(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
July 25, 2024. Good morning
Shelah, Connie, Barksdale. (item:0:Chairman Gleeson lays out the flow for today’s agenda) So
Commissioners, what I'd like to do this morning is start
with Public Comment. I don't know if we have anyone signed up, but we're
going to let Shelah run through the Consent Agenda. And then
start with public comment and then bring up the Beryl
related items first. This way, anyone that's here for that can get
through that and then leave, and then we'll take up the rest of the agenda
in order, if that works for everybody? Okay.
Shelah, will you run us through the Consent Agenda please? Yes.
Good morning. Commissioners recusal memos were filed in project
No. 52761. The Chairman is recused from Items
3, 4, 5, 9 and 10. Commissioner Hjaltman is
recused from Items 2 and 7. By individual ballot,
the following items are placed on your Consent Agenda:
Items 1, 3, 4, 5 and 8.
Also by individual ballot, the Commissioners voted to place Items on
the Consent Agenda, and no one signed up to speak on these Items.
Those are Items 13, 14, 16 and 24.
Thank you, Shelah. (item:0.1:Chairman Gleeson asks for motion to approve items on Consent Agenda) I'd entertain a motion to approve the consent items
just laid out by Shelah. So moved. Second.
Have a motion and second. All those in favor say aye. Aye.
Opposed? Motion prevails. All right. I'll call up
Item No. 11 for General Public Comment. Shelah, do we have anyone signed
up? (item:11:Shelah Cisneros confirms 1 person has signed up for General Public Comments) Yes Chairman, one person signed up to speak under Item number
11. I believe it's Savant Moore.
And one question is that, are we sticking with the three minute time limit?
Yes, we'll do three minutes. All right. Good morning, sir. If you could state your
name and who you represent. (item:11:Houston resident Savant Moore gives Public Comments concerning CenterPoint's response to Hurricane Beryl) Good morning Commissioner. Hopefully governor
of you watching this? My name is Savant Moore. I'm a public servant for the
city of Houston. Today I come on behalf of everyone in my city
of Houston, asking you to do the impossible, holding american
corporation accountable, ensure they show us the same respect
they give their shareholders. We are their customers. I stand before
you to highlight a grave injustice my city endured after
Hurricane barrel. While the CEO of Centerpoint and the
VP of utilities went a few hours to two days without
power, my community suffered nine to 14
days, and some on northeast Houston still do not have power.
Our seniors, who depend on electricity for oxygen and insulin,
were left vulnerable and struggling. We must remember the 24 lives
lost, half of which were directly due to power loss.
Let us take a moment to honor their memory. Rest in peace,
Maria Laredo Russell, Richardson Sarah Elizabeth Elston
Johnny Courtney J. Michael Taylor Charles
Richard Anderson Sr. Candy York Oscar Rodriguez James
Edward Butcher Brian Keith Taylor Pamela Jarrett
Thomas Fermin Vergara William Carreras Judy agreed
to Leroy Lyons Michael Lehrer David Smith
Rebecca Smith Charles Yanez Ethel Carter Michael
Pervette Rachel Ross electricity was created
in the late 18 hundreds, yet we still haven't figured out power outage
solutions. This situation reveals a severe lack
of vegetation management and disaster preparedness. By Centerpoint,
I asked, what will this board and the governor do to protect Texans lives
from such mismanagement? To prevent further tragedies and
prolonged power outages, I propose the following immediate
actions. Enhanced vegetation management increase the
frequency and scope of tree trimming and vegetation clearance
around power lines to reduce the risk of outages caused by fallen
branches. Deployment of mobile power units. Strategically position
mobile generators in temporary power units in high risk areas.
Priority restoration for critical needs establish a clear,
prioritized restoration plan that focuses first on areas with
hospitals, senior centers and individuals relying on medical
equipment. Improve communication systems. Implement robust
real time communication channels to keep residents informed.
Pre storm inspections. Conduct thorough pre storm
inspections of infrastructure to identify and address potential
weak points that could fail during severe weather.
Lastly, pre stage restoration teams have teams ready
and pre stage in strategic locations to quickly begin power restoration.
This is a bipartisan issue and a Texas issue, and we
need to find a solution to quickly, because it's not a question if
the next storm is coming, if there will be another power outage,
it's when and when will we be prepared. We must act swiftly
to protect our communities and prevent further loss of life.
Let's honor the memory of those we lost by ensuring this never happens
again. In closing, I leave you with the scripture. Do not
merely listen to the word and so deceive yourselves.
Do what it says. James 122 the
purpose of human life is to serve and to show compassion and the
will to help others. May God bless you, and may God bless Texas.
Thank you. Thank you for being here this morning. Thank you for your comments,
sir.
We have no one else signed up. That's correct. Thank you,
Sheila. So I think the way
I talk to Connie, I think the, and Sheila, I think the best way to
do this, I'm going to call up items number, items 32 and seven together,
and then we'll take up item 33 directly after that.
(item:32:Chairman Gleeson lays out Project No. 56793) So I would call up Item 32, that's Docket 56793:
Issues related to disaster resulting from Hurricane Beryl.
(item:7:Chairman Gleeson lays out Application of CenterPoint Energy Houston Electric, LLC for approval of Transmission Distribution System Resiliency Plan) And Item 7, that is Docket No. 56548,
Application of CenterPoint Energy Houston Electric, LLC for
approval of its Transmission Distribution System Resiliency Plan. And
ask CenterPoint to come up. I would also
like to thank just a few people who submitted letters in
this. So we received letters related to barrel from
a joint letter from Senator Miles, Senator Alvarado, and Senator
Cook. And we also received a letter from Houston's Mayor,
John Whitmire. So I want to thank them for their input as well. Mr. Chairman,
may I say something about Docket 7
which is what we just brought up? Is that right? So we brought up 32
and Item 7. Yeah. Oh, Item 7.
Okay, I'll wait on Docket No. 7 until that time. Jason?
(item:32:CenterPoint's Executive VP Jason Ryan gives update on Project 56793) Good morning, Chairman Gleeson and Commissioners. I'm Jason Ryan,
Executive Vice President at CenterPoint Energy. I have with me today Jason
Wells, our CEO. Tony Gardner, our Chief Customer Officer
and Randy Pryor, VP of our Electric Operations.
Who was also Incident Commander during the
response to Hurricane Beryl. Let me
before I turn it over to our CEO,
provide a little bit of information to you, but more importantly,
the public who's watching. On some information that we filed yesterday
in Project 56793.
So Item No. 16 in that Project is
the presentation that you all have before you, and that, I understand will be
on the screen for the public that's watching, but for people that want a copy
of it, it's in Project 56793, and it's
Item No. 16 there.
We also provided our initial set
of factual documents to help aid in the Commission's
review of what happened during the storm,
leading up to the storm and after during restoration.
That is Item No. 17 in that same Project,
in Project 56793. And I'd
call your attention maybe to a couple of things just to orient the
material. In Tab No. 3 of that document
is a timeline of relevant
facts. It's the beginning of our production
of those relevant facts to the Commission. Things like how many
mutual assistance crews did we call on, when did they show
up in the Houston area to begin work, how many agents
we had in our call center day by day. That kind of
factual information is under Tab 3.
Then under Tabs 7 through 19,
we lay out a day by day with both
those factual statistics of call center agents and outages,
and how many customers we've restored, how much of the emergency generation was used day
by day, but also our communications to our customers
broken up day by day, both in our press releases,
other public information posted on our website, social media.
So you have all that content there in tabs seven through 19.
Under Tab 20 is how our incident
command is structured, again to orient you to
the work that Randy led as Incident Commander.
Going back to the front part, though, relevant to what we'll present
today, is some of our go forward information. Under tab
one is the new communications program that
we will have in place for the next storm. And going forward,
under tab two is our screenshots of the new outage
tracker that will be going live by August 1.
So that gives a little bit of information about what we provided yesterday.
We hope that providing that information early will allow
the fact finding and after action report to proceed quicker,
because I know that the schedule you have laid out in your report to the
Legislature is going to require us to move with some urgency. So we wanted to
provide this information now, and I know that we'll
keep providing information going forward. So with that
if it's okay with you Chairman, I'll turn it over to our CEO. That's perfect.
Thank you, Jason. I think just for. So this goes somewhat smoothly, if we
could withhold our questions until they finish their presentation. I've told them they have
about 30 minutes or so to lay out their presentation.
Mr. Chairman, I do have a comment about the resiliency plan docket. I'm happy
to go whenever you want at the end. Yeah, let's let them lay it
out, and then we can bring, we can talk through those dockets. Okay. Good morning,
Jason. (item:32:CenterPoint's CEO Jason Wells gives apology to CenterPoint's customers and their Pillars of Action) Good morning Chairman Gleeson, Commissioners. I'm Jason
Wells, CEO of Centerpoint Energy. Thank you for the opportunity to
be here in front of you this morning. It is my privilege,
the privilege of all of our leaders and employees to serve our customers in
the greater Houston area. As you all know,
Hurricane Beryl left widespread devastation in the greater Houston
region. Including extensive power outages,
with many of our customers experiencing uncertain wait times for
restoration. In times of emergency, our responsibility
is to respond quickly, to communicate clearly,
to provide accurate information, and to restore power
as rapidly and safely as we can.
I take personal accountability for the areas where we fell
short of our customers expectations. Most importantly,
I want to apologize to our customers for the frustration we caused.
We will do better. While we cannot
erase the frustrations and difficulties so many of our customers endured,
I and my entire leadership team will not make excuses.
We will improve and act with a sense of urgency before
turning to our commitments to improve. I do want to take a moment
to acknowledge and thank all of the incredible work of
our vegetation line and support employees,
as well as our local contractors and mutual assistance crews who worked
in incredibly challenging conditions to restore power in
terms of areas for improvement. I commit that starting immediately,
we will improve our communications with our customers and will take
specific actions to build the most resilient coastal grid in the
country. Slide three summarizes our
initial plan. Additional details can be found on slide 15.
Our pillars of action fall into three categories,
improvements in resiliency, improvements in communication,
and greater collaboration with local partners and emergency
responders. Each pillar of action is designed to
specifically address issues for the remainder of this hurricane season
and beyond to improve the resiliency
of our system, which my colleague Randy will expand on shortly.
We are especially focused on enhancing our vegetation management efforts
and as of July 16, we had nearly doubled our vegetation
management workforce to immediately address the higher risk areas of
vegetation throughout the rest of this calendar year.
To improve our communications with our customers and to address one of
the primary criticisms we received in our response to Hurricane barrel,
we will launch a new cloud based outage tracker on August 1.
Tony will provide more details about this new tool and other actions we
will take in just a minute.
To strengthen our community partnerships and improve on our emergency response coordination
year round. We will be hiring a new senior leader to
join our executive team whose expertise is intended to help
us make the necessary improvements in every aspect of our
emergency and storm response.
We'll also be taking additional actions based on internal reviews,
independent analysis and counsel from emergency
response and communications experts,
as well as through additional feedback from this body, our customers,
our elected officials and our community leaders.
Going forward, our most important priority today in the months ahead
will be to improve our emergency response with a sense of urgency to
re earn your trust, as well as the trust of the millions of people who
depend on us. Our company and the thousands
of men and women of CenterPoint will remain tireless in our efforts
to strengthen our system and better serve the community that
we are all proud to call home. I'll now turn it over to Tony
to cover our action plan. (item:32:CenterPoint's Sr. VP Chief Customer Officer Tony Gardner gives CenterPoint's Action Plan) Good morning Commissioners.
My name is Tony Gardner. I'm the Senior Vice President Chief Customer Officer here at
CenterPoint. As Chief Customer Officer, it's a critical part of my job to
represent the voice of the customers in how we plan and conduct our business.
Since Beryl made landfall, I've personally reviewed hundreds of customer complaints
and hurt their frustrations that they shared with us in the ways
in which we communicated and did not meet their expectations.
I'll personally carry forward those voices as we execute actions
that Jason summarized my entire organization will be
laser focused on improving our overall customers experience for
our communities that we have the privilege to serve. Slide 5
lists the five key areas we've identified for improvement in our customer communications,
and I want to use Slide 6 to focus on the actions we will take
to address in some of those areas.
First, you heard Jason talk about the launch of our
new cloud based outage tracker by August 1, which will accommodate
the new level of increased traffic that we can expect during significant storm events.
This is where our prior outager failed. It was a physical,
server based system which simply could not handle the traffic during elevated
storm level events. Our new outage tracker will allow customers to
see outages based on their counting city or by their zip code.
The application will be mobile friendly and mobile responsive.
After we've launched a new outage tracker, we will continue to make sure that we
engage with our customers and community leaders to get feedback so that we
can continually make sure that we improve on that application.
Second, as a part of our effort to dramatically improve our public
communications, we brought in industry experts to help us develop
an at emergency preparedness and response communications playbook.
This communication playbook will include daily press briefings,
press releases, public advertising, social media and
other tools to engage and inform our customers more effectively during times
or major storms when they need to hear from us the most.
While these specific communications will be led by our corporate communications
arm and our organization, it will be closely coordinated with the customer
communications to ensure that we maximize every possible tool to
keep our customers informed and updated.
Third, we are committed to making sure that we provide our
customers restoration guidance to our impacted service territories
24 hours after a storm has left our service territory.
That guidance will be refined and communicated daily and
our customers will know, based on our situational awareness, where we are in our
restoration efforts. In addition, we will also continue to
drive the adoption of power alert service to increase our ability to push
information to our customers in a timely manner. We recognize that some customers
experienced delays receiving their power alert service messages during Hurricane
Beryl and we're taking the necessary measures to make sure that we can provide
the appropriate capacity to accommodate the use of that
tool during our storms. One thing I would like to
stress to this body is that because our marketplace,
the way our marketplace is structured, we only have contact information for
about 42% of our customers.
That's because we only have direct contact if those customers
sign up for power alert services through us or if the reps pass
that information on to us to help increase the effectiveness of
our direct communications, we may ask you all to
change policy so that we can get contact information from
our reps so that we can improve upon the number of
customers that we can push power alert service notifications to
during storm level events.
Fifth, to address the lengthy hold times that our customers endured
during Hurricane Beryl, we'll increase our call center staffing by more than
165% compared to our normalized levels. To make
sure that we can reduce our wait times for our customers.
Each of our call center agents will continue to go through additional training
during storm season to make sure that they can provide customers
the level of service that they've come to expect and that they deserve.
In addition, we'll be leveraging speech analytics to monitor
our customers experience while they're dealing with our contact center agents during
storms so that we can make sure we provide them the right level of the
right level of customer support and meet their expectations.
In closing, this is just the start of our efforts to rearn our customers
trust. We know that we have a long way to go to make sure that
we can meet our customers expectations, but we're definitely committed to doing so.
And with that, I'd like to turn things over to Randy and he'll talk to
you about how we went through making sure that we restored our power for our
customers during the storm event.
Good morning and thank you, Tony.
(item:32:CenterPoint's VP of Operations & Incident Commander Randy Pryor on the restoration of power after Hurricane Beryl) My name is Randy Pryor and I oversee our distribution projects and
grid modernization programs here at Centerpoint. I thank you for the
chance to speak here today. I served as the incident commander during
the storm, overseeing our preparation, response and restoration efforts.
So let's begin with what happened. We began tracking
Hurricane Beryl, prepping for impact nine days before Beryl made
landfall as a storm began approaching Texas.
Can you speak into the microphone a little more? I'm sorry.
As a storm approached Texas, forecast initially showed that
our service area and Greater Houston would be spared a direct
impact by the worst of the hurricane.
Nonetheless, we remain vigilant. We plan for impact
and secured 3000 mutual assistant crew members, all of
whom would be arriving from locations safely outside of the projected
path of the storm. We also coordinated with
utilities across Texas and our regions to ensure resources
would be available if need be. As the forecast
trajectory changed, we quickly called on additional
mutual assistance crews under agreements that are in
place well before any major event to substantially increase
our crews. As shown on page eight.
Early in the morning on Monday, July 8, Hurricane Beryl
made landfall as a powerful category one hurricane.
It brought heavy rains and flooding. Winds up to 97
knocked out power to over 2 million of our customers.
The powerful combination of extreme winds, along with the
weakened trees and other vegetation, caused significant damage to
our communities. Along with the company's electrical lines,
distribution poles and other equipment.
And with Burl, the extent of trees falling was greater
than what might have been anticipated in previous storms due to additional stress
from winter freezes and droughts. Over the last several years,
the greater Houston area was hit directly by the dirty side of
the hurricane and sustained strong winds for an extended period
of time and far inland. To put the
impact in context, Beryl had peak wind gusts of 97
mph winds recorded along the coast of 91
Bush Intercontinental Airport at 83 mph.
Once the storm had passed through the area and it was safe to do so,
we began immediately dispatching our crews to respond and
assess the damage in accordance with our protocols.
Now let me talk about our response and restoration efforts.
As shown on slide nine, we activated
and deployed over 15,000 centerpoint and mutual assistance
crew members. These incredible men and
women worked 16 hours shifts in hot, humid and
at times stormy conditions. I want to thank these frontline workers
from here in Houston and across our state and
the nation for the service and dedication in restoring power
to our communities. We also coordinated with the
Texas Division of Emergency Management and other local partners
to prioritize hospitals, assisted living centers,
cooling centers and water treatment facilities over
the course of restoration. We ultimately set up 22
staging sites to coordinate and direct our restoration efforts,
although we had to shut one down due to threats of violence against our
crews. We deployed mobile generators at 28
sites across Greater Houston to various critical facilities,
including those I mentioned before going on
to page ten. During our restoration efforts, we replaced
over 3000 distribution poles,
walked over 8500 circuit miles to repair damage,
and removed or trimmed more than 35,000 trees and
or other vegetation. As we turn
to slide eleven, in terms of the
pace of our restoration, we restored over 1 million customers
within the first 48 hours. While the thousands on
the ground worked incredibly hard to restore power and achieve significant
impact in the first 48 hours, it is clear we must
continue to enhance the resiliency of our system to
support faster restoration times.
We have engaged in industry experts in emergency response
to conduct an extensive review of our emergency response
programs. This effort is intended to develop key learnings
to support rapid restoration of critical customers,
improve the speed which we resolve public safety issues,
and improve end to end processes from mutual assistance,
crew activation to crew and work dispatch.
Once this study is complete, we will share these learnings and
recommendations with the commission and other relevant local and
state stakeholders. More immediately, we will
use innovative damage modeling to assist and strategically deploy
our crews and overhaul our processes for work assignments
and staging site selections.
The goal here is very simple we intend to
enhance and have available tools to restore power to
as many people as quickly as we can and as safely as possible.
Given the effect of the vegetation that had on our system,
one of the core programs we will be immediately expanding
is our vegetation management work. Over the past
five years, we have spent over 220 million in vegetation management,
covering more than 25,000 circumahs.
Given the impact that extreme weather is having on
our vegetation, it is clear than ever before that
we must expand this effort. And that is
what we will most urgently do in terms of
the critical role of mutual assistance and the invaluable relationships we
have with utilities across the state and the region.
We will be evaluating how we can better mobilize these critical assets.
And lastly, given the impact the storm had on our essential services,
we will be adding temporary generation units to deploy
and provide power to critical care facilities and
other critical infrastructure. These critical facilities and
essential services depend on us, and we will work
closely with them over the coming days and weeks to identify how
we can best ensure that they have the backup power that
they need. We will work tirelessly
to strengthen the resiliency of our grid,
take further steps to address vegetation risk,
and better coordinate and improve our emergency restoration efforts.
My commitment to the community that I am so proud to serve
is that we will learn, we will take action,
and we will get better. Thank you, and I'll turn
things back over to Jason for some final words. Thank you,
Tony and Randy. (item:32:CenterPoint's CEO Jason Wells gives commitment to strengthen their system & best serve the community) Commissioners, you have my commitment
that our leadership team will work urgently to strengthen our system and
best serve the community we love and are proud to call our home.
As shown on Slide 13, we will be taking these messages from here to our
communities to engage with them on ways we will improve our service moving forward.
We have already started the small group listening sessions and
I look forward to personally being involved in more of these and other
activities over the next few months. Thank you for your
time today and we will update you on the status of our initial action plan
every month and provide a copy of the independent after action
review before the end of October. We're happy to answer any questions you
may have about this material, about our plan to create the most resilient
coastal grid in the country. Thank you all for being here.
Commissioner Glotfelty, I know you had questions on resiliency.
(item:7:Commissioner Glotfelty's thoughts on recalling CenterPoint's Resiliency Plan)Yeah. So I wanted to say something about Docket No. 7,
the resiliency plan. And that is, I was prepared
today to propose that we call recall the CenterPoint Resiliency
Plan from SOAH and hear it at the Commission.
Because of this storm and because of the urgency of the
issue with which we face
here, I feel like the focus of the
resiliency measures. The specific projects contained in the resiliency
plan should be looked at by us very specifically and very
clearly. We must be able to satisfy the timelines of the
Governor and the state leadership to ensure that this resiliency plan
is correct and achieves the goal that they have set out and we
have set out for this territory.
I understand that there's a request from parties to continue
negotiations on this to come to a settlement.
And instead of asking for us to recall that today,
I would suggest that we let them play out and see what we get from
a settlement. I know Mr. Chairman, you as, you said at the last meeting
settlements are good. Let's see if we can find a
settlement here. I want to ensure that we have
the right, as in the law, to modify any plan that's presented to
us. Even if there's a settlement, we must be
willing to bring this back to the Commission to get deeper into the specifics
of how we will ensure resiliency on the CenterPoint system and all
of the systems and all of the resiliency plans to ensure
that the goals of our Legislature and our reliability are set.
So let's let it go forward, let it see
how it comes back to us. But we should be very diligent
about taking these on ourselves as a Commission and hearing the hearings
here as opposed to SOAH. (item:7:Chairman Gleeson to Jason Ryan concerning abatement) I completely agree with
you. Before the request to abate came,
I had a similar sentiment that we probably need to bring this here so we
could hear the case and preside over it.
One question I have, I assume part of the request for abatement is also will
you all be amending the provisions that are
in the resiliency plan that you filed? That's correct.
So what is the thought process behind asking to abate
it, rather than just withdraw it and come up with a new
plan and submitting something new?
So we're certainly open to either. I think as we have discussions
with parties over the next couple of days, let us land on
an agreed path with the parties. I think obviously there are going to
be learnings from our after action. There can be
information and learnings coming out of your own report that
we should incorporate in that, and so we'll work with the
parties. Maybe there are some things that should move forward immediately,
and we can reach an agreement on that and maybe file an amended
plan for the things that maybe should be informed by the work that
our independent assessment is going to show, and that your assessment will show,
too. Okay. (item:7:Commissioner Cobos' thoughts on recalling CenterPoint's Resiliency Plan) So, if you will. So I
came in sort of thinking that the company should withdraw their application and
wait to hear feedback from the Commission, from the Texas Legislature, from your independent
consultant, so that your resiliency plan is robust
based on lessons learned from the Beryl.
And the reason that I believe that it's important to do that is
because you know under your CCN, you have an obligation to serve.
You have an obligation to provide continuous and adequate service.
Getting a resiliency plan approved does not stop you from doing what you should be
doing already to maintain continuous and adequate service for your customers
in your service territory. So in my opinion,
you can move forward with the actions you're already taking, and you list it out
to provide enhanced resiliency for your service territory and
come back and refile a a more robust resiliency plan
that takes into consideration all of the feedback from
the Commission, the Legislature, and your independent consultant. That's my opinion.
I think if we move forward right now, we're not doing a
service to what all the information,
all the work that we're doing, we're going to be doing at the commission through
the investigation, the feedback from the Legislature. You just
hired an independent consultant. We want to make sure we get this right.
But at the same time, you move forward with your resiliency measures and immediately,
and ultimately, when you do file a resiliency
plan, then I'm open to the commission hearing the hearing. But at this time,
I don't see that it provides us any real benefit other than
not taking all the information that we'll get in the coming months into
account when we consider your plan.
Any other questions on the resiliency plan aspect of this?
(item:7:Chairman Gleeson to Jason Ryan on abatement timeline) So I think in your request for abatement, one of the things you put in
there was you provide an update in October.
I'd submit that October may be too long for an
update. If the abatement moves forward and you don't withdraw, I think
probably need to communicate a little more frequently than that.
Leave that out there as some food for thought. Yes, sir. We appreciate
the feedback. We will work with parties over
the next couple of days and provide an update next week.
I completely agree with the assessments that we need to see amendments
to this plan based on our independent review and based on
y'all's review as well. So message heard on that.
We'll update you next week. Okay, thank you. Commissioners, any general
questions about Beryl?
Thoughts, maybe? (item:7:Commissioner Cobos general thoughts on Hurricane Beryl response) So,
you know, I think it's great that y'all came with a bunch
of information is what you're going to do next. A lot of what I heard
seems like things y'all should have already been doing, right? I mean, you know,
you're the second largest utility in the state, operating in multiple states,
have a lot of experience with hurricanes. These are all things that I think,
you know, some of the things that I heard today are things that the company
should have already been thinking about and doing. You know, as you know,
I went down to Houston and towards some of the aftermath
and it was devastating. Right. And y'all know, y'all were firsthand there.
So, you know, the processes and procedures that
are laid out in the presentation, they're great to hear. But ultimately,
at the end of the day, I think that your performance will be judged by
your actions and the results from those actions. And, you know,
accountability is very important. I think that y'all have all experienced express the desire
to be held accountable and to take the actions and to
start building and regaining trust with your community, with state and local
leaders, the Commission. So I appreciate all of
that. But at the end of the day, actions speak louder than words.
So we need to get through the hurricane season and that's what needs to
happen, and these actions need to be taken. And we hope that
you do. But I think in general Chairman, if you will.
I think, you know, CenterPoint is here before us today. But there
are utilities in hurricane prone areas that
I think should, should be taking some of these lessons that CenterPoint
has laid out today into account as well. You know, and everybody,
you know, all these utilities in this hurricane prone area should be thinking about
what are they doing right now to prepare for the next hurricane and storm?
What process and procedures work to prepare for Beryl?
What can they do that they didn't do to prepare for Beryl to be
better prepared for the next storm and hurricane?
What are you doing to accelerate and adequately fund vegetation
management and what is the status of
that post barrel in your service territories and
ensuring you have the appropriate manpower and funding to get that done?
What are you doing to accelerate distribution, pole replacement?
And if you have transmission lines that were impacted, I know you all didn't.
What are you doing to ensure that the transmission lines
are hardened and able to withstand the next
storm or hurricane? What are you doing to proactively plan for pre
staging and deployment of mutual assistance crews? What measures can be taken
to restore more power, to restore power more quickly?
From a manpower standpoint, if you lease mobile generation units,
what are you doing to optimize the use of those existing mobile generation units?
They're units that the Commission authorized
and the utilities are earning a rate of return. So
I mean, we approved at least CenterPoint's based on the notion that CenterPoint
is in hurricane prone area, and these units would help with restoration of
power. And so we
need for the utilities that own the mobile generation units to develop a plan to
optimize the use of the units and take lessons learned.
If they're too big, get smaller ones. I mean,
make sure you have the right sizes to address your critical care facilities and other
customers that are critical, including water utilities and districts.
What are you doing to ensure that your outage trackers are working 24/7
CenterPoint's gone to a cloud based system. I think that's
great. You know, you need redundancy. You need the ability to stay still,
continue to have access to that outage tracker if the Internet goes down. I know
during the storm, Xfinity and Spectrum went down.
So what can you do to ensure that your outage tracker continues to work?
What are you doing to ensure you communicate with your customers and the
public prior to, during and after the storm? Because as you
noted, only 42% of your customers are signed
up to be on your power alert service. So what are you
doing to get the word out? And you. Not every customer has the
ability to sign up for the power service. And so how
do you communicate to them? The daily press calls.
The daily calls. Information to push out in multiple language,
I think is really important. English, Spanish, and whatever other predominant languages
in your service territory. And what
are you doing to increase your emergency response? And so
CenterPoint laid out steps that they're taking and implementing through a
plan. I think that's important for all utilities in hurricane prone
areas. What are you doing to ensure you communicate with water utilities and districts
during a power outage? And, you know,
ensuring that you understand what their needs are. If they
have backup power, they don't have backup power, etcetera.
If you're a utility in ERCOT like CenterPoint, what are you doing to ensure
you communicate with your reps in your service territory to get customer information?
And duly noted on the suggested change on the rule language, that's something for
us to take into consideration as you don't have a direct relationship with
customers. In the meantime, what can you do to coordinate
with reps to get that customer information? And so all of these,
all of these measures that I've laid out today
are not just important for CenterPoint, they're important for all of the electric utilities that
serve customers in hurricane prone areas. And maybe
there's an opportunity as CenterPoint moves forward with lessons learned and
implementing best practices and procedures for these utilities
to engage in sort of a collaborative group to learn from each other
and prepare. I mean, if you did well during this
hurricane, that doesn't mean you'll do well the next hurricane. And so what
can you learn from each other? To be better prepared in the future is going
to be critically important as we move forward to get through this hurricane season
and for the future. So that's my general
comments. Thank you.
(item:7:Commissioner Jackson's thoughts on Hurricane Beryl response and infrastructure) I'd just like to speak to the process, and I guess from my background and
management of risk, I kind of see it as
kind of twofold. One is, you know,
shoring up that infrastructure, hardening so
that in the event of an incident, the infrastructure
is strong so that it could sustain the event.
So that's one aspect of management of risk.
The other is that, you know, we don't know what's going to
come at us, whether it's a tornado or a hurricane or some
other type of event, but we also need to be prepared
to respond and recover quickly.
And so oftentimes after an event,
one of the things that an entity will take responsibility for
themselves. And I noticed that you are doing an independent
review. And although there's not a scope provided of
the folks who are actually going to do the review, it talks about some of
the work that they did in other areas and that they
focused on evaluating the root causes
of the outage, response delays,
and really kind of did that at
the front end of the investigation. And so I
guess my expectation would be that you would take ownership
of that, recognizing that, yes, it's important that we get input from
customers, that we meet their expectation, that we meet public expectation,
but also expect that there be, there would be an expectation
from the utility that
you would want to define and understand the
root causes, whether they are a need
to better harden your infrastructure from a physical standpoint or if
there are things that can be done in order to better,
to be able to better respond quickly. And oftentimes
at kind of the front end of that root cause analysis is
looking at the system and asking that question, you know, how well
am I able to feel like I have a good map,
a good identification of the system? How well are
my it systems able to communicate with themselves
so that we can go out, gather information quickly,
analyze it and triage it,
either. And that benefits you, whether it's on an ongoing
basis or whether it's something that you're doing in response
to an incident like this. And so I guess I
did have a direct question, and that is, do you expect
to do a root cause analysis as part of this independent
review? Yes, ma'am. And then I
guess as a follow up to that,
in terms of the things that you've kind of laid out. And I know that
this is kind of just at the beginning stages, and you're totally focusing on,
you know, the outcome of barrel. But the expectation, I would think,
would be that this would be for the system as a whole, you know,
that going forward as an outcome of this root cause
analysis, it wouldn't just be the part of the distribution system that
is pointed towards Beryl. You would be looking at everything. You would be doing a
very comprehensive review in
kind of like the area of communications.
I know that passive communications is good.
You want to be able to go in and you want to be able to
look at the outage tracker. But I think what we've seen in some other
areas is that you kind of need that one two punch.
You need something that's not just passive, but it's also active that
provides information to the customers. And you
kind of mentioned one of the challenges that you have in terms of getting
directly the information of your customers. And I
think that's something that would very much needs
to be addressed and needs to be resolved. But there's
also additional communication that's ongoing with emergency
management. And so I would suggest
and ask you as kind of a leadership role if
you might be willing to work with emergency management in some
sort of overall comprehensive ring down
emergency alerting system that could be used not
just for power outages, but for other things that might impact
a community. And I think there are other parts of Texas where that has been
done successfully that you could take a look at,
particularly the Southeast Texas Alerting Network.
Which has been in place, you know, for probably, you know,
for over ten years,
having multiple ways of being able to get out information, not only
going directly to your side and looking at the outage tracker,
but also being able to work directly with emergency
management. Because at the end of the day, they are the ones that are
obligated to tell the public what they need to do to be protective of
their own safety. So I think that partnership would be valid.
I would just kind of end with, you know, something that was
put in place and a report that was done after
Hurricane Harvey, and it was done by the Texas
section of the American Society of Civil Engineers, the eye of the
Storm report, and I was always so proud of our Texas section because,
as you know, ASCE does this infrastructure report card.
And yes, they do go out and they grade how well the
infrastructure is in a given state and particularly in Texas.
But they have taken, you know, many measures moving forward to improve
the grade. And I think that's what we expect here is we expect an
improvement in the grade. And one of the quotes
that was in this report, in the eye of the storm
report after Harvey came from Governor Abbott and
he said, we need to future proof Texas. We don't know what's coming at
us, but we need to be for whatever it is. And I think that's my
expectation here, is this needs to be a part of future proofing our
state moving forward. It's not just about barrel. It's about all the things
that impact us. Putting in a very robust system
by which we can not only strengthen and harden the
physical assets, but we can also be prepared from a response standpoint
to be able to utilize technology, utilize partnerships, to be
able to quickly. So it really doesn't
matter what the event is. Texas is prepared and we future
proof start. So thank you for the work that you've done so far,
and I look forward to seeing your updates, and I look forward to seeing the
progress that we're going to be making. (item:7:Jason Wells' response to the Commissioners on CenterPoint incorporating their recommendations) Thank you, Commissioner. We couldn't agree more.
You know, we manage a system that faces numerous natural
hazards, and we have to mitigate and harden our system to
all of those risks, as well as be much better at responding to emergencies
when they occur and communicating throughout. We will conduct a thorough root cause
analysis across the full spectrum of our responsibility,
and we'll incorporate those recommendations. Thank you,
Commissioners. (item:7:Commissioner Hjaltman to Jason Wells concerning CenterPoint's new system and critical infrastructure) Looking at
Tab 20, and it looks like your incident kind of Command
Flow Chart. Is this what the new system
will be looking like? Is that correct? No, Commissioner.
this, this was a system that we implemented last year.
You know, one of the things that I recognized when we stepped in,
when I stepped in the role last year as COO is that we hadn't fully
implemented the National Incident management system incident command structure across
the company. That was an improvement we put in place in 2023.
There is still a lot more work we need to do, which is why we
have initiated and will search for and will hire a
senior executive emergency management professional to continue to accelerate the
adoption of the ICS structure. Okay. And will that include
more point contacts for particular critical
infrastructure or to try to narrow
so, you know, you don't have so many people going different directions? It's going to
one point contact to help eliminate that confusion. Yes,
Commissioner, we know we frustrated our critical facility
partners with chaotic communication
around restoration times, coordination with when they could expect service,
coordination with when, and if we could provide mobile generation
backup, all of that will be immediately streamlined for this hurricane
season, and we will continue to improve on
preparation for future storm seasons.
(item:7:Commissioner Hjaltman to Jason Wells on vegetation) One final question on the vegetation.
Houston is a very different city from most in Texas and has
different rules. Do y'all run into issues with the city
on tree management and then municipalities as well,
and then cities within Houston itself? Is that an issue that needs to
be addressed? I do think it. Thank you for that question,
Commissioner. I do think we do need to look at vegetation management broadly. There's clearly
more we can do. We've proposed more to do here.
We will have more recommendations about what we can do in this process.
But trees, as you know, are personal property of
homeowners, local, state government.
Right. We do not have the ability to trim
trees outside of our right of way. You know, we worked with
one of our largest vegetation management companies.
Their calculation was nearly 60% of
the vegetation they removed were trees or full trees
that had fallen from outside of the right of way. So I do think
the issue of vegetation management is broader and requires
the attention of everybody that will be impacted by
this. (item:7:Chairman Gleeson to Jason Wells on vegetation) Jason, just a quick follow up to that.
But you all do have a program, correct, that if
there are dead trees outside of your right of way that you think could be
hazardous, you go contact that landowner and then work
with them to see if they'll allow you to cut down those trees, correct?
That's correct, Chairman. You know, historically, the utilities
have conducted vegetation management on annual cycles.
I don't think that's reflective of the risk that our system faces. Last year,
we implemented a high hazard tree program and significantly expanded
the scope. It was part of the nearly 30% increase in
vegetation management spend that we initiated last year.
And we are going to use that program and accelerate
it as we reduce this risk going forward. But we have to work with landowners
and get their consent on those trees. Yeah. You know, when I went out
with Jason to, I think we were in Bellaire.
I was actually somewhat shocked to see that there was maybe
18 inches of span between a distribution line
on either side and these 25 foot trees and
hedges everywhere. And so I think that's good to expand that because I think you
have an opportunity here, you know, coming off of an event like this where landowners
will probably be more willing in response to this event to work with you to
take down those trees. Yes, sir. Commissioner Glotfelty?
(item:7:Commissioner Glotfelty to Jason Wells concerning vegetation management) Yeah, I have a bunch of questions here.
I'll follow up on vegetation management. My issue
that I've espoused
on since I became a Commissioner, the first rate case
was SWEPCO, and they got
dinged by me because of the vegetation management practices.
I think the mindset of vegetation
management has to be we use every technology,
we find every crew that we can and that
we don't skimp on this. I know that there's an
issue between capital costs and o and m costs,
and it always impacts vegetation management.
But I'd like you all to become a leader in
this. You all do have a very compact
territory and you can lead.
So I hope you all take technologies, I hope you become
a leader in this and show the rest of the country the best
practices on this. There are a lot of them there, and you all can implement
them. And then tell us that because you can not only lead
for your service territory, you can be the leader and show every other utility and
every other co op and every other muni in this state how
best to be, how to be the best vegetation management company
in the state. And with that comes a challenge,
which is vegetation management crews are not easy to
get. I understand that. So I would
ask that you all look at is it economic to bring some more in house
and have them be part of your system, of your team so
that you're not just hiring out crews? And I would say the
same with linemena. If you look around,
if you drive around Houston, as I know you all do, I do.
I see more contractor trucks than I see Centerpoint
trucks. And I know historically there has been a long term
reason for that, and that is to share costs between utilities when
these crews are not being used on your system.
So in other words, another company can pick up some of those costs.
It's my belief that many of your contractors have
their employees on your system 365 days a year.
And that ought to be an area where you all look at bringing those in
house so you have control over them and
we have oversight over them. Otherwise, it's just another contract.
That's the way I see it. So I know you all have big contractors there,
but I think you should look to bring some of those in house if it's
economic to do so, you all should bring them in house so they're directly under
your control. Thank you, Commissioner. We hear
the charge and intend to rise to the occasion with
respect to vegetation management. It offers no relief to our customers who
experience the anger and frustration with Hurricane Beryl,
we recognize the need to move move from annual cycles to more targeted
technology based tree trimming.
We had implemented a predictive modeling system using
the latest technology with lidar weather
stations at a granular level that track ground
saturation, rainfall levels,
canopy growth to target trees of highest risk.
Unfortunately, that system is available after hurricane
Beryl passed through, but that system will be utilized
to inform the vegetation that we've outlined in our commitments today,
as well as our vegetation moving forward. And we continue to intend
to learn from others with respect to
bringing vegetation and line crews in house.
We are actively working that process a little over three
years ago when I joined the company. We recognize the need to significantly
increase our level of investment in our Houston electric system.
We nearly doubled our capital investment overnight.
The only way that we could conduct that work efficiently at that time
was to utilize the support of outside contractors.
As we look forward and see the need for
continued investment well into the future, it is time
to look at bringing more of those resources in house. And so we will come
back to you with a specific recommendation on that front.
Thank you. Thank you for the commitment on vegetation management
as well. I know there are new technologies out there that you all
are using. It's also important to be the
best user of the best technology. So I believe that you
all have that commitment.
(item:7:Commissioner Glotfelty to Jason Wells concerning smart meters) You all have, you all
spent a few hundred million dollars a couple years ago, a decade ago,
on smart meters. Were they any value in this
hurricane? I mean, I continue to hear that people say the outage
tracker was out. I had no clue when it was coming back on.
Wasn't the plan for smart meters many
years ago that you could help track outages and help provide information
to customers? And was that a total failure?
Commissioner, the smart meters were useful in our restoration efforts.
However, they were not useful to our customers, and for that, I apologize.
As Tony outlined, we experienced
significant demand on our outage tracker during
the de Racho restoration response,
demand that our own internal servers couldn't handle.
We committed to bringing cloud based outage tracker
online by August 1, which has historically been the
start of hurricane season. And that two month implementation
is faster than what has happened in the industry previously.
That's why we can make the commitment sitting in front of all of you today
that we will have an outage tracker on August 1. When we do have
that outage tracker, the meters will provide benefit.
In the interim. We knew our customers needed some form of information
as we were building this new outage tracker, and we used maps that
were more tied to the circuit level. That created frustration
at the address or meter level.
And that was a reflection of this period of
time between when we had to take down our old outage tracker before we
can bring our new outage tracker up. As I said, at this start of August.
(item:7:Commissioner Glotfelty to Jason Wells on outage trackers) Yeah, I think we saw a lot of online folks say,
your outage tractor says, tracker says, my house is
online and I'm not. And the nesting problem there,
as you all call it, I hope that gets fixed in this
outage tracker. The other thing is, so in
this new world of technology, I can't
help but think about things like ways,
ways for traffic and accidents. Everybody that's a
crowdsourced tool that everybody can input information
in. And if there's a technology like that that can
help you all figure out, you all have to do the assessments before you
can send crews out. But if you could crowdsource that and
get the customers who have
the meters to help you do that, it might speed up the process.
I'm thinking differently here. I don't know if that works or not.
But the fact is, you know, for you all to walk 8000
miles of distribution lines is hard and
it delays some of the restoration.
Not all of it, but some of it. And if there was a better way
to use the community in that process, it might be kind
of a leading edge technology that you can show the world.
Yes, Commissioner. We hear the charge and fully agree.
We've begun to use aerial resources, whether they
are helicopter or drone. We are,
as we think forward to our customer platforms, looking at
ways for customers to report and send photos of damage
so that we can prioritize lines down and other
safety related items that come up in, in a restoration
response. And so we will be opening the aperture as wide
as possible to bring the latest technology to bear to accelerate restorations
moving forward. Great. Thank you. (item:7:Commissioner Glotfelty to Jason Wells concerning mutual assistance and prestaging of crews) I wanted to
shift topics here a little bit to mutual
assistance and pre staging of crews.
I think there's, you know, I've said this
to y'all individually, that there are a lot of things that
went wrong here and a lot of things that you all need to fix.
I don't think that you all were 100% wrong. I think there are some things
that were done to industry standard and that would
be challenges for every utility in every community in a
situation like this, the pre staging of
crews and mutual assistance. So it's my understanding that
mutual assistance is you
have to call a regional mutual assistance group,
which everyone's a member of, and request crews and
they make a determination as to whether the storm
is actually going to happen in your territory and that they release them off
their system. So if that's
correct, there are there a lot of variables that are not in your control when
you try to recover crews for mutual assistance?
Commissioner, there is competition for resources, but one of the great hallmarks
of this industry is the cooperation.
You know, as Randy had mentioned, we were coordinating
with our Texas Gulf coast peers pre staging
nearly 15,000 mutual assistance crews along the Gulf coast.
There is variability to a path of a storm. It is
important to pre stage crews out of harmony, harm's way so they're not negatively
impacted. And that coordination
continues all the way up until landfall, which is why we can redirect
to where they're most needed very efficiently. Now, that's not to say
that there's room for improvement and that will be a focus of
ours, but the coordination is widespread so that
the industry can respond to where it's needed most.
But isn't it right that you have to request those crews and they
have to be released from the utility that they're working on in
order to help you respond? That is a correct
statement, but I will say at the same time,
not only are we in coordination with the regional mutual
assistance providers, I was in close coordination with the national EEI
mutual assistance team as well. And there
is a procedure to releasing those crews,
but there is also means in which we can
request and get additional crews
to help with the restoration process.
Randy, did you want to add something? (item:7:Randy Pryor's response to Commissioner Glotfelty's question requesting of resources & prestaging of crews) Well, I was just going to
confirm exactly what Jason just conveyed.
The requesting utility, in this case us
CenterPoint, did make our request for the resource and then
the providing. Utilities do have to make decisions
based on potential weather threats that they're seeing either currently or
forecasted to see in the next few days. Right.
To be able to provide that availability and then there's a matching
that's provided there. And then, of course, outside of our rmags,
we do have other agreements with utility providers to secure resources that
we did do as well in advance of this event.
And am I right to say that there is competition for crews when you have
a storm such as this? Yeah, I would say early on in the pre
staging. Right. I mean, because everybody's kind of anticipating,
you know, what the impacts are going to be and of course,
you know, everybody's predictive models are, you know,
have variables. Right. So in the likelihood of any major events,
you know, those, those impacted utilities, and you just can't
think of the immediate Gulf coast because these storms do have pass,
you know, through Texas, through the midwest, et cetera.
So, you know, that's what folks have to consider when they're considering.
While there may be devastation along the Gulf Coast, Midwest utilities two
and three days later are also dealing with tornadic activities from the
same storm event. So those considerations are made.
But, you know, getting back to initially, yes, I would
say typically the resources are there,
but after the event is
where we really aggregate based on the impacts, the customers
impacted and the number of events and then be able to work through
those resources to be able to allocate to where the most specific needs are.
And is it true that if you have a crew that drives in from,
so as I understand, mutual assistance, what you want to do is you get,
you want to get the closest crews to come help you first. And then,
so you say 100 miles, you get whatever and then 200 miles and then 500
miles in 1000 miles. If you get crew, if it's a big enough storm and
you get crews from 1000 miles and they're driving 12 hours to
get to Houston, Texas,
they cannot drive into Houston. Come to your staging yard,
pick up a ticket and just go out on your system. Is that correct?
There are rules that require required rest periods if
that's what you're referencing. So if crews are driving, let's say 1000
miles, typically that's a two day drive, right? On average it's
about 500 miles a day. These are large trucks compared
to smaller vehicles. So on average, the utility
looks at about 500 miles per day.
So 1000 miles out, meaning they arrive two days depending
on that time of day that they arrive. Right. I mean, if they arrive
in at later in the day after 608:00
they are required to have, you know, a rest period to be able to start
the next day. So in that case, we will utilize our onboarding
and we have brief training, safety orientation
for those crews to be able to utilize that. And then they require
their respiratory. And are those rules, OSHA rules? Is that governed by
the, there are OSHA rules applied to that. So the
complaint that I've heard is that, you know, we saw a bunch of trucks sitting
there. We couldn't put them out on the system right away. Some of
that may be because assessments weren't done yet.
Some of it may be because of OSHA rules. I mean, there's more
than just a,
they're sitting there because, because you don't have anything for them to do.
(item:7:Jason Wells' response to Commissioner Glotfelty's question on restoration and crews response times) Commissioner, they come to help with restoration. I mean,
this is what they do. This is what they live to do. And there
are a variety of reasons why trucks can be parked.
A specific job site may still require incremental
vegetation work before it's made safe to begin the construction.
There are incidences where maybe the construction
is more profound than what was originally
assessed and they waiting on materials.
But these crews get to work as quickly
and as safely as we can to deploy them on our system.
They work tirelessly to bring service back
online for our customers, and they were working hard immediately
in this storm, which is why I, we were able to restore more than a
million customers within the first 24 or 48 hours.
Just have a couple more.
When you do your storm
drills, do you have third party evaluators there that give
you real third party evaluations as
to how you're doing and what you think? The room for improvement? Or do
you all just pat each other on the back and say,
we did good this time? (item:7:Jason Wells' response to Commissioner Glotfelty's question on 3rd party assessments) No, sir. We don't currently utilize
third parties to assess. We have hired emergency
management experts to come in and offer best practices,
help shape the drills,
provide feedback, but it's not as formal as
a third party assessment, and that is something we're considering moving forward.
I was appreciate, I appreciate the team members that
you brought on board, former FEMA people Manny Miranda
from Florida Power and light. I think they provide a very,
very valuable view that can be hopefully incorporated
quickly to the benefit of the consumers and the company
so that these things are dealt
with a little bit better in the future. Yes,
sir. (item:7:Commissioner Glotfelty to Tony Gardner on communication) I think I have one
last thing, and that is communications
was poor. I don't know how else to put it, but I
think you all know that. I think you all have committed to changing it.
The fact that you all don't have contact with
all of the customers, I think, is you
all have equipment on their premises,
so they are your customers. And if you don't have the information
to your customers, then that's your fault. And I know you want
to change that. And I know as we've restructured this
industry, most of the contact has gone to the retail electricity
provider. You all are still the bread and butter of
Houston, Texas, distributing electricity. So I
hope you all find the way to become
critical to your customers. So as a chief customer officer
and you only know 40% of your customers, that's a challenging
role to fill. You know the way we've structured the industry.
Yeah. Absolutely, Commissioner. We make sure
that we continue to reach out to our customers, trying to get some more contact
information. We're constantly making sure that we encourage our customers to
sign up for power services. But we're at the mercy of the market.
Right. And that's why I'm asking you guys today to help us
change policy so that we can reach out and get more information
from our retail electric providers. As you all may very well know,
we do reach out to them constantly and ask for permission to get
customer contact information, but we may need a little bit more
of a push from a policy perspective so that we can contain more of that
information. And we'll only use it during emergency procedures.
Right. We won't market things to customers. We won't do anything inappropriate. We just
want to make sure that we can communicate with our customers and share with them
the right level of information so that they can take action and respond and
make sure they can do things to secure their families during strong level events.
Thank you.
(item:7:Commissioner Glotfelty to Jason Wells on CenterPoint's system terms of wind speed) I think the one other thing is, I won't get into this, but understanding
what you design your system to in terms of wind speed,
things like that, I'd love to hear in the future if it's
150 miles an hour wind speed, if it's 120 miles an hour,
and what the difference is, what's the difference in cost, what's the difference in value
to the consumers? And so I think, as Jason,
you have said, the canopy grows, we've got a lot of trees. The storm
was obviously, we were on the dirty side of the storm. This hasn't happened before.
But understanding that our weather
is changing, we have to be more diligent
in that. And I encourage you to reach out to me and
let me know what you're, how you all are dealing with that piece.
Commissioner, we proactively took the steps in
2022 to move to constructing at
the national standard for high wind and extreme ice
loading. So new construction does meet those
new standards moving forward. We can provide the detail around that. And the
plans that we've put in place with respect to the resiliency investments
are addressing the historical investments
we have made in our system prior to making that proactive change.
(item:7:Commissioner Glotfelty gives his concerns to all providers in hurricane prone zones) I guess I'll close with, I know this storm hurt.
It hurt a lot of people. I think we had, you know,
folks died as a result,
just like in Winter Storm Uri. I think that's,
it's horrible that it happened. I think this is
not just a wake up call to Centerpoint. This is a wake up call to
Entergy. This is a wake up call to TNMP. This is a wake up
call to TXU. This is a wake up call to every utility
around our state that they have to take serious.
The storms that are facing their system, the challenges that are facing their
systems, whether it be a wildfire that's going to let their customers go out,
or a big storm, or a de Racho, I don't care what it is,
you all know your system the best, but you all have to
do better. The customers deserve better, and we all are giving
you a return that expects better.
I know you all can do it, I really do, and I hope you all
will lead in that regard. You have my commitment. Thank you.
(item:7:Commissioner Cobos to Jason Wells on CenterPoint's presentation) I have a couple of specific questions that I want to ask.
So, in your presentation on page 15,
under the phase two near term actions,
you lay out that you're going to target the
first 350 of 2000 incremental distribution
line miles with higher risk vegetation.
And on the next page you break out,
or you state that vegetation management or vegetation is a major driver of long duration
outages during barrel approximately 2000, or, I'm sorry,
1900 total distribution circuits. So is
the 20 1900 total distribution circuits that you've identified,
those are the higher vegetation, vegetation risk
circuits? Those are our total circuits on our system.
What we're targeting is the 2000 miles on
those circuits that present the highest or highest risk,
which we've tried to demonstrate
here on slide 16. This is the new technology I referenced earlier
with the LIDAR scan that looks at the density of
vegetation in and around our lines.
The darker green is the heavier density,
and also overlay. As I said, there's multiple variables that lead
to tree failure, and you can see that the three month cumulative
rainfall in some cases was 400% of historical totals.
You could see kind of the concentration of that,
the darker blue over the, and if you sort of marry it
up with the vegetation that is the most dense,
those are the trees that are most susceptible to failure in
the wind. And we saw that as we back tested the results
of Hurricane Beryl. The largest intensity of outages were in
that area. We're using that, those analytics
to address the highest risk
vegetation on those 2000 miles before the end of the year.
Okay. Okay, so the 350 is a portion
of that highest risk? That's correct. What we can accomplish by August 31.
Okay, and then the
remainder will be by December 31.
That's right. Okay.
I'm wondering if you could add a little bit more than 350
years, that just the maximum amount you all determined right now through
your capabilities, by the end of August, I want
to exceed expectations. Our intention is to do more.
This is also a time though where we have to respond to storms
in the interim. And so we're balancing what we think is
a very aggressive target with one that we can achieve.
Okay. (item:7:Commissioner Cobos to Jason Wells on mobile generation units) So with respect to acquiring more
mobile generation units in the past, prior to you assuming your
role as CEO, I visited with your prior CEO and he
stated that it's sometimes difficult to get mobile DG
units because you're in competition with other various
stakeholders like the oil and gas industry, other utilities
that are in hurricane prone areas. Do you believe that
you'll be able to get the increased smaller mobile
gen units that you're recommending or
proposing to do? I mean, is this in the works right now?
Is there really that competition out there through, you know,
mobile DG acquisition still? Yes,
Commissioner, I do think we can continue and we're committed to increasing
the size of our small mobile gen facility for restorations.
I think our previous CEO was referring to competition for
the larger mobile gen units that are often are really dedicated
to load shed type events. You know, in this storm,
we utilized 18 of our own, the full fleet of
the small mobile generation units that we have. We were able to
secure another twelve from our neighboring utilities and
we think we can and are committed to securing more for future restorations.
Okay, back to the critical care customers
and at risk customers. That's an area that just
resonates with me. And I know in your proposed next
steps for communications, I really do hope that they are involved
in the critical care customers. At risk customers
like nursing homes, hospitals, assisted living,
all of those type of facilities that have the
critical care and at risk customers are involved in the communication efforts going
forward. It's just critically important that we restore
these types of customers in an accelerated, prioritized manner and
maintain communication with them during storms,
prior to, during and after storms. And I know you all
have made that commitment, but I just want to stress that one more time
and, you know, whether it's through your communication channels
or preparation through mobile DG, whatever it is that you
can do to make sure these types of customers don't lose power or quickly
restore the power. Commissioner,
you have my commitment. Our performance was not where
it needs to be and we will get better. We have 8600
critical facility customers on our system. We started working
with them on
July 7 before the storm. That's insufficient.
We need to be working with them year round on preparation and coordination.
And you have my commitment that we will do that moving forward.
Yeah, coordinated may be with the city as well. Like if there's something that
they can do to help, you know, if they are without power, maybe getting water,
oxygen, whatever it is, that they need there to sustain the
short duration power outage.
(item:7:Commissioner Glotfelty's thoughts on mobile generation units) Can I just, I hope we can have that discussion about mobile
general a little bit more in the future. I don't want to use this form
for that, but for you all
to own the responsibility to provide mobile and for every
critical customer in the region I think is not
perhaps what was intended with the mobile generation language.
And I hope that's not what you're striving to be the best,
the savior to everybody there.
You all know that I have a difference of agreement on how mobile general
happens and why I think that it should be to the folks
that do generation and not the t and D folks. But I hope we can
have a deeper discussion about that and how it's used and why
it's used and how
it's, obviously, it's paid for in rates, but I would really like to
dig into that a little bit more. (item:7:Chairman Gleeson to Jason Wells concerning mobile gen and CenterPoint's moratorium) Yeah, I think we have to.
We allowed them to rate base hundreds of millions of dollars in mobile general.
So I think it's incumbent on us to dig deep into and how it's performing
in the storm. Jason, just a couple
things really quickly. So I think you put out publicly a DNP
moratorium until the 29th, until Monday. Yes, sir.
Can you talk through how you came up with that date and if you've had
any consideration about potentially extending that moratorium?
Yes, sir. We originally came up with that date assuming
that the full recovery of Hurricane barrel would
be completed. Restoration has occurred, but our communities and
customers are still recovering, and so we intend
to extend that moratorium through the end
of next week. I think that's advisable.
(item:7:Chairman Gleeson to Jason Wells on transmission concerns) So, you know, during the direct show, you had some transmission issues
during this storm. Some transmission issues. Do you know the issue?
The facility, facilities that had issues during the directo,
are those the same facilities that you saw go down during barrel?
Chairman, thanks for the question. And no, there were no structural issues
with respect to the facilities that were
impacted by Beryl and de Racho. When we put
up temporary transmission poles, as we had to after de
Racho, temporary is a bit of a misnomer.
Those structures are built to a high wind standard
and worked without issue in
Hurricane Beryl. We did have one circuit lockout
in both Hurricane Beryl and in the derecho.
The lockout in that case was, in both instances,
a tree coming in contact with our line that was outside of our right of
way. But as soon as we cleared that, that vegetation,
we were able to re energize the line.
(item:7:Chairman Gleeson to Jason Wells concerning CenterPoint having a Town Hall and unacceptable violence) You know, you talked about communication I know last time you all were in front
of us. I advise that at some point in the near future doing
a town hall to communicate directly with your customers. I still hope that's under
consideration and you plan to do that. And I'm glad you talked about
the reps, you know, in the aftermath of the storm. I talked to a
number of reps in the association. I mean, they're there to help.
You know, they have their own call centers that if you provide them material,
you know, they can help and calls can be directed to them.
They have those customer relationships. So I'm glad to hear that you're
going to try to work with them, because I know in the middle of the
storm, in the middle of the crisis, is not the time to be trying
to figure out the systems for dealing with crisis communication.
The time for that's, you know, between the storms, because we know another one's coming.
So I'd say, you know, work on those systems. They're there to
help. And I'd like an update on that piece. Yes, sir. For my office.
definitely. Violence,
you know, we saw, we read a lot of stories
about line, you know, line workers being attacked. Can you.
I don't know that I have a full picture of that. I know at one
point, I think in the presentation, you said you'd actually take down
one of your staging sites because of violence. I know another one was,
I think, moved farther out, which caused some delays. Can you talk through just
what the lineworker's experience was during this?
Thank you, Chairman. You know, the vast majority of our customers
that came in contact with our linemen offered
grace and patience and appreciation.
Unfortunately, there were numerous instances of
threats and acts of violence against our line workers.
As Randy mentioned, we had to demobilize the staging site
because of the very credible threat of drive by shootings.
We had multiple instances of guns being pulled and put
in the chest of our line workers.
We had very active threats around the community, sometimes throwing
rocks. I want to acknowledge the
work of law enforcement. They did an incredible job
of keeping our lineworker safe. But I think what's
important here is not only is that behavior not tolerable
in society, it's counterproductive to the restoration,
but it jeopardizes future restorations.
These crews that come to help our communities through mutual assistance
don't have to be here. They come because they want to help.
And I think there's more we can do collectively to keep these
crews safe as they perform this vital work to restore service
to our customers. Absolutely and I think that experience is
something you need to make sure you communicate to your customers as well, that it
is counterproductive to what you all are trying to do in
the restoration effort. (item:7:Chairman Gleeson's thoughts on upcoming hearings) I think that would be really helpful as well. The last thing
I'll say is we have two hearings coming up next week.
We have a legislative session in less than six months that's going to start.
I would look at those as opportunities. We have a few
legislative staffers here from the House and the Senate.
Please bring forth items that need to be addressed in statute.
You know, anything that's there that could have helped during this,
let us know, let the legislature know. Talk about that, because I think you
have a real opportunity here to get some statutory change and regulatory change,
but we need to know what those things are. So I'd urge you to look
at those as opportunities to communicate what those changes might be
and then continue to work with us to get those done.
Absolutely. Thank you, chairman. All right. Any other questions,
comments? Thank you. (item:7:Commissioner Glotfelty's questions on injuries or fatalities) Just one. And that is, did y'all have
any serious accidents on the system, or did everybody make
it home to their families?
Fortunately, we had no significant injuries and fatalities.
We had a handful of illnesses and motor vehicle incidents,
but no significant injuries and fatalities during the entire restoration,
and that should be applauded. Yes, absolutely. Thank you
y'all for being here. Thank you.
All right Commissioners, like I said. I'll bring up next Item 33.
Just a bit of housekeeping, you know, and we
did this last time too. In conversations with our, with our Court Reporters who work really
hard for us. We'll be taking breaks anywhere between, after every
hour and a half to 2 hours. To make sure that they have time to
recover from this. So my plan is to probably
try to go, if we can get through a couple items in the next 15
minutes or so, and then take a 10 or 15 minute break.
(item:33:Chairman Gleeson lays out Project No. 56822) So next I'd call up Item 33. That's Docket 56822,
Investigation of Emergency Preparedness and Response by Utilities
in Houston and the surrounding communities. Connie, you filed a memo.
(item:33:PUC Executive Director Connie Corona lays out her memo on Staff's proposed scope & approach to the investigation) I did. Good morning Commissioners. On Monday, I filed
a memo outlining staffs proposed scope and approach to the investigation.
It identifies 7 primary focus areas for investigation.
And notes that one of our objectives will be to develop recommendations for
utilities and to share with the Legislature.
We'll also be looking to see what changes we can make to Commission Rules.
And if we identify actions that we can take in the short term
before the December 1 deadline, we will certainly bring
those to you. Our timeline contemplates spending
the month of August, collecting data through requests for information
which we'll issue to electric and water service providers in the Greater
Houston area. We also will invite
other impacted entities like retail electric providers, communications providers
and industry groups. To respond to RFIs and tell us
about the impact of the storm on their services and operations,
on their response and any recommendations to inform the investigation.
Our timeline also contemplates a workshop in October. For
the purpose of collecting best practices from SME,
subject matter experts, regarding the storm preparedness and response.
And finally, I want to announce that Staff is in the process
of developing an online portal. To invite
public comment from residents and businesses in the
Houston area. That will be live in the
next couple of weeks. So that folks can go online,
sort of fill out an online form to share their
experiences and perspectives with staff
for the investigation. (item:33:Chairman Gleeson's thoughts on PUC Executive Director Connie Corona's memo) I think that's all good.
You know, I think we do a pretty good job of communicating with our state
elected officials, obviously the Houston delegation in this case.
I also urge you all our Governmental Relations Staff, you know,
we received a letter from Mayor Whitmire. To reach out to local
elected officials as well to make sure we get their input. You know, they're the
closest on the ground to those constituents. And so I think it's important that we
hear from them as well. We will certainly do that. Thank you.
Commissioners? (item:33:Commissioner Cobos' thoughts on PUC Executive Director Connie Corona's memo) Yeah, I'm in agreement with the Chairman. Pursuant to
Mayor Whitmeyer's letter, I think it's important that you send RFIs
to the cities and the critical care facility operators.
Will do. Thank you.
Questions or comments?
Okay. Thank you, Connie. You know, continue to keep us apprised of
how it's going. Thank you. All right,
Shelah. That brings us to our contested case dockets.
So Item 1 was consented.
So that will bring us to Item 2. If you'll lay out Item 2,
please? Yes, Chairman. (item:2:Application of SouthwesternPublic Service Company to amend its CCN to construct generation facilities in Lamb County, TX and Lea County, NM) Item 2 is Docket
No. 55255. This is the application
of Southwestern Public Service Company to amend its certificate of
convenience and necessity to construct generation facilities in Lamb
County, Texas and Lea County, New Mexico. Before you
is a proposal for decision from SOAH. All the parties filed
exceptions and the SOAH ALJ filed a response.
That recommended adding one ordering paragraph to the PFD. The Commission
heard oral argument in this proceeding at the July 11 meeting and
Chairman Gleeson filed a memo in this docket. (item:2:Chairman Gleeson lays out his memo) So as I noted
in my memo, you know, this is a hard case. I agreed with the
ALJ in a number of places. There are a few where I didn't.
You know, I disagree with the ALJ's conclusion that
SPS adequately considered alternatives to
the solar facility. I honestly do. And that the process was
necessarily fair and reasonable.
I agreed with the conditions that the ALJ
put forth. As I said in my memo, I'd recommend,
if we're going to go with the third party consultant review. That we
ask the parties for more detailed language to include in that order concerning
favored nation clause. I think we need one in here as well. I think
it's important that we get our ratepayers get the same considerations
that you New Mexico customers do. I think,
you know, they've agreed to the NERC weatherization standards.
I think that's appropriate in this case. And the
one that I keep going back and forth on that we heard about was the
cost cap. When I wrote the memo, I was leaning
in favor of a cost cap. Probably vacillated a
time or two since then on it.
I'm happy to hear y'all's thoughts on the memo. And, you know,
particularly on the cost cap. I can go either way on
it. So, you know, where I land will
definitely be informed by what you all think.
Okay. (item:2:Commissioner Cobos' thoughts on Chairman Gleeson's memo) Chairman Gleeson, I'm in general agreement with your
memo. I ultimately, I tend to agree that the
RFP process could have been handled a little bit better with respect
to taking a more broad view
of resources out there in the all source RFP.
I think just on its face, looking at the language in the RFP,
it seemed to really favor renewable resources and
resources that ultimately were constrained by the timeline
that they were under, that the utility was under to be able to
effectively interconnect resources in time to meet a capacity need.
The capacity need was on the radar for a while. These utilities,
the generation units, rather, that the utility was
seeking to retire, have been known for a while. So the
competitive RFP process and spss
identification of a capacity need could
have been done better. But I understand that the
company needs the solar facilities to be able to comply with
the Summer PRM requirements, not only the existing 15%,
but also upcoming Summer PRM requirements from SPP.
So I got to a place where I was comfortable with the three proposed
solar projects. I would agree that the
company hasn't carried the burden proof on the battery facility.
I do believe that battery storage provides
reliability benefits during
critical hours of the day. We've seen that in ERCOT,
but unlike in ERCOT, when a vertically integrated utility comes
before the Commission with the CCN to get
approval for a facility to meet a capacity need,
we have to establish that additional that that facility will
result in probable improvement of additional service and
lowering of cost for consumers. In this case, since it's so small and
expensive, I don't believe that they've established their case
for additional that it will result in the probable improvement of
service and lowering a cost.
So, in your place, with respect
to the review of the PFD,
and agree with the conditions, with the addition of
the most favored nations clause and the
weatherization standards that the company is committed to comply with from
NERC, I think that is appropriate. We can have a
cost cap deliberation in a minute, but I do want to provide some
guidance as a commissioner covering SPP.
Serving on the RSC for SPP over
the course of last year. We've been having many discussions
about increasing SPP or
Summer PRM and the establishment of a Winter PRM and SPP.
In a couple of weeks, I will have to go to an RSC meeting
in St. Louis to vote on whether
the whether SPP should increase their Summer PRM from 15%
to 16% starting in the Summer of '26
and whether they should establish a Winter PRM of
36% starting in the Winter seasons of '26-'27
and '27-'28. And I
think it's really important that the utility starts planning
now, immediately in their next RFP, to start complying
with these PRMs. Because I will say that whether Texas opposes those PRMs
or nothing, they're very likely to be approved by the
SPP RSC. And right after that, the SPP is already starting
to discuss going from to 17%
Summer PRM and about a 44% Winter PRM
for the two next Winter seasons. So,
you know, the PRMs are increasing. The demands
of meeting those planning reserve margin requirements
in SPP are increasing. So the LSEs,
the load serving entities, and SPP, like SP's,
will either have to build the capacity or go buy the capacity from
another merchant generator out there that has excess capacity to
sell to them. And that's going to be more and more difficult as many LSEs
start to compete to buy that excess capacity.
So, you know, solar is certainly very helpful to meet
Summer PRMs, and at times it
is helpful in the Winter. But ultimately you need to get accredited
capacity to meet the Winter PRMs.
So more dispatchable generation is going to
be very important. And battery storage is dispatchable. But if you're going
to look at battery storage, it needs to be big enough to actually
help meet those
Winter PRMs, but also cost effective. And given the fact
that the generation fleet is aging and some of it's retiring,
you know, thermal dispatchable generation is definitely
you know, an area that the company needs to prioritize in their next
RFP and upcoming RFPs, because those Winter PRMs are coming. They're coming
fast, and the Winter seasons overall
are just riskier. SPPs taking that in consideration as they look
at their I accredited accreditation
methodologies that they're putting forth for us, we feel assurance at the next
ERCOT meeting. So the company needs to start planning.
Right? They need to start planning. These PRMs are coming in.
And I get it. Y'all are under pressure. You know, you have,
and you're not the only company that has parent companies that want cleaner
energy. There's many companies out there that want that. Right? And so you're under
pressure from your potentially your parent company.
You have other states that you operate in that want. That have
clean energy goals, like New Mexico and large customers out
there. You know, they have corporate sustainability goals and they want to meet them.
And you as a utility, they're your customers. You want to provide them with these
types of resources. And ultimately, you know,
you want to take advantage of federal incentives,
you know, that money that's out there and. But you
can't lose sight of that. We have to focus on maintaining reliability and meeting those
Winter PRMs. And so I really, you know, to put it
simply, I think, as I've said, you know, you need to make sure that you
have enough dispatchable generation to keep the lights on during the Winter and
keep moving forward with that in consideration. As you move forward with
your upcoming RFPs, make sure they're competitive. Make sure that,
you know, there's no perception that they're just intended
to be for renewable generation. But I have faith that
y'all will move forward in looking at those options.
And I just wanted to provide that perspective.
As the SPP RSC member, I know y'all are fully aware
of these upcoming PRMs, but just as a reminder,
it's important not only for SPP maintain reliability there,
but that is the expectation we have in Texas. We got to keep the lights
on in the Winter. Thank you, Commissioner.
(item:2:Commissioner Glotfelty's thoughts on Chairman Gleeson's memo) Yeah, I would appreciate your memo.
I think you laid out all the issues quite well. Kind of
where I've landed on this is approve the solar, deny the batteries.
I'm not supportive of the minimum
production guarantee and the cost cap.
I think. I mean, I want to. I want to be there because
I think the RFP process for utilities is always
flawed. Utilities always pick themselves. So let's not,
you know, fool ourselves. But the place
to solve that issue is in their rate base, in their rate case.
And if they. If we. I just
think that's the decision should be yes or no,
and then hold their feet to the fire when the rate case comes around.
So I think the weatherization guarantee should actually be
the ERCOT standard, not the NERC standard.
I know we don't have much leg to stand on here, but it's
further up north than where our ERCOT standard goes.
And those people are no less important to us as a commission.
So that, and the most favored nation, you know,
guarantee, I think, is important. So all of these issues,
I'm not totally beholden to.
They are bigger than just this one case. They're issues that this Commission
has to discuss at some point in time. So,
you know, wherever that leads us today, I'm happy to
find that common ground. Absolutely. And, you know, in my briefing, I discussed,
you know, an ERCOT standard. Since we do that kind of by region,
I ended up getting to a place where I felt like, I don't know what
standard we would actually apply to, to everything. And so I think
this is a good. Since they've agreed to this, I think this is a good
step. (item:2:Commissioner Jackson's thoughts on Chairman Gleeson's memo) Well, I'm in
agreement with your memo for the most part. I also wanted to hear
what other thoughts and ideas folks had on the cost cap.
I feel like that's kind of a big step. But in this particular and
unique case, because of the background, and I think what,
you know, has been mentioned is, in terms of the planting reserve
margin and how we anticipate that growing over time,
there's likely some
reason to protect the consumer in terms
of the investment. And so the cost cap may
be a good idea. I know a lot of times we want to
reserve a lot of these actions to the right
case. But in this particular situation,
you know, the answer could likely have been, you didn't follow
the process. And the answer is no. I don't think we want that
to be the case because we know that they actually need the
generation, they need it in a given timeframe. And so
solar is, at this point in time, the option
moving forward. But I do think that it's reasonable because
we do want to protect the ratepayer because
of the fact that they didn't necessarily follow
the process, that a cost cap
might be appropriate, and that
would enable them to go ahead and get the solar reserve, the battery
for another determination on down the road and then
protect the consumer with the cost cap.
So Commissioner Glotfelty, if we didn't have a cost
cap, could you get behind the production
guarantee?
So I
guess part of the challenge is I don't know how it works. I don't know
how it takes into consideration forced and unforced outages. I don't
know how it takes into consideration weather. So those are
the challenges that I have. If we have an appropriate accommodation and
a fairness component to that. Yes, I can deal
with that. I don't think, I just feel like we're dealing
with mechanical systems here. Solar is not necessarily mechanical. I understand
that. But mechanical systems fail.
We have to have that recognition. We want them to maintain them. But,
so, yeah, I mean, I can do that. I mean,
(item:2:Chairman Gleeson's thoughts on cost cap) I agree. For me in this case, you know, in the trade off
between risk, between the different parties, I think
I feel like more of the risk has to be on SPS.
And so I'm okay if we don't implement
a cost cap and we deal with, with that in the prudence in the base
rate case, if everyone's okay with everything,
with the rest of the memo, I can support that.
(item:2:Commissioner Cobos' thoughts on 100% production tax credit guarantee) Yeah, and I think that the 100% production tax credit guarantee
is critically important because that's one of the underpinnings for
making the solar projects cost effective because of the fuel savings and the tax
savings. And so
I think that's a critical component of the conditions. And the minimum
production guarantee is also very important
because those can flow through, back through the customers. And I think in the past,
when SPS came in for their big WIM projects
several years ago. There was similar language put in through the
Commission order that approved those projects.
So it's a framework that I think we've had in place before in
the past, and it was put in place to make sure that those
PTC benefits flow back through to
the customers. And,
you know, we want to make sure that they flow through
to all customers because there are some back end issues and I won't get into
them right now, that sometimes
ends up being sort of more of the PTC benefits
flow through to larger customers rather than residential customers.
But I, I want to make sure that we get that framework
in place and I could go either way on the cost cap. I hear you,
Commissioner Jackson. We have a mixed precedent
at the commission on cost caps. And,
you know, SPS in the past has agreed to one in the WIM projects
through settlement agreement. So it's not like a new first
case of impression for SPS. I would
just say that if we do put one in,
that AFUDC has to be included.
So I'm okay without imposing the cost cap if you know, like you say,
we can have the production
guarantee.
Okay, so I
think we have agreement. Sounds like we have agreement. Okay.
(item:2:Motion to deny & modify parts of the PFD consistent with memo and discussion) Then I will entertain a motion to deny in part and modify in
part the PFD consistent with my memo in our discussion,
and delegate to OPDM the authority to issue an
order regarding the third party prudence reviews discussed in my memo.
So moved. I second. Have a motion and second. All those
in favor say aye. Opposed? Motion prevails.
(item:2:Chairman Gleeson recesses open meeting) So Shelah, I think this is probably a good point to take a little recess.
So 10, 15 minutes.
So why don't we come back at 11:30? So we'll
stand in recess till 11:30.
(item:2:Chairman Gleeson reconvenes open meeting) We will reconvene our open meeting at 11:33.
Shelah, I believe that brings us to Item No. 6. Will lay out
Item No. 6, please? Yes, sir. (item:6:Application of Southwestern Electric Power Company to amend its distribution cost recovery factor) Item 6 is Docket No.
56511. The application of Southwestern Electric
Power Company to amend its distribution cost recovery factor.
Before you as a proposal for decision. Let's see.
Cities advocating reasonable deregulation filed exceptions. The ALJ
filed a letter in response to the exception stating that no changes to
the PFD are warranted. And Chairman Gleeson filed a memo.
So simple correction memo. Happy to
hear any thoughts or answer any questions? Good catch.
I'm in agreement. I'm in agreement as well. Okay. (item:6:Motion to approve proposed order consistent with Chairman Gleeson's memo) I would entertain
a motion to approve the proposed order consistent with my memo. So moved.
I second. Motion and a second. All those in favor say aye. Aye.
Opposed? Motion prevails. Okay, so the
next Items up are 9 and 10. I'm recused from those, so I
will turn this over to Commissioner Cobos. Thank you, Chairman Gleeson.
Shelah, will you please lay out Item No. 9? Yes, ma'am. (item:9:Application of Energywell Texas, LLC for a Retail Electric Provider Certificate) Item 9
is Docket No. 5651. The application of
Energywell Texas, LLC for Retail Electric Provider
Certificate. Before you is an appeal of Order No. 2.
Finding the application deficient, establishing deadlines, and an
opportunity to cure and denying request for good cause exception.
And the appeal is before the Commission now.
(item:9:Motion for extension of time to act on appeal) I would move to extend time to act on the appeal.
I agree as well. All right. Do I
have a motion? Do I have second? Second. Okay.
All in favor? Say aye. Aye. Great. Motion passes.
Okay. Item No. 10. Shelah, please lay that one out.
(item:10:Investigation of Berkshire Communities, LLC for violations of PURA and Commission Rules) Item No. 10 is Docket No. 56786. This is the investigation
of Berkshire Communities, LLC for violations of PURA
and Commission rules. Before you is a motion from Commission Staff to
open a formal investigation of Berkshire Communities, LLC.
Commission Staff has opened an informal investigation
for possible violations. Related to the unauthorized
resell of electricity and denial of tenants rights to choose a
retail provider in areas of the state that are subject to
retail customer choice. Commission Staff requests that the
commission issue an order to open a formal investigation. So
that they may determine which affiliated business entity is the proper
respondent in this docket. All right. Thank you,
Shelah. (item:10:Motion to grant Commission Staff's authorization to institute a formal investigation) I would grant Commission Staff's motion to authorize Commission
Staff to institute a formal investigation of Berkshire for possible
violation of PURA and the Commission's rules. And direct OPDM
to develop and order consistent with the Commission's decision to grant the relief
requested in Commission Staff's motion. I'm supportive.
I'm supportive as well. Okay. Same. All right.
Do I have a motion? I so moved. So moved. A second?
I second. All right. All in favor say aye.
Aye. Motion passes, thank you. I will
now hand the gavel back to Chairman Gleeson. Thank you,
Commissioner Cobos. So that concludes the contested
case portion of our agenda. So we'll move into Rules and Projects.
(item:11:Shelah Cisneros confirms no one has signed up to speak on Rules & Projects) Shelah, I think you said no one signed up to speak on any rules or
projects. That's correct. Okay, so based on consents
and where we don't have anything to discuss. (item:18:Chairman Gleeson lays out Project No. 54445) I think that'll take us to
Item No. 18. That is Docket
54445, Review of protocols adopted by the independent organization.
So, you know, we have 13 revisions
in front of us. Twelve of them, I would say. Not a
lot, if anything, to discuss. Then we have NPRR1224.
So I think the way I'd like to do this is if we end up
at a place where we approve 1224,
we can just have one motion for. For all the
approvals. If we end up taking a different action, then we'll
probably need two motions. One to approve the other twelve, and then
another for whatever action we take on 1224. Does that work for everybody?
Didn't quite understand it. We're going to do all of the other ones in one
motion, and then. So I don't want to do anything yet, because if
we end up approving 1224, we can just add that to the existing.
To the existing. To that motion.
So we asked for ERCOT staff,
for the IMM-Dr. Patton's here, and for PUC Staff
to come up and go over their comments.
The way we're going to run this, we'll have ERCOT go first, then Dr. Patton,
then PUC Staff. And then if ERCOT
has anything to close on, we'll allow them time. We've read
everything, so I'd say five minutes is preferable. No more than ten, if that
works for everybody. Okay, so if y'all want to come up.
Woody?
(item:18:ERCOT's Woody Rickerson on ECRS, NPRR1224, $750 floor and working with IMM) Woody Rickerson with ERCOT.
All right, so I want to start with some background information. Try to go quickly
here. ECRS isn't a new idea concept was included
in a future ancillary service paper released back in 2012.
The need for ECRS was recognized over a decade ago and
is anchored in ERCOT. Being a relatively small grid with high penetration
levels of renewables. Prior to June 2023,
ECRS capacity was actually being purchased within
responsive reserve ancillary service. Fundamentally,
ECRS is a reliability tool. When ERCOT
buys ECRS, it's buying a capability, not necessarily a capacity,
although it comes with a capacity. When ERCOT holds ECRS,
it holds a guarantee of ten minute ramping capability.
When we release that ECRS, we're also releasing that guarantee.
The market may or may not have that capability.
The immune analysis shows that over the last twelve
months, ECRS was deployed. The resulting system
was short ten minute ramping 15% of the time.
So keep in mind, that was even with a more conservative
release of ECRS. So 15% of the time, that ten
minute ramping wasn't there. So why is that important?
First of all, ERCOT doesn't have synchronous ties,
interconnections. Other regions like MISO,
New York, New England, all of which are monitored by Potomac Economics
all have those ties. Those areas can lean
on those import capability. ERCOT doesn't have that luxury. ERCOT provides
or ECRS provides much of that function that synchronous
ties provide. Secondly, ERCOT's an island.
It's actually one of the smallest of the three major interconnections. So a
1200 megawatt forced outage has a much bigger impact
on ERCOT frequency than it would have in a larger interconnect.
Therefore, ERCOT has to protect that frequency more so than
other regions. And lastly,
ERCOT has a high penetration level of solar and wind,
so those resource types come with more variability in output.
ERCOT depends heavily on wind and solar forecast.
An example would be just a wind ramp that we expect that
arrives 30 minutes late that can cause significant
operational problems. ECRS is one of
the tools that helps us mitigate that risk of forecast errors.
Those risks don't exist to that same level in
other regions as well. So that's a another risk that's unique
to ERCOT. At a high level.
What the immune system has proposed reduces the
amount of time ERCOT has access to ECRS.
It puts more risk on system operations.
And really, if you think about it, holding any ancillary service product,
holding any ancillary service product out of the market, is withholding.
But when we talk about responsive reserve withholding, responsive reserve withholding
regulation, that's deemed okay because of the high
need for reliability.
ERCOT would put ECRS in that same category.
ECRS is a high need reliability tool,
and the reliability trade off is worth some cost of withholding.
Now, we agree with the IMM that there's room for improvement,
and we think improvement can be made without some significant risk
in reliability. The NPRR1224
40 megawatt threshold for release provides
some of that improvement. And just keep in
mind, too, that the 40 megawatt trigger is actually the
third trigger. It's a new third trigger for
releasing ECRS. Two triggers already exist.
ERCOT will already release ECRS if frequency deviations
are seen, and ERCOT also will release ECRS if
the forecasted ramp deficiencies are known. So if we look into the future and see
your ramp deficiency, we'll release ECRS. And that's a lot
of what IMM wants us to do more of. And I think
in the Summer of 2023, that was not as established as it
is now. So there already have been improvements made to.
To release ECRS, as we see forecasted ramp
problems. So NPRR1224 sets
up that third trigger with a 40 megawatt deficiency after ten minutes.
I think if you were to move that trigger down to something like 5 MW
or no megawatts, it would result in a substantial number of unnecessary
deployments. So, as a system operator,
we don't want our operators deploying manually deploying ECRS
every day or twice a day, and then having to bring it back
in. We want to make sure the ECRS is deployed during material
shortages, not during small ramp periods, which the five
megawatt trigger would force us to deploy more often.
As a grid operator, we just don't want our operators in the situation where we're
doing that repeatedly every day. Concerning the $750 floor,
ERCOT did rely on market participant input and attack processes
for setting that floor. We continue to believe that there
is some risk in demand fluctuations
if a low floor is
coupled with a low trigger. So those two things together
could cause demand fluctuations. As you release ECRS,
demand that has responsive to prices,
comes back on, prices go up, it goes off. You have these fluctuations
that could occur during critical periods of the day. We want
to avoid that. So we do think there is some risk there.
The IMM has argued that releasing ECRS,
and you see this a lot in the comments, in most cases,
doesn't mean ERCOT will lose ECR's capability, or generally
doesn't result. Those comments are.
You find those throughout.
I think in the most recent comments, we see 85% of the time when
ECRS is released. There isn't a problem with retaining
the ten minute ramp, but that means 15% of the time there is,
and we can't operate the system. Looking back at
what happened, we operate the system going forward.
So I didn't need car insurance yesterday because I didn't get in a wreck,
but I had it and I'll carry it going forward as well.
And ECRS is much like that.
We don't know what's going to happen tomorrow. That's why we
carry that ecrs as an insurance policy. If we could
buy ancillary services for what we needed yesterday,
we could run a very efficient market. But that's just not the way the
system works.
Having said all that, I mean, we agree with
the IMM, the deployment could be improved, especially when compared against the performance
from 2023. So, no doubt about it, and we're
willing to work on that. And I think we've already made improvements to improve
that. We've been working with the IMM and
market participants on those improvements for the last six months.
TAC asked ERCOT to review the ECRS quantities in December
2023. So we started that several months
ago. ERCOT determined that the quantities being procured were appropriate
for the risk. Those risks are the things I talked about for isolated grid
with high penetration renewables, no synchronous connections.
During this review, ERCOT met with IMM's staff.
In fact, many of the concepts in 2024 were originally proposed
by the IMM. So,
ultimately, the framework laid out in 1224
represents a balanced improvement over what happened in the past
that can be used as ERCOT gets ready for. For RTC.
So that's what I got. Thank you, Woody. And before
we get into questions. Woody, I would want to recognize and thank
Senator Menendez and Zafarini for sending us a letter relating
to NPRR1224. (item:18:Chairman and Commissioners questions to Woody Rickerson, NPRR1224) So,
when this was initially proposed, there was no offer floor.
Can you talk to me why? Talk me through kind of why not?
Why there was no offer floor originally? So we
left a space, there was an anticipation
there would be an offer floor, but we wanted to get market participant feedback on
what the offer floor would be. So the NPRR
was written so that that offer floor could be filled
in after market participant input.
So just one piece, maybe, of constructive feedback
that wasn't apparent to me, I would say, and honestly, you know,
I'm not going to follow this as closely as everyone who's in every you know,
committee meeting. I thought you all were completely agnostic
to that, to be honest. And is it still fair to say. Fair for
me to say that the part of this revision
that is most important to ERCOT is the
trigger? That's correct. Okay,
Commissioners, questions for Woody? (item:18:Commissioner Cobos' thoughts and question for Woody Rickerson on offer floor & working with IMM) Yeah, and thank you for
emphasizing that. It wasn't clear to me either,
Chairman Gleason. It seems to me like the offer floor
came up discussion because there was some discussion
of potentially lower offer floor that the IMM put out there.
And so the market sort of reacted and came up with a
different offer floor if there was going to
be an offer floor. So, you know, as the
conversation sort of evolved to the board, it became unclear.
Clear where. You know, at least now
we're clear where ERCOT really stood in terms of what's most
important from this entire exercise, because from my perspective,
based on where we left off, when ERCOT got their 2024 ancillary
service methodology approved, ERCOT committed to
work with the IMM and the stakeholders to improve
the deployment of ecrs to better balance, you know,
making sure you still have resources when you need
them for the reliability risks that you laid out, but also
releasing ecrs a little bit earlier,
a little bit more, to mitigate
any potential artificial pricing in the market. And that was the
exercise. Right? That was the exercise that I
believe that the group collectively, ERCOT, IMM, our Staff.
Embarked on to try to rebalance the ECRS deployment,
where you're still getting your reliability tool, but, you know,
consumer costs, pricing concerns are mitigated.
And so the deployment trigger was really where I thought
our focus was. And somewhere along the way, given potential,
probably, back and forth discussions on an offer floor, is how
we ended up with the seven offer floor. And ERCOT seemed
to really,
really advocate for the $750 offer floor. But what I'm hearing from you today
is that the deployment trigger, as you just said, is the most important piece
of this NPRR for ERCOT. That's correct.
Okay.
Commissioners?
Actually, I'll wait for my comments till after Dr. Patton goes and Staff goes.
I might do the same thing.
Dr. Patton, thank you for being here this morning.
You're welcome. It's on. Okay.
(item:18:IMM & Potomac Economics President Dr. David Patton, NPRR1224) Well, I appreciate the invitation to come, and I
apologize in advance for the
difficulty. This is a complex issue, and you're
hearing things from ERCOT. You're hearing things that are diametrically opposed
from me.
It may surprise you to say there are a lot of things that ERCOT
and I agree on in this issue, but at the outset, I think it's important
to acknowledge. Just to put this,
this into context, the market performance that impacted
by the deployment of ECRS in 2023 was calamitous.
I've never seen something as bad as what happened in 2023.
This one issue doubled energy prices.
It would have been hard for me to suggest something that would have
that magnitude of an impact on the market
performance, the competitiveness and the efficiency of prices. And so the
priority has to be to fix this, not just iterate
and improve and make it a little bit better.
And we know how to fix this. And so that's why we
disagree with what's in the NPRR, both elements, the deployment
trigger and the offer floor, because what the NPRR would do
is institutionalize a fairly large share of the dysfunction
that we saw in 2023. And in some respects,
there are conditions under which the NPRR could result in worse
performance of the markets than occurred in 2023. Because in
2023, we didn't have a $750 offer floor.
And that offer floor, under a lot of conditions, could do more to distort prices
than failing to deploy ECRS.
So I want to talk about the things that have really confused people.
I've said multiple times that refusing to deploy
ECRS demonstrably undermines
reliability. We've been evaluating
the operations of the ERCOT market since the early two thousands. In fact,
that's when we first started working with ERCOT and with the PUC,
is the very first big report we did was on operations.
And I think we had 15 recommendations for, for how to improve operations
and reliability of the system. And we do the same sort of evaluation in all
the other markets, because the operating actions,
and this is one of them, the decision to deploy
reserves has a huge impact on the performance of the market and
how cost effectively you're maintaining reliability.
Now, this is a new product, so it's not surprising that people are confused
about whether deploying ECRS is good
for reliability or bad for reliability. The assumption is
when you deploy ECRS, somehow you've lost access to
resources and you've diminished reliability. And so
from an operator perspective, I can understand the
appeal of having a bank of resources sitting there that you can deploy
when. When you really feel like you need it. The problem with
that is that if
you don't deploy ECRS before,
the real time market can no longer do its job, which we
refer to as SCAD sked, has one job,
to send dispatch instructions to the generators that will
meet the demand on the system optimally.
What the trigger in this NPRR does is say, we're going to let
the SCAD run out of resources, and for up to ten
minutes, by at least 40 mw. So we're going to intentionally prevent
SCAD from doing its job if we adopt this trigger.
And when you do that, a couple things happen. One is
you're no longer sending dispatch instructions to generators that are
adequate. And so now you're leaning on regulation to
keep supply and demand imbalance. That's not the purpose of regulation.
Regulation is intended to address situations
where maybe generators are running lower than the instruction you gave them.
Like, it's no. RTO should design their real time market
to run out of resources so that you then have to lean on regulation,
because then you're closer to a frequency event.
The regulation keeps you out of the frequency event by incrementing
up generation when supply and demand are in balance.
So the number one priority should, from a reliability standpoint,
should be not to let sched run out of resources. Now, when sched does
run out of resources, it has the very unappealing side effect that
you get price spikes, because sched thinks the lights are about to go
out. And so that's why in 2023, we repeatedly saw $5,000
prices that were sustained for a very long period of time.
Because to sched, it looks like
the system is going down, but it only looks like that because we're
not giving it additional resources so that it can meet the load.
Now, one of the reasons for the
offer floor is, I think there's a concern that if you release ECRS
resources and allow sched to
meet the load, that obviously prices are going to be much lower
and maybe they'll be too low. But there's
been no analysis by anybody that suggests that prices are going
to be too low if we release ECRS resources.
In fact, we, in our rebuttal comments, did an analysis showing what ORDC
would do in these intervals where we're actually short of reserves and
the prices are efficient. If you're significantly short
of ten minute reserves, price would average dollar 900 and go
all the way up to $5,000. So there's
no evidence that ORDC will not do its job and needs to be supplemented somehow
by an offer floor that would bolster prices. Now, the important
thing with the 85% number that ERCOT
mentioned is that 85% of the time when
we released ECRS, there was no shortage.
And when there is no shortage, there should be no shortage pricing.
So any price effect you get from the $750 offer
floor is a pure distortion, and that's 85% of
the time. Now, 15% of the time there is a shortage. And Woody
just mentioned that the 15% is
because we released ECRS. That's not true. The 15%
is a shortage that existed because of supply and demand.
And whether you release ECRS or don't, you're going to see those shortages. And those
are the periods where we demonstrated that the ORDC sets prices
adequately. So I was encouraged that
the Staff recommendation was not to accept the $750
offer floor because that's the most unambiguously unreasonable
part of the NPRR. But the deployment trigger is very,
very important, and it's important to understand why
adopting a deployment trigger that lets get go short hurts
reliability. And there's two reasons.
When you release ECRS, you're not losing reserves.
And you heard that over and over that we need reserves.
We need to hold these things. We don't want to deploy them because we need
to have them so that we can deploy them. When you deploy them,
you get spinning reserves on the system. There's no way you lose
reserves. You have to ramp when you deploy these resources.
If they turn on some gas turbines, let's say you
ramp down other resources on the system who provide you spinning
reserves. Now, why is that a good thing from a reliability standpoint,
that's a good thing because then when unexpected things happen on the system,
SCAD can immediately start ramping those resources up. Like you
get response right away if you hold them
as ECRS and wait for the operator to press the button.
If it's a gas turbine, you have to wait ten minutes for it to come
on. So it provides less reliability value, which is why the
demand curves for spinning reserves are always higher than
for non spinning. They provide more value to the system. And when you deploy ECRS,
you're creating spinning reserves. So it's a good thing from a reliability standpoint.
But there's two other very important things, and these are nuanced, and I'm
not sure people recognize that this is going on. One thing we
saw when we looked at what units will ramp down
if you deploy ECRS. Most of
those resources are gas turbines that are fast ramping
and batteries. Now, that should scare you that batteries
are the ones ramping down when you deploy ECRS. What that means is
when we don't deploy ECRS and sched gets really tight and
prices go up, we start dispatching our batteries. We don't want
to be dispatching our batteries under those circumstances. If we're not short,
we want to preserve the state of charge of the batteries. So when prices jump
up to 3000 and $4,000 load curtails
that shouldn't be curtailing, which Woody mentioned. Batteries start
running that shouldn't be running. And all of this is being done to
preserve gas turbines that are sitting there that are
much better suited to provide SCAd the flexibility that
it needs. And ultimately, if you keep doing that, if you keep
not deploying the ECRS, you think,
I can see how it appears that the system is more reliable because I'm looking
at resources that. That I can press a button and deploy, but the system is
less reliable if I've diminished my supply by running
batteries out of their state of charge in the meantime.
So that hopefully explains why our
reliability conclusion about this deployment trigger is.
We come to a very different conclusion than ERCOT operators. And it's just that
I think we're looking at the secondary and tertiary effects of
deploying or not deploying, rather than just simply do I have
resources that I can turn to.
So the last thing I would say is,
on this trigger,
you may wonder why it was on the list of potential triggers that
we produced. We never proposed a ten minute delay,
but the trigger that we,
that we preferred was a price based trigger, which,
which would trigger before your short,
a very small shortage, we thought would. Would not have
a big distortion. The problem with that is, once we started doing
simulation, the simulations, the effects of
waiting until sched goes short became clear. It was
much larger than. Than my intuition,
which is why we're now opposed to it. And ERCOT has
a deployment trigger right now that when it forecasts it can't meet the ramp in
sched, it will deploy ECRS in concept. And they said this
in their comments, in concept, that's pretty similar to
the trigger I would like you to impose in this NPRR, which is
if SCAD sees five or ten minutes from now that it's going short to
release the ECRS to avoid the shortage.
But for some reason, that trigger has not worked
like we've even this year. We've already incurred over
half a billion dollars of cost by having sched
go short and remain short for extended periods of time when
ECRS is not being released. And I
can't tell you why that trigger doesn't ensure
that SCED doesn't go short, but it doesn't.
And this new trigger, if you move
it back, basically 15 minutes, so you deploy the ECR
s before you're short, it'd make a huge
difference. And if you don't believe you should be,
if you don't believe you should be deploying ECRS early.
I don't understand how you can think the next
NPRR, which would permanently deploy ECRS, is a good idea,
which ERCOT has supported or has said positive
things about, because that would make ECRS available
when it doesn't even look like sched needs it. So what I'm
proposing is I feel like a much less aggressive
approach than the next NPRR, which would
permanently deploy ECRS. So with
that, I'm going to. I'll wrap up, and I'm happy to take
questions. Thank you, Dr. Patton. Commissioners, questions?
Doctor Patton, are you referring to NPRR1232 as the next NPRR?
Yes. Okay.
I have a question, and it's for Woody and Dr. Patton.
ECRS. What percentage of ECRS now is
batteries going into the system? Woody?
30%. Okay. And how does that play? If you're moving
over, like Dr. Patton's notes show,
and you move it over when it's triggered so that it's
seen, how does that work? Because if you're turning on a battery, aren't you?
The charge is now being used.
Yeah. So this is another confusing part of this equation.
When you deploy ECRS, it doesn't mean anything's going to turn on. It just
makes it visible to SCED, and then SCAD makes the economic
decision, do I want to turn that on or not? And the portion of the
ECRS that's deployed, that's batteries, probably won't turn on because their offer
prices tend to be high. The portion of the ECRS that are gas turbines,
those are the ones that probably will turn on because their
costs are much, much lower than the batteries. So that's
why when I talk about deploying ECRS, I skip
a couple of steps and go straight to, we're going to see some gas turbines
turn on as a result. Okay. Is that
in your agreement, too? Yes. Okay.
I'm totally confused.
I apologize. But as much as I've known
and learned about the system, this coming to us at the
end, I thought I could get my head around
it. I believe 50%
of what Woody says and 50% of what you say,
but I can't reconcile the two.
I believe Woody and agree with Woody on reliability,
that the frequency is an issue, we're not connected to other systems,
that this might be a tool that's needed. Dr. Patton, I don't know
why it matters to anybody about when batteries
discharge. Our market is a market, and it's intended to
discharge when the price is right for that battery and
or that resource. And I sense
what we have done, what we've created over time. You all
please comment on this. It is so damn many
ancillary services that we've created and we
pull from them and we don't stand within strict guidelines of them.
So the market doesn't know we're giving operators flexibility to
this because of reliability challenges like last Summer,
which is not this Summer. In terms of temperature, in terms
of resources, in terms of forced outages.
And we need to use this ancillary service study
to define what these markets are for and why they are being
used. So that's my statement. I have
no clue where I stand on this. I really don't.
Can I answer your question? Yeah. Okay. The batteries
and I, I mean, to be honest,
I'm not surprised that, that this is why I apologize
first thing I said when I got up here, because this, this is, this is
a very difficult issue.
The batteries are, it's important to think
about what did we do before ERCOT and why weren't we seeing outages
and so forth. What happened before ERCOT is these gas turbines
that are being procured as ERCOT were held by market participants
who would self commit them as they saw prices go up. So we
did not see SCAD routinely run out of resources because we relied
on participants acting in their own best interest to make more
supply available when the real time market needs it. But now we're buying so much
of this and sequestering it that that response is
hindered. And so now we're seeing SCAD start to run out of resources. Now,
the reason running the batteries is bad from a reliability standpoint is
if a battery's opportunity costs are $1,000 or $1,500 or
whatever it is, there is a point in time where
it's worthwhile to discharge the battery,
use it up, and then you don't have it anymore because it's really
needed at that point in time. But that's not what's
happening here. What's happening here is prices should be $80.
We shouldn't be running the batteries, but we're printing $1,000
price or 2000 or 3000 solely because we've let sched
run out of resources. So we've created the illusion that this is
a dire circumstance where we should be running the batteries.
But it's a manufactured.
Why is the ORDC flat? Because isn't that
the trigger that's supposed to encourage people to
put more resources into SCED? Yes, it's flat
because by our operating procedure,
we are allowing SCED to run out of resources so
that the SCED price is shooting up,
and it's completely out of sync with how many reserves we had.
See, ORDC can see all of the resources, and it's
going to, the prices in ORDC are going to go up when we
are truly running out of resources. SCED can only see what we let
it see. So SCED can't see the ECRS resources.
It can't see anything that's offline
longer than ten minutes. It doesn't even know it's there.
And so our job should be to allow SCED
to do its job, to give it resources when it needs resources. And then if
we start to run out of resources, the ORDC will let prices rise and
get the market response. That's why I keep calling these
things artificial shortages, because you look at ORDC and
ORDC says everything's fine, and SCED says,
we're about to go into a blackout. Prices are $5,000.
It's just one of those two is right and one is wrong.
So I think, I agree with a lot of what's going on here.
There are things that happen on the system where you need ECRS.
You need to be able to have it in your pocket as an insurance policy
to deploy it. It's happened twice in the last two weeks.
So we had fire at a large plant,
caused some problems, deployed ECRS.
We also had a failover problem with the software where
base points were having problems, and we deployed ECRS.
And so the basic high level rub
we have with the IMM is that under what the IMM
is proposing, we would run without ECRS more
often. We wouldn't have ECRS.
We would deploy it more often under your rules than what we have now.
Now the argument is, it's okay, ERCOT, because you're going to have
all that stuff on existing resources. But it's not
all the time. It's most of the time, but not all
the time. So I don't want to sit here and have
to explain to the PUC we're going
into why we went into emergency operations last week,
and that part of the time,
that's why we need to keep it. There's a, there's an argument to say
that any ancillary service that you hold is withholding from
the market, and yet we withhold responsive reserve regulation
to some extent. Those are always held in
reserve, and that's artificial, that's an artificial shortage. That's a,
that's withholding from the market. And we would count ECRS in that same category.
Now, 1232 doesn't release all of ECRS. It's only a
portion of it. So it's not the super aggressive
dump it all out into the market that we agreed to, it's only a portion
of it. And so to characterize it as all of ECRS,
that's not correct either. So. But that's the. I think
at the highest level, it's ECRS
is a reliability tool. We need to keep it as
there's a point where it makes sense to
cash it in for reliability, for more resources.
But the point is different between what the IMM is suggesting
and what we are. We want to hold on to it longer and use it
longer. And the IMM argument is you really don't
need to hold on to it that long. You can rely on the market to
provide that. Just real quick, let's try to just constrain our comments to
this NPRR and not talk about things that are in front of us, if you
may ask. And I don't want to get into just this endless point counterpoint
here. I still want to hear from Staff, and then we
still need to discuss, so. (item:18:Dr. David Patton's additional thoughts on ECRS) Can I just
connect the dots between what he said and what I said briefly, please?
It's virtually the case that you have these reserves all the
time after you deploy them. And that's the
part that's confusing. There's no way you lose them.
The worst case scenario is you
turn on gas turbines and you ramp down one slow ramping
steam unit, and it takes longer than ten minutes to get those megawatts
when you need them. But the point of the analysis we
provided you is that never happens.
We have many marginal units that will turn down, so you
can get those resources within ten minutes. And the resources that are
ramping down are combined cycles, gas turbines and
batteries. So I would say I
would be surprised if we could find any instances where we've lost
the reserves because we've deployed them. And I think that's a
super important part of your thought process when
you think about should we allow for these resources
not to be deployed, because they will still be there. They'll be more valuable
to respond to every of the contingencies that Woody listed than
they are sitting offline in the form of gas turbines.
You don't lose the reserve, you may lose the capability.
There's a difference. Other questions of Dr. Patton?
Just an observation. You know,
there's this issue with, as both of you all are highlighting,
you know, all ancillary services are reserving capacity out of the market.
Right. And I know, you'd want to get into things that are not before us,
but I'm just wondering, we're talking about ECRS today, and in the future,
we're going to have DRRS even more capacity held out of the market.
So are we going to be back here in, you know, another year
or year and a half, whenever that is, and be having the same discussion?
So back to Commissioner Glotfelty. His broader point is we
really need to get to a place through the ancillary service study
and obviously with the ultimate implementation of RTC.
But in the meantime, to start really thinking about, you know,
what are the triggers for deploying all of the ancillary services
and have a real clear map going forward, because it
sounds like as we stack on more ancillaries,
that we're going to end up in the same conundrum,
potentially. And I know we want to hear from
Staff, but could you expound a little bit more on what you just said?
Which was you're not losing capacity, but you're losing capability?
Yeah. I mean, if you, when you deploy ECRS
the amount of capacity that you have is the same.
You were holding it, now you let it go. The total amount of capacity is
the same. But what you may be giving up is
the ten minute ramp that ERCOT comes with a guarantee that
it is ten minute rampable when you release it
into the wild, into the, into the market.
It resides in other places. It resides on units that
may not ramp in ten minutes. And there may be some combination
out there that means that you've lost the capability that
you wanted to buy. We buy it for the capability,
not for the capacity. And so why is that capability so important
in the environment that we have today, which is the
resource mix that you talked about? Well, I mean, it's forced outages,
large force outages for ramp problems
when you have wind or solar ramps that don't occur when you expect. So,
things like that, when you need to respond quickly with some capacity. You can't rely
on a slow ramping capacity that
lives out on some units. You need to rely on fast
ramping ERCOT capable,
qualified capacity. And by keeping it longer,
you maintain that guarantee that you have that.
But isn't just releasing it, it allows it to just be there
when you need it, not actually deploy it,
but reserves. I mean, it may actually run.
So the ECRS capacity with that capability may
actually start running and the reserves that it
displaces move to slower moving units.
Now, I would agree with the IMM that in a lot of cases that
doesn't occur. In a lot of cases, you have high priced batteries that sit there
and provide that ten minute capability, and that's great.
But I'm concerned, and I think all of our concerned,
that it's not true all the time. And the
times when it's not true are the ones that will burn us,
potentially. And that's the reason we
would like to hold onto it longer. Not all the time,
but hold on to it longer. And like I
said, there are a lot of improvements that we can make. We can use our
triggers more effectively. We can not
have the problems we had last year, but there is a fundamental
disagreement here on how we're doing this.
So David, I just want to walk through your comments. Just a thought exercise
just real quickly. So one of the things you talk about is, you know,
one of the justifications for this is the reduction in your own numbers from 12.5
billion down to 5.7 if this had been in place last year.
And I think on the previous page you talk about you ran last year
with the new deployment trigger with $100
offer floor, and that got you down to 3.6 billion.
Is that all correct? And so you have a statement here that you say,
we shouldn't do this simply that that is a dubious exercise
and we shouldn't do that simply because it's a perceived improvement.
If we had had costs that were either 5.7
or 3.6 billion, compared to 12.5,
that's a perceived. That's not an actual improvement?
Yeah, I've been searching for the right analogy. It's like your
house is on fire, so you put some water in it, now your kitchen's
on fire. And so you say, well, this is a big improvement, so we'll stop
at that. You know, we'll be happy with that.
Well, no, I mean, you should put the fire out in your kitchen,
too. If I can't think
of a market dysfunction that is produced a $3.6 billion
inefficiency in any market, I mean,
I could be overlooking something. But if all we ever saw in this
market was a $3.6 billion artificial set
of prices, we would have said, this is horrible.
And so, I mean, the only reason anybody thinks that's an improvement
is because last year was so much worse.
And. But it's not hard to drive the 3.6
down to zero. We just have to make the resources
available. And I do think it's important to say
we have analysis in the rebuttal comments to ERCOT showing that
the megawatts that you've deployed are there and are more
available to the system to respond to every contingency that ERCOT
is worried about. He says he wants to guarantee it will be there in ten
minutes. But if you turn on a turbine and distribute
those megawatts among combined cycles, turbines and
batteries, you're going to be able to get that ten minute capability
in two minutes. There's only
one scenario where it may not be there, where it all shows up
on an old steam unit, like a single steam
unit, and then maybe it'll take 15 minutes to get it, rather than ten minutes
to get it, but that just doesn't happen.
So I would say, from a reliability perspective, there's no argument
for delaying the deployment of ECRS.
And if you don't delay the deployment and
let sched go into shortage, that's where the $3 billion are
coming from, is the price spikes that SCAD is
producing, that the ORDC is not producing,
or sched thinks it's short, but you're not actually short.
And so the way to drive that to zero is to
deploy the ERCOT more further
ahead of time. Is it fair to say, in that analysis,
if you had run last year with the new deployment trigger,
but with an offer of zero instead of 100, it would even be less
than $3.6 billion?
It would be less, but I suspect
it would probably just go down to, like, 3 billion,
because the impact of $100,
when conditions are tight and prices would probably otherwise be $70,
that impact is probably a pretty small share of
the $3.6 billion. So, just to recap,
it would have gone potentially from 12.5 down to three
last year. Yeah. Okay. And are those
real dollars paid for by consumers, or are those wholesale
market? I mean, where do they kind of reside in this wholesale retail
picture? That's a great question, because there's been a lot of
misreporting of this number.
You know, are consumers going to pay that cost this year?
No, they'll pay part of it. So the
settlements that are happening through the ERCOT markets are going to generate
real cost immediately. But if you think about how
we're serving customers, we have retail
LSEs that are serving most of our customers, and they're
contracting for electricity forward.
They don't want to just be buying in the spot market for the most part.
And if you look at what happened to the forward prices, they doubled for
the next two summers. Once you got into, like,
July and August, and people saw these price spikes being caused by this problem.
All of the forward prices skyrocketed.
So the customers,
they're not going to bear it contemporaneously. But their
rates, when the LSEs have to sign new
bilateral contracts, are all going to be much, much higher
because those forward prices are all triggered based on the
spot prices in ERCOT. So it's hard to say how much of this
cost would eventually arrive on consumers. But the longer the
problem goes on, the larger the share of the costs
hit Texas consumers. And that's even with the addition of
ten gigawatts of batteries and solar. I mean,
that's where I have this one disconnect. And that is if
I get that. So, like, if you're in a fixed price
contract, if your rep, they're going to go procure power in
a fixed price, you know, PPA,
that's not going to deviate, and their price to the consumer is not going to
deviate during that year. But what you're saying is, well, when that contract runs
out, if you continue to show these higher costs
in the market, they're going to be included in the next contract price.
But that's assuming that's everything static, is that right? I mean,
that's where. So if we're adding all of these
resources, we should be driving down the price in
those out years. And totally agree with you. Historically, that would
be right if it took two years, 18 months to 24
months to build a gas turbine. But these plants are coming
on in six months. So I'm
just wondering, you know, as these contracts go out further and further,
is it realistic to think that they're actually going to see that same thing?
Yeah, so that. So the way the forward prices are
going to move is they're going to be based on expectations, and expectations are
going to be driven by what people just saw, which is the
volatile prices. And we're still seeing some of those volatile prices in 2024.
But conditions are milder, so not as much.
And the expectations are going to be informed by the new resources coming in.
Where a problem like this really affects the
performance of the market is when things get tight. And it's important
to utilize your resources, all of your resources,
to avoid, you know, price volatility. Then it.
Then it really hits you now with the solar coming in and
not having, whatever, 90 days of
over 100 temperatures and more batteries,
we're going to have a little bit of surplus and we're not going to see
conditions where it becomes critical to
use every megawatt you have. And sked is not going to
run out of resources nearly as often. So the problem with
this NPRR will diminish, I believe,
except if we see, like really unusual weather conditions.
But that is not to say we shouldn't plan
to operate the system in a way that when we do get into conditions like
this, we don't see costs spike and prices spike.
Those forward prices are also going to be driven by the load.
I mean, the tremendous load growth that has started being
reported in the last six, eight months, it's got to have a big factor
in what those forward prices are. And so that may move you in
the other direction. If that load growth eats up
a lot of the growth that we're seeing in solar that serves the peak,
then we could be back into situations where the
deployment makes a much bigger difference. Just, it's very,
it's highly uncertain, you know, this, what the costs
are likely to be. That's one of my nervousness about the scenarios.
You were asking me about where we were looking at 2023,
like what we may actually see in 2025,
if you approve this is,
I'd have a hard time telling you what that number may be.
So I don't want people to bank on the
analysis of 2023 and as
if there's some certainty around those costs. Because your
number is not actually what it was to procure ECRS, it was
what it did to the market, correct? Which is why your numbers were
always two different numbers. Yeah. So we spent $600
million to buy ECRS
and then there was the effect on the deployment decisions on
the energy price. So. Yeah, two different buckets
of cost. So Dr. Patton, your combined cost then comes
from not only the procurement of the ECRS, the $600 million.
But as you spend $600 million and
you have more power reserved in ancillary
services, including ECRS. That creates higher
energy prices. So now the opportunity costs
that you lose or the opportunity cost of not being available
to the real time market causes ancillary service prices
to go up. So, right? Because you're going to pay,
or maybe pay more for ancillaries because the opportunity cost
is now higher because the energy prices are higher. So that's how you came up
with your combined. Yes, I didn't
cost impact. My numbers aren't combined, they're simply the,
the energy impacts. So I don't include the
600 million.
But you're right. I mean, the ancillary service study is going to be
really important. We've developed a probabilistic model to
try to quantify based on the risks that are being managed on the
system, how much of this do we really need? And I think we're going to
come to a conclusion that we need less than what's currently being procured.
And as you procure less,
and that's based upon what? That you think we're going to have
to procure less. That's based on a probabilistic
analysis of all of the issues
that create reliability risks, contingencies, forced outages on the system,
forecast errors for wind, for solar, forecast errors for
load. It puts all those things together and then
says, you know,
how much reserve do we need to procure to meet a reliability requirement
like the one that you all are considering?
But you're right. As you buy more, the price for
that reserve product will go up exponentially because there
aren't a lot of suppliers who are capable of providing
it. And as that pool of resources gets tighter and
tighter, the price goes up sharply, which is why we
paid 600 million much higher than what most RTO's are paying
for their ten minute reserves. But then the consequence
of that is we have more resources being held out of the energy market,
and that's really what we're more concerned about and what this NPRR is
focused on. Okay. Harika thank you for waiting patiently
through this. Why don't you go ahead and lay out the memo that you all
filed earlier this week? (item:18:Commission Staff's Harika Basaran lays out Staff's memo, NPRR1224) Harika Basaran from Staff. so
I just want to first go over the process and Staff understanding.
So ECRS was implemented last Summer,
then IMM raised. Harika, would you speak into the microphone a little more? Thank you.
Then IMM raised significant concerns and then stakeholders.
Staff, ERCOT. This issue was discussed.
Our understanding when we talk with IMM and ERCOT was
there were three solutions based on the time to take to
implement them. One of them really, I think IMM's preferred
solution was, like David said. Long term, revisit the whole
methodology, the quantity of that $600 million.
But however, ERCOT did not agree to that. But I think at
the end, parties agreed that let's take this up
under as study, which we will. Another tool, solutions,
again provided by IMM was as
an idea concept, a medium term solution,
maybe a standing deployment of ECRS in SCAD
all the time with an overflow. But this could have system
changes at that time when this was discussed by ERCOT or by the
cuisis. In the short term, I think ERCOT
agreed to explore further. IMM's proposal
was release portion of it based on under generation.
So then ERCOT agreed to explore those solutions and
then they submitted NPRR1224. And when they submitted it.
There was no overflow and the trigger was 30 megawatt.
And ten minutes in the stakeholders
process, the 30 megawatt was increased
to 40. And then floor added thousand.
And that new addition of the floor really changed the whole discussions.
Like all what we are discussing here about the trigger, I think that
got lost. The focus became more on the floors.
So Staff's position is on the
trigger. We did not hear much discussion
or objections to that trigger in the stakeholders process.
Except IMM. I may be wrong, but.
And on that one, we really wanted the first ERCOT and the stakeholders,
if it was acceptable for them. So ERCOT gets more experience
with ECRS and then they can adjust it like incremental improvements.
So that's what we want Commission to balance reliability
needs ERCOT Woody says with economics. However, on the
offer floor, we don't think any floor is necessary.
That was not one of the concepts at the origin.
And we think ORDC should take care of the scarcity.
And also we lots of
estimation were based ASDCs demand curves under RTC.
However, we think that if you can take only one part of
RTC as if it's in effect which the, you know,
value of the reserves, but you don't look the efficiencies it will bring.
It's not really one sided. So that's why we have problems with that
approach. And we
also think that ORDC was adjusted again with the floors regarding
the bridge solution. So it was made really to add more revenue
to the system. And it's going to be in effect all this summer. So there
is another tool already there. So we did it on the think
any floor is necessary. So staff preferred option is
just implement the trigger without any overflows. So it can be
implemented as soon as possible. The provided option
too, if you want. Not preferred option, but if
there is a floor, it will be between nonspin 75 and RAC. That was
brought up in the stakeholder discussions as well. So that's why I
am making it. And then I don't want
to talk about the next NPRR. You don't want to discuss that? Okay.
That's all I have. (item:18:Chairman Gleeson's thoughts on Commission Staff's memo) So Harika, in my discussions with
ERCOT, they would like to see this done by August 1.
That's a date that's important to them.
So why, why not just reject this NPRR
and just tell them that we think it's appropriate to use that
trigger so that they can meet their date. If you're,
if you don't think the floor is appropriate. That brings us the
same solution, so we are okay. Yeah. If that's the will of the
Commission. Woody, could you implement this without the NPRR,
with that kind of guidance from the, from the dais?
Yes. Any questions of Harika?
Okay. All right, thanks, y'all. Appreciate it.
So, as they step away, I'm going to talk a little bit about
process. The process for this NPRR
did not work for me at all. So I know this
came up under NPRR1186. Where Commissioners
at the time felt that a lot of information came in post
board decision. I would argue that some of the most pertinent
information I heard came in post board decision.
And I don't know how Commissioner Cobos feels as a
Board Member. But as the Chair of this Commission and a Board Member,
that doesn't work for me. I need to have all the information
that I can have at the Board. Because I think it is important for me
to be able to tell the Board what I think so that
if they pass something they know well, perhaps it
may get rejected at the PUC.
I didn't have all the information. Not one of us said a word
about this NPRR in the Board Meeting,
except for Courtney as the OPUC. And I
think, for me, that does a disservice to the board process. If I
were them, I would be upset if we don't approve this
today. And I don't think we're solving for what
the Board, how the Board feels necessarily. But I think
it is important for me to make sure I have full information when
I go to that Board Meeting. So I've talked to Connie, I've talked to ERCOT.
I've talked to some stakeholders. We have got to figure this out,
because in the last two weeks, I've heard the one thing that's
been consistent from everyone is there are parts of this process,
from a protocol getting sponsored or revision getting sponsored,
to the day we adopt, reject or remand.
That doesn't work for someone.
So I don't know what you all feel about
how this worked, but if I had had the information I have today
at the Board last month. I would have said some things
in response to what was before the Board, and I
need that going forward. So I've asked Connie to engage with everyone,
with stakeholders, with ERCOT, with the ERCOT board,
with us. We've got to figure out a way to fix this because this is
not working for me. And what I'm really concerned about is I've started
to hear some rumblings. That there's concerns
about the way RTC is being done. And
we have held RTC up as the panacea
that is going to save us from so many things. We have got to get
that right. We've got it. Whatever that looks like, it has got to be right.
And if we're here in 2026 and we're in the exact same
spot on any part of RTC, that's going to be a
failure, in my view. So I don't know what it looks like.
I'm asking everyone in this audience to help us figure this
out, because I've heard from a lot of you that I'm looking at right now
that there are parts of this that don't work. I've heard zero solutions.
So if you're going to come and say there's a problem, I need thoughts
on how to fix it. And again, we're not solving for giving people what
they want. We're solving to give everyone an opportunity to have full information
and have a voice in this process so the Board and the Commission
can make a proper decision. So,
you know. With that, I will say where the reason I
didn't file a memo on this is. Because, honest to God, until yesterday,
I didn't really know where I, where I sat on it.
Based on this conversation, you know, I would say a
reduction from 12.5 billion down to 3
billion is not, is a
good move. I think if you're out, if one of the rooms in your house
is on fire and one of them has people in it and the others don't,
you know, you put the fire out in the one where the people are.
And so I wouldn't view that $3 billion as
inefficiency for ERCOT. I view that as the cost of reliability.
And I'm going to rely on them, the people
who operate the grid, to tell us what they need.
And so, for me, I think the proper way to move forward is
to reject this NPRR. And I'm okay
with the trigger at 40 mw for ten
minutes. And if they can implement that without this,
that's kind of where I stand. But again, the process to
get here was inadequate.
So happy to hear your thoughts. Chairman Gleeson,
you know, the process is tough, right? I mean, it's an
evolving process. I feel like information becomes available leading up to the board,
after the board. And so with NPRR1186,
I felt like it was the same information all the way through,
in some respects, from stakeholder comments all the way till they got to us.
The only difference was we accepted comments here from the stakeholders versus,
you know, 11 or 1224 in this instance.
But to your point,
you know, hearing more from the stakeholders, you know, I know our staff
works very hard in digging into these policy
matters over at ERCOT, and they certainly have opinions and I think
having more engagement with them, I know I certainly do on my
SPP and formerly miso matters, it would be good.
But also, you know, from ERCOT as well. I mean, it was
unclear to me where they stood on the offer floors
up until, like, I got briefed this week.
And so, you know, I came to find out that
the offer floors wasn't really as important as a deployment trigger, but it seemed
like the offer were important to them. And so I
just feel like we need to get very candid feedback all the
way leading to the board and all the way over here. Otherwise we're going to
end up in these, you know, again, conundrums over and over again. Right.
And so the board did what they did.
They had the information that they had before them at the time and took
action on the information that was presented to them
at the time of the board meeting. And since then, the information has continued to
evolve and we have to make a decision at
the back end as sort of the judges of approving,
rejecting or remanding these NPRRs based on the best available
information we have before us. And oftentimes, I think that even at the board
meetings, we're still processing, like for
this one, it sounded like you were and I still was for NPRR1224 still
processing the information. And,
you know, not to mention we have a lot of other things.
We're still processing a lot of other work that we're still working on.
So this NPRR is not the only thing we're working on. We have a lot
going on. And sometimes at board meetings, we still have to process
what's being presented to us and come to a conclusion of where we
sit as Commissioners on these NPRRs
and market rules that come before us for final approval
or I rejection or remand. So it's
tough, you know, and but I think to your point, I'm in
agreement. We have to have the best available information we can.
We had attack recommended NPRR
and the board. That's what they had before them.
And but, you know, I think just having more candid conversations
as to where people really sit and what they really want versus what they don't
really need is very important so that we could decipher
these issues and not end up in these situations over and over again in the
future to the actual decision on the
NPRR. I'm with you. We need to make a decision
that actually has an impact this summer,
and that's the exercise that we embarked in. And somehow,
along the way, we went off into the pastures. And so
we need to get back on track and get a meaningful change
in place by August. And that meaningful change needs to
come by way of a deployment trigger, a modified, an additional
trigger. So a third trigger for ERCOT
to use as its discretion. And I'm open
to. I hear the IMM's concerns on the
40 megawatt under generation. Our staff is saying
this started as 30 megawatt under generation. I kind
of, in some ways, I may want to consider the 30 megawatt
under generation as an incremental improvement
towards, you know, deploying the ECRS
a little bit earlier. So 40, 30 megawatt under generation,
I think, is on the table for me. But whatever we ultimately decide needs
to be implemented by August 1. And I don't think we need an offer floor.
The offer floor is, my understanding, was introduced because potentially,
as I kind of understand, is because the IMM was
proposing 100. But the offer floor really serves no purpose. The ORDC
is what values are operating reserves during scarcity
conditions. And we have taken really aggressive action with the ORDCs in the
last two years with the ORDC in the last two years by not
only implementing the price floors, but also implementing
the shifts that we implemented during our market reform discussion. So we
have made the ORDC more aggressive
in pricing scarcity conditions and lack
of reserves, operating reserve shortages during
scarcity conditions. So, in my opinion,
that's the tool we've relied on. That's the tool we've been modifying.
And I don't see why we have to have another
mechanism to price the value of reserves through an offer floor for
ECRS. So I think the main
focus here is a deployment trigger, and those two options are what I would put
on the table as long as we get something done by August 1. And so
that means that, like you, it would mean rejecting the
NPRR so we can get something in place. And maybe, you know,
like Harika mentioned, you know, we're making improvements
along the way until we get more information from the ancillary service study in RTC.
Maybe we start at. Maybe we start at 40, maybe we start
at 30, but maybe next year we come back and see how it's performing
and see if there's any modifications that need to be done
to the deployment trigger that we can, you know, have ERCOT do, because it is
a new ancillary service product, and they're learning along the way, and we want to
make sure they have it as a reliability tool, but we also want to make
sure that it's being used efficiently as well.
And so we're going to have this issue too, with other ancillary services we
introduce into the market. So I see this as a continued conversation
until we get to RTC.
And I'm in agreement with you as well on the fact that we need to
have more visibility into RTC. It's such a massive project,
and I know ERCOT's full steam ahead in implementing, and that's great,
but I myself have heard concerns about the ancillary service demand
curves and where it's headed, and we need to kind of know where it's at,
because we don't want to get saddled at the back end with a bunch of
controversy with what they look at when we've been, you know,
like you said, telling everyone, this is, this is the holy grail,
you know, for having a more efficient market, and it's going to solve problems like
getting rid of ruck and better pricing ancillaries and,
you know, all of that. So having a process for more
visibility into the RTC implementation,
I think at this stage is important, as ERCOT sort of rounds the corner
in their final stretch to getting RTC off the
ground.
You've heard what I think. I support you Mr. Chairman,
and your solution. And we'll follow
your lead on that. I think it's a
great idea. I made it at the board when I was on there,
so I'm all for it.
I'm supportive of, I guess,
rejecting and, you know, putting the
trigger in place, as ERCOT had recommended in doing it by August
1. Recognizing that, you know, we have RTC
that's coming and we need something to be in place,
this is definitely an improvement. Improvement. I'd like
to speak more to, I think, what you talked about in terms
of the need for information, for decision making
earlier in the process, and to me, the word
process is the key. I mean, everything that
we do, we need to make our decisions
based on good data and good science. Because the better the data,
the better the science. The better the science, the better the policy.
And having a process that's well
defined, that has, you know, every once in a while, it's just
good to go in and review that process,
particularly if we see in this particular situation, and we've seen it
maybe in NPRR1186 as well, that it's not working
in the way that we feel like it should. And it
could be that just times are changing. It could be that we have
more initiatives that we are trying to execute at the same time.
And so we need to go in and we need to evaluate
and maybe change the process. And I think that's not just incumbent
on us, but it's also incumbent on our
market participants and our stakeholders to help in that.
And so I think you're definitely on point
that we need to take a look at the process,
the way that things move through TAC, the way that we get
information, the way that we do the evaluation. Recognizing,
again, that it's not just one issue, that all of them are interrelated
and the outcomes of all of them impact the
performance of the system as a whole as we move forward. So very
much agree with you that we need to evaluate
the process. We need to make that a top priority. And in
this particular decision, I do agree that we should
reject and then have the
40 mw for the two scattered rolls implemented.
There's no floor.
Okay, sorry. I think we have agreement.
So. Okay. So what I think I'm going to do
is make, like I said, make two motions. So the first one
would we have, you know, we have a filing from, from yesterday.
So I think we vote on those first and
then we can vote on 1224 separately severed out. (item:18:Motion to approve the proposed order file by Staff on 07/18/24, NPRR1224) So I
entertain a motion to approve the proposed order filed on this project by Staff
on July 18, 2024. So moved. I
second. Have a motion and a second. All those in favor say aye. Aye.
Opposed? Motion prevails. (item:18:Motion to reject NPRR1224 for reasons discussed, NPRR1224) I'd entertain
a motion to reject NPRR1224 for the
reasons we have discussed. So moved. Second.
Have a motion and a second. Those in favor say aye.
Aye. Opposed? Motion prevails.
(item:18:Executive Director Connie Corona confirms instructions from Commission, NPRR1224) Chairman, if I may echo back the instruction I heard.
And that is staff is
to engage with the stakeholders in an effort
to improve the information flow to the Board and
to the Commission without porting the
entire stakeholder process over here.
Correct, yes. So we
look forward to hearing, hearing from folks on their ideas.
We would certainly entertain any
solutions that are brought forward by a
joint effort among the stakeholders. So that
would be an instruction to go off and brainstorm,
bring some potential solutions back to staff that
we can then share with the Commission. You know, perhaps that's
something that can be undertaken at TAC.
Okay, thank you, Connie and I will apologize to everybody.
We have a workshop after this on PCM,
so we're going to keep pushing through today. so.
All right. (item:19:Chairman Gleeson lays out Project No. 54584) I think that brings us to Item 19. That's Docket
No. 54584, Reliability standard for the ERCOT market.
Werner? I think ERCOT
staff is perhaps also coming up.
Go ahead, Werner. Thanks. (item:19:Commisison Staff's Werner Roth on redefining the recommendation of rejecting the Brattle study) Werner Roth, Commission Staff.
No long prepared remarks this month. But last
month or during the last open meeting, Commission Staff had recommended rejecting
the Brattle default technology of an error derivative
combustion turbine. We felt that the justification for doing so had not
been well presented and recommending sticking with the frame CT that was used
in the 2012 cone study. Since then, ERCOT's
filed a couple like, filed the Brattle study and filed an additional
memorandum on top of that. And we would like to refine
our recommendation to capture everything that went into the 2012 study and carry that
over to the 2024 recommendation. Namely maintain the
use of the frame combustion turbine, sticking with the 20 year
life of the. For the recovery of costs, and using
level real dollars. So that would make the
new staff recommendation with, as was filed in the ERCOT memo,
of $140 per kilowatt year.
Okay. Commissioners, thoughts?
(item:19:Commisisoner Cobos' thoughts on Commission Staff's recommendation) I appreciate ERCOT filing the supplemental information regarding
the frame CT and also appreciate staff's analysis of
the frame CT. I think that the cost
of new entry is based on the
least cost of entering the market. Right. And so I
have a lot of concerns with using the new era derivative, LM 6000,
because that's just not what's being built right now. We don't have the
discounted refurbished rates because that's not information
that brattle is able to get from the generators. But ultimately,
our. Our cone figure has been
based on a frame CT because it's a. The least cost of entry into the
market. And so from my perspective, I would hinge
our cone on a frame CT and I
would stay with a 20 year amortization because that's the industry
standard of sort of amortizing
not only not the life of the unit, but when generators expect to get their
money back. And I think that's reasonable.
But with respect to the dollars, I would go with level real. That's kind
of where I would start. I'm open to discussion on it only because that is
the actual cost per year of that
unit, rather than using nominal, because nominal could
add cost to the earlier years of the unit that don't actually
exist, like inflation. And so I would
start with a frame CT 20 year
amortization on real dollars, which would put you at 140.
Any thoughts?
Commissioner Jackson, anything to add? (item:19:Commisisoner Jackson's thoughts on Commission Staff's recommendation) So,
I guess in ERCOT's evaluation, because they went back to Brattle.
Okay. And you said, okay, what would Brattle come up with
in terms of, you know, if this were a cone CT.
I guess you actually presented a 25 year life,
but then added in the real realization,
and so your capture was 134.
Okay. And then if you backed out
what the impact would be on the 25 back
to the 20 year life, you would land at 140.
So 140 would be for the cone frame
CT for real levelization and for
20 year life? Yes.
And so your evaluation
is consistent with that?
Yes. And so I
guess, from my perspective, that that's a good starting point.
I think we've had a number of different evaluations
that have come up with some different ranges, and I think this falls within that
range. And so, to me,
20 year life makes sense. We've heard that that
was favored by the financial community.
I think, for some of the reasons that we've talked about, if you're going to
do this more frequently, that the real levelization makes more
sense. And then, of course, continuing to use the
frame CT, I think, I think makes sense at
this particular time as we kind of establish
the cone and utilize it in the kind of activities
that we're talking about and the references that we're talking about for
the rest of the market design.
(item:19:Commisisoner Hjaltman's thoughts on Commission Staff's recommendation) I agree with Commissioner Jackson's thinking. I think I was looking
at kind of providing a range of 146 to
150 or a little higher with
the most recent data coming from ERCOT. I was going to go a
little lower afterwards. So, in the same area.
Thank you, Jimmy.
(item:19:Chairman Gleeson's' question and thoughts on Commission Staff's recommendation) So Werner, just to be clear.
Your recommendation as you sit here now is use the frame CT value of
140 and to look at this next
in 2026? Yes, that is correct. In the reliability
standard rulemaking, which we will have for you, the BFA next month.
We do have something in there that would, in 2026,
would require an update to the cost of new entry.
Okay. I'm comfortable as well with the frame CT and
reviewing this in two years in 2026 and using the 140
for planning purposes. So do
you need anything else? Can you provide one more comment?
(item:19:Commisisoner Cobos' additional thoughts on Commission Staff's recommendation) So, I know that we're going to use this configure for the reliability
standard and the updated cost assessment for PCM, but I think
that we should also consider, consider the impact
that this new cone figure has on peaker net margin. And I say that because,
you know, as you all know, Chairman Gleason, we sit at the board meetings
and, you know, and get these updates from the IMM. And the
IMM has, you know,
continuously said, well, we've been exceeding cone for, you know, three, four years in a
row. Whatever has been provided to us. And there's always a question of, well,
why aren't we seeing new build? Well, we know that for one,
the 105 was, you know, hasn't been updated in twelve years.
And so, and that, that's not what we're
seeing in the market in terms of the cost of new entry. So I'm just
wondering, in order to have a true, at least a better,
more updated perspective of the cost of new entry
as we get these updates from the IMM, if we should
actually use the, the updated number in the peaker net margin. I know that
that has impacts to the LCAP and all that. I'm not trying to get into
that. I just feel like that the peaker net margin from the perspective
of revenue in the market to incent new build and retention of existing generation
is our barometer of where things sit. And we as
policy makers, board members use that kind
of think about that barometer as we
think about or assess how our market is looking in
terms and sending new build. And so that's
just one thing I wanted to kind of put in there is, you know,
something to consider. Yeah. So as I understand what we're doing today, this,
this is just for planning purposes as we move forward, as Warner said, and there
will be a different process to work through pternet margin.
Good afternoon, Rebecca. (item:19:ERCOT's Rebecca Zerwas on protocol revision request) Rebecca Zerwas for ERCOT.
We have been discussing the possibility of a protocol revision request,
one to implement. We asked for the feedback and I know you'll provided earlier on
the every five year cadence. And the other item is to cone right
now stops at the board and to bring it in front of the commission if
we did change cone. So I think that's something we could consider adding
the conversation for the peaker net margin use of cone in the protocol.
Yeah. And that's an important point, I think. And I think what I've gotten
from staff is that we really need to be involved in the cone updates
and, you know, the two year and the five
year, that's where we ultimately go. That's something that,
I mean, the cone figure drives so many different,
you know, areas of our market that the commission has to absolutely be involved
in that. Okay.
All right, you good Werner? Perfect. Thanks, y'all. Appreciate it.
So before we call up Texas RE on 23.
I'm going to just quickly call up Item No. 28. Commissioner Glotfelty
has a nuclear update. (item:28:Chairman Gleeson lays out Project No. 55421) So I would call 28. That's Project
No. 55421, Texas Advanced Nuclear Reactor
Working Group. And I was told it's a brief update, so we'll do that now. Very
brief. (item:28:Commisisoner Glotfelty gives his Nuclear Working Group update) Since October, our 18 members have been working,
meeting often. Getting a lot of work done. Hearing from guest speakers
and delegating ideas to four subcommittees. The four subcommittees that have
been working through are regulatory and ERCOT market design, demand and end users,
higher ed, development and manufacturing.
They've each met monthly, sometimes weekly, over the last ten months.
With the help of over with hundreds
of people. Well, I wouldn't say hundreds, but well over 100
each week.
The numbers of hours of brain power to create
and come to some ideas at this level,
at the subcommittee level has been great. We've got forms
created for different ideas. They have all been submitted from
this ad hoc subcommittee level to the final, to the committee.
That this Commission set up, approved as requested
by the Governor. We'll be providing discussions
with each one of the members. We'll be filing more information
in the docket number. But I just want you to know the subcommittee process is
concluding and we're getting more towards this funnel of actual
ideas and the writing of a report. So you'll see these ideas at ASAP.
(item:28:Chairman Gleeson's thoughts on Commissioner Glotfelty's nuclear update) Like I said last time you gave an update, the advancement of nuclear seems to
be one of the few things that everyone I talk to agrees about. So,
great work. Look forward to seeing what comes out of it. And as
we've talked about before, you know, if anything coming out of
the report needs to be added to our agency report and
our legislative recommendations, you know, please let Staff know. Absolutely perfect. Staff has been
helping us on this, so. Absolutely. Great, thank you.
All right, now. (item:23:Chairman Gleeson lays out Project No. 56022) We will cycle back to Item 23. That's Docket No.
56022, Calendar year 2024
reports of the Texas Reliability Entity.
Joseph, go ahead. (item:23:Texas RE's VP & COO Joseph Younger gives an overview of the 2023 Reliability, Performance & Regional Risk Assessment Report) Good afternoon Chair, Commissioners.
Joseph Younger, I'm the Vice President and Chief Operating
Officer at Texas RE. With me is
David Penney, who's our Director of Reliability Services.
We're here to provide you with a brief overview of our
2023 reliability, performance and regional risk assessment
report. Which we filed in the project, along with
some slides from the presentation that David's going to talk to in a little bit.
But before I did that, I did want to just take the opportunity to,
again, thank you all for, for providing
us this opportunity to continue this collaboration. A couple
of years ago, Commissioner Glotfelty was very,
very influential in starting and growing this relationship.
And giving us opportunities not just to come here to the open meeting,
but also interact with Staff. And collaborate
on all the things that we're seeing and on our shared reliability
and security mission. So that's been really important and fruitful and has
continued with you now on our Board, Chair Gleeson. So we really
appreciate that. Turning to the report just
to kind of briefly set the stage before David walks through it.
This report is an annual report that Texas RE
produces. It's done solely by our region, and it focuses
on providing an independent look at reliability and
security metrics of the bulk power system in the ERCOT
interconnection. There's two aspects to the report
that I want to highlight, and David's going to touch on in more detail.
First, it looks at, we take a lot of data in, and so it looks
at trends in the data and how the system,
the bulk power system, is performing and focuses
on trends in that data. And then we use that data to
identify and assess known and emerging risks for
our region and provide that information. And for us, this assessment,
along with other documents like the CMEP IP that we talked about back
in January when we were here. There are key input into our
risk based compliance programs, our outreach programs,
all that we do. So it's a fundamental part of our work.
So, as I mentioned, we filed this in the project along
with David's slides. So with that, I'll turn it over to David
to kind of talk through the details of the report and then take any questions
you may have. Thank you. It's a pleasure to be here today.
(item:23:Texas RE's Director of Reliability Services David Penney gives information on 10 year report on ERCOT's interconnection) As Joseph mentioned my name is David Penney, Director of Reliability
Services. And with the help of Mark Henry and other folks on my team,
were largely responsible for the data collection
and the analysis of that data in relation to this report. So, I guess
a little bit of a background for you. There's NERC committee called the RISC,
the Reliability Issues Steering Committee. That's composed
of NERC and industry executives that go through a process every two
years or so to identify key risks to the
bulk power system. In their most recent report, they identified five
risk areas. Grid transformation, resilience to
extreme events, cyber and physical security,
critical infrastructure, interdependencies and energy
policy. And so what we do, and the way we try to format
this report and the analysis related to it. Is we take
all the data that we collect from transmission, outage and performance data
generation, outage performance data protection system performance
data, frequency data, event analysis, and so forth,
we cast a wide net, and then we look at that data
and analyze it to see how it answers the question of how is the grid
performing in relation to the these risk areas? And that's kind of
the way the report is structured. As Joseph mentioned,
we're one of, we've been writing this report for ten
years, and it's a solely focused on the ERCOT interconnection. And it's
kind of a companion report to the NERC state of reliability
report, which looks at similar assessments nationwide.
So, with that being said, I kind of want to step you through some of
the performance metrics that we look at and how we rated them and
where things are trending. When we look at different indicators,
we try to sign it a basic rating. Whether it's improving,
whether it's stable, if it's something we need to monitor,
or if, in worst cases, if it's actionable, if we're foreseeing multi
years of declining trends. So, a few
things to highlight for you is in the significant improvement
areas we've seen. One of the big ones is around resource weatherization.
In the post Uri world. A lot of activity was undertaken with
Senate Bill 3. ERCOT's activities related to their site
visits. Now, last year,
the dirt weather station EOP standards were approved. So there's
been a lot of activity in relation to that. And we're seeing the fruits of
all that labor. If you look at the actual grid performance during
Winter Storm Elliott, Winter Storm Heather most recently. The fleet is responding
and we're seeing the improvements that are necessary.
That does not mean we need to rest on our laurels and stop, but we
are seeing the improvements related to that. Another area
we're seeing significant improvement is in the area of primary frequency
response. Primary frequency response is a
function of when we have a major grid disturbance, like a significant
loss of generation, the grid has to respond by arresting
that frequency decay, and that's how we measure it using PFR.
And that's mandated by a couple of the NERC standards, the Bowel 0031
in particular. It's interesting to see the improvement in the
PFR numbers, especially in light of the
changes in the resource mix that we're seeing as we get further and further away
from conventional units and migrate towards the renewable fleet.
And I think a lot of the credit that we're seeing due to those improvements
is how ERCOT has looked at performance requirements for batteries
in particular, because that is what's providing a large tranche of the
ancillary services that are providing this improvement. And we're seeing the fruits of
that as well. We had lots of discussions
earlier today about resilience, and a couple of the resilience metrics.
We look at the numbers. We're seeing one of the big drivers in
transmission outage rates and events pares down to two main areas,
weather and equipment failures.
The numbers we're seeing, if you look at the year over year trends,
the rates are fairly stable, which is probably both good and
bad, because we're not improving, but we're also not
getting any worse. But we are still seeing fairly level trends in
relation to weather caused outages and equipment failure type outages.
A couple areas we're monitoring,
again, we've had lots of discussion earlier today about solar ramps being
one of the big ones. As the commission well knows,
our summer risk hours are no longer at peak.
They're during those solar down ramp periods and the
mora. And the other reports that ERCOT puts out show
that some of those same numbers, that the probability of EEA, or capacity
deficiencies, are during those solar down ramp periods. And if you
look at the raw numbers from last year, we were seeing downramp magnitudes
of 7500 mw or more per hour.
This year, they've gone even higher. We've seen some
hours that are close to 10,000 mw an hour. And so
I think ERCOT's taking the appropriate steps through the changes they're
making, the ancillary service methodologies, and what they're procuring
to mitigate those risks. But it's something that's going to have to
continue to be monitored, because it's only getting worse as the solar penetration
increases. Another area we're looking at, or monitoring
very closely, is related to human error. When you,
when you look at some of the raw data for protection system
miss operations and events, a large
percentage, more than 50% or higher, of the cause
code, the root cause analysis, and contributing cause analysis we do, those events
has a human performance or human error component to them. And I think
it goes back to discussions we've had many times around the
aging of the utility personnel, the new technologies we're implementing,
there's a lot of human error aspects, and it's something we have to monitor closely.
Another area we're monitoring pretty closely is around generation, conventional generation
forced outage rates. We've seen an increasing trend for
both simple cycle gas units, but more importantly,
with our coal and lignite fleet. Look at the year over year trends.
Those horse tide rates are increasing. And I think from
the analysis we've done in the background related to that,
a lot of that has to do goes back to the changing resource mix,
because those units, when they were built back in the seventies and eighties,
were designed to be base loaded. That's not how we're operating them today.
They get cycled up and down every night. That creates
wear and tear on the mechanical systems, changes their capacity
factors, and that's resulting in the increase in forced outage rates. So that's
what we're seeing is happening there. One last area that we're monitoring
pretty closely is around physical security. We saw a very large uptick
in 2023 with physical security type reported
events, in particularly particular ballistic events,
gunfire type accidents. And if you look at the 2024 numbers
to date, we've already exceeded the
count so far in 2024, has already exceeded what we saw all of last year.
So it's definitely not going away. It's getting worse. It's something we have to keep
hold on. The one area that we addressed is
actionable, is well known. It's IBR
voltage ride through issues. And I know the commission is well aware
of what's happening with NOGRR245, as well as the
NERC standards that are being developed under FERC order 901.
So I don't want to go into a lot of details there, but there's definitely
activity going on that's going to hopefully address this stuff in the future.
So, as Joseph mentioned, we take this analysis and
the trends that we do, and we look at it. We identify
risk focus areas that we want to address.
And a couple of the things that we identified this year that I
want to just highlight real quickly. IBR voltage ride through
issues is one. Physical security, which I mentioned.
Remote access is another area that's highly critical to
us. Gas, electric interdependencies, supply chain.
And then a new one that we added this year was the integration of large,
flexible loads. When we look at these risk areas,
we try to evaluate them on two basic criteria. One is
the likelihood of it, and we're basing that likelihood
rating on are the number of occurrences we're seeing increasing
or decreasing. Are there any documented cases of risk?
Or. And most important, are there any existing controls in place to mitigate
that risk? And then the consequence or impact of
that risk focus area is fairly simple. Is it localized to
a small geographic area or to one entity entity, or is it widespread
or potentially involving multiple entities?
So the basic question around these risk focus areas is, what are we doing about
it? So over the past year and
previously, we conduct multiple webinars.
We had over a dozen webinars in 2023, and we planned a similar number
of webinars this year on one or more of these risk focused
risk topics. There's been two, two NERC alerts that
have been issued, one related to cold weather and one related to IBR data
collection of settings for voltage and frequency ride through.
We've had multiple workshops, an IBR
workshop last year and our, we have our ongoing winter weatherization workshop
also this month or next month, excuse me. We have a physical and cybersecurity
workshop that we're working on. And then through our compliance monitoring program
in 2023, we had well over 200 entity
engagements on specific requirements related to these risk focus areas,
and we're planning a similar number for this year.
A couple of other things to mention real quickly on
the data collection side is we recently
have completed a questionnaire on the remote access issue to
all the dark entities nationwide, worldwide. Where we ask them, the specific question
is, do you allow entities or companies outside of your organization
to access your systems for the purposes of monitoring,
operational control or maintenance of the system? And the results are
interesting to say the least, as far as the number that
shows up. And the other thing real quickly to
mention is there's currently a project going on at the NERC
level. It's called the Interregional Transmission Capability Study. It's kind
of an outfall of winter storm Elliott, where they're looking at
transfer capabilities between regions and between the interconnections to see
if we can mitigate or eliminate the risk that Winter Storm Elliot and Winter
Storm Uri posed. So that's kind of it in
a nutshell of what's in the report. Again,
as Joseph mentioned, it's available for the Commissioner if you have any questions.
Just feel to reach out. Thanks for that. Just one quick question. Yes sir.
(item:23:Chairman Gleeson's question on electric gas coordination) You talked about electric gas coordination. One of the things I think we've
been lauded for is our electric supply chain map, and we've
talked to federal officials about that. To your knowledge, when you talk to other
REs, has anyone else adopted something similar to that map? I have not seen that
with the companies I've talked to. I know we do. When we look at
infrastructure interdependencies, I know gas electric has gotten a lot of
the press and the conversation, but we can't lose sight of the other
industries that depend on that. We depend on in particular
because we collect through the GAD system, we collect outage
data related to fuel, lack of fuel issues, but we also look
at water supply issues that can affect a plant on or offline,
and also telecom issues that can affect an entity's ability to control
or monitor their system. So we're looking at a wide breadth of things and not
just focused on gas. Commissioners,
questions? Thank you. Thanks, y'all. Appreciate it.
Thank you very much.
All right, Shelah. I think that brings us to Item 34.
Is that right? Okay. (item:34:Chairman Gleeson lays out Project No. 50664) So Item 34 is Docket No.
50664, Issues related to the state of disaster
for coronavirus disease 2019. So this came up in
our discussions around El Paso last time that went into it.
I had questions about regulatory assets being booked for COVID.
So what we have. We have a second draft order filed in this docket
today. That would require utilities
to stop booking COVID related expenses as of the
date of this order. And I think we talked about it in terms of El
Paso. So everyone was in agreement with this?
Agreed. Okay. (item:34:Motion to approve the proposed order filed on this project on July 24) Then I will entertain a motion
to approve the proposed order filed in this project on July 24.
So moved. I second. I have a motion and a second. All those in favor
say aye. Aye. Opposed? Motion prevails.
Okay. (item:38:Chairman Gleeson opens up item for update from Executive Director, Deputy Executive Director or Commission Counsel) The last thing I have is No. 38, an update
from our Executive Director, Deputy Executive
Director and Commission Counsel.
(item:38:PUC Deputy Executive Director Barksdale English gives updates on TX Energy Funds, New Director of DCE and workshop that follows the Open Meeting) Thank you, Chairman. Three quick updates.
First, just a brief reminder that the loan
applications for the Texas Energy Funds in ERCOT
loan program are due on Saturday, July 27
at 11:59 p.m. Central daylight time.
So to all the eligible applicants, please get those applications in.
Last time I looked, which was probably about 50 hours ago now,
we had somewhere around ten or twelve applications submitted.
Another 60 in flight. So we're hoping that these last
72 hours or so, we'll see a good flurry of activity
on the TEF portal. The second
thing that really gives me a lot of pleasure to announce.
is that Connie and I have decided on
who the next Director for the Division of Compliance and Enforcement
will be. And I'm very pleased to announce that our very own John Lajzer
will be elevated to that position starting August 1.
JB's been with the PUC for about 6 months now in the Enforcement
Division. He's been a great asset. He comes from a long
line of enforcement jobs prior to the PUC. So he's going to bring
a lot of experience and knowledge in that regard on both sides of the table,
which is great. And he also has the added benefit of
being a PUC baby. As his dad was an employee
here back in the days when Daryl Teigen still had a mustache.
So I'd like to just welcome JB
to the position and thank you for
stepping up. That's amazing. Congratulations.
I will say just real quick. You know, it's hard to take a job
like that, because the last guy that had it was amazing at it. Big shoes
to fill, so. That was you
Barksdale. Oh, that was me? I mean, you're talking
to the guy who's got the world's best boss coffee mug out here,
so. And then the last thing to announce
is as you mentioned, Chairman. There is a workshop following
this meeting. And given the time and and how long we think
that workshop will start. If assuming there's not much more
to occur here in this meeting. Then perhaps we can all gather here
back at 2:00pm to start that
workshop, if that's okay with everybody? We expect somewhere between
two and a half and 3 hours for that. So, trying to get everybody out
on time. Our agenda is posted online for anybody
who wants to follow the bouncing ball at home. And that's it.
Perfect. Thank you, Barksdale. (item:38:Chairman Gleeson adjourns meeting) Okay, I don't have anything else.
With there being no further business in front of us. This meeting of the Public
Utility Commission of Texas is hereby adjourned.