the.
The SBP staff is expected to quickly,
probably by the end of this year, early next year, start moving towards a discussion
of increasing the summer PRM from 16% to 17%
and establishing around a 44%
PRM. So those are very large percentages.
And they, you know, it's got
a lot of concerns by our LSEs, or LREs, as they call
them, an SPP, about the ability to comply
with not only the 36 and 16 that were approved by the SPP,
but definitely for the 17 and 44%.
And so the way you meet them is by making investments in your existing generation
to ensure they're available to perform, building new capacity
or buying excess capacity from another LSE,
LRE, or merchant generator and SPP to comply. So there's,
there's impacts, I think, cost,
and also, and I say cost in
terms of, you know, spending money to add
new plants, but also costs. If you don't come, if you're not able to meet
the PRM, then you have to pay a deficiency payment. And SPP
did create sort of a curve to try the. So that you're not paying outsize
deficiencies. It's based on the actual deficiency amount that
you are actually short. So they did make some improvements
in that area. But ultimately,
it's a lot of pressure on our LREs that are operating in SPP in
Texas. And then also, you know,
it will have a downward impact on the switchability of
the generation units, that switch between ERCOT and SPP.
So I just want to provide that update. Any questions?
Okay, thank you for that update. (item:57:Chairman Gleeson opens up item to PUC's COO, Hayley Hall) So I
think then the last item we have will be Item No.
57, which is normal, where we get an update from our Executive
Director or Deputy Executive Director. But today our Chief Operating Officer,
Hayley Hall, has an update. Believe our appropriations request
is due tomorrow. And this is the first appropriations
request since 2010 that I've had absolutely nothing to do with. So I'm in a
bit of mourning. So no pressure.
(item:57:Hayley Hall, Commission Staff's COO on Legislative appropriations request for FY '26-'27) Good afternoon, Hayley Hall for Commission Staff. We are putting the finishing
touches on our legislative appropriations request for FY '26-'27,
which starts a year from September.
Thank you to Jay Stone, Nathaniel Lilly, Jess Heck,
and Casey Green for their contributions to the report.
The legislature did not ask state agencies to make an across the board cut this
year. So our baseline budget is basically the same as our FY
'25 budget, more or less. And then we're asking for five
exceptional items in addition to the baseline budget.
One is for additional staffing kind of across the
agency, but really concentrated on the contested case process to deal with,
with kind of demand for services and our caseload
growth across the board. The second is to develop
a case management system. This was a recommendation from the Sunset Commission
to gather better data across the contested case process,
automate where we can, and provide kind of an across the board tool to
have a chance to analyze our data, look for trends,
and kind of make sure our resources are allocated efficiently.
The third is related to infrastructure,
reliability and resiliency. We have a lot of additional work in
that area. So it's a request for additional staff for
additional CCN volumes, a lot related to
permian basin reliability plans and other reliability plans and
reports on resiliency and those types of things. As part
of that exceptional item, we're asking for funds to create
a Texas version of the federal eagle eye system. That's the
outage tracking database. That would provide a lot more detail
than what the federal system provides in the event of an outage
event. The fourth is related to.
What is the fourth one?
The TEF expansion. So a few additional staff for TEF.
As noted earlier, the response has been a lot more than
what we had anticipated. So it's just a handful of extra staff to
deal with those volumes. We'll be in the monitoring phase of kind of all four
programs at that point and just staffing up for that eventuality.
And the fifth is a replacement of power to choose. That resource
was developed in the early two thousands. The last significant update to that
was in 2015. So it's just time for a
refresh with kind of an updated modern architecture user interface.
Do you know offhand what our current FTE cap is and
what these exceptional items would take it to? Our current FTE cap
is 283, and this would add an additional 53
FTEs to that. Do we have
all those FTEs filled at 283? I think right now
we're at about 253. So we've added about
50 FTEs during this past year. Year. And we're continuing to staff
up in the coming years with the FTEs that we got during the
last legislative session. So this would be in addition to that. Okay.
So. And we would go from 283 to. I'm sorry,
what number again, if you's total.
Okay. Okay. So, yeah. Like over 300, 330 something.
So I am glad you're doing a review of the contested case side
of our business. The just.
The Permian basin alone will have a litany of CCEM proceedings
that our staff has to process within 180 days, not to mention
the other contestant cases that were under expedited timelines on.
So I appreciate you taking a look at that. And,
you know, if you need to add more than 53, you may want to consider
that because that's a lot of work, even just on the CCN side of it.
Thank you. Thank you. And I'll say Commissioner Jackson, from the
first day she got here, was well ahead of the Sunset Commission on wanting us
to have a case management system. So. Yes,
I'm happy to hear we're doing that.
Okay. Do you know, do we have any joint
budget hearings or any other hearings coming up this fall that we know yet?
I'm sure there will be hearings. I think they're in the process of being scheduled.
Okay. Okay. Any questions.
All right. Thank you, Hayley. Thank you. All right, I'm going to look to Connie
since I skipped, like, four things this meeting. So I think at this point we're
clear. All right. (item:57:Chairman Gleeson adjourns meeting) This meeting of the Public Utility Commission of Texas is hereby
adjourned.