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 today,
July 11, 2024. Good morning,
everybody. Good morning, Sheila. Connie Barksdale.
So we're going to do things a little different.
We're going to take up item a first,
but then we're going to take up item 19 after that.
And we're also going to break at 1130.
We have to go into closed session. So we're going to break at 1130 for
that and most likely come back, adjourn closed session,
then recess the public meeting until 01:00 I think this will be a
longer open meeting. So we'll come back at one, assuming we get there
first order of business, as you all can count.
12345. So,
Commissioner Yaltman, welcome.
It's already on. Thank you. We had to practice his counting
in the hallway. By the way,
he is an aggie. He is. He kept skipping
a number. So excited to be here. Thank you,
Courtney. We're excited to have you here. So first up, we, you know,
we're going to call up item a, which is a review of ERCOT.
And, Connie, I'll have you lay out your memo first. But, you know, again,
for everybody, as everyone knows, you know, this area of Texas,
and Texas is dealing with a lot, you know, human tragedy, human loss and property
loss as well. You know, I talked to the governor's office.
I've talked to lieutenant governor. You know, we're going to figure
this out. You'll hear from all the utilities this morning.
They'll lay out what they have gone through and their efforts
to assess and restore their systems. We'll ask them questions.
But I want to assure everybody this will be the first step in this process,
not the last step. And we will probably end up
filing a report as we head into the legislative session about
our learnings and potentially some legislative solutions that we may need.
So with that, Connie, unless anyone else would like to
say anything. All right, Connie,
would you like to lay out your memo? Good morning, chairman and commander.
Commissioners. First, for those who are interested
in following along some of the discussions today,
items related to Hurricane ERCOT are filed in project number 56793.
Centerpoint filed their presentation last night,
and it's available to view online as they give it in just a
few minutes. Also in that project yesterday,
I filed a memo advising impacted utilities that staff
intends to exercise limited enforcement discretion on certain
administrative rules and deadlines so that the utilities
can focus on service restoration. The discretion
applies to the prescribed timelines for certain routine matters,
such as deadlines for filing reports and responding to new
requests for new service. The enforcement discretion applies
through July 26, as specified in the memo,
and list the rules to which it applies. Again,
the purpose of this is to ensure restoration efforts take precedence over routine
matters inconsistent with what we've done historically in similar
situations. That is correct. Any questions for
Connie? Okay. Then we'll go
ahead and start calling up the utilities. So first we're going to hear from AEP.
Good morning, Chad. Good morning.
(item:A: Chad Burnett, AEP Texas, Beryl Efforts, 56937) SSo I think you know my name is Chad Burnett. I'm the vice president of
regulatory and finance for AP Texas. I am
excited to come here today to share with you an
update on our storm recovery efforts and the preparations that we made in anticipation
of Hurricane barrel. As you know, AP Texas has
the greatest coastal exposure of any utility in the state of Texas.
Our footprint goes all the way down to Brownsville,
basically at the southern tip of the Rio Grande Valley, all the way up to
Bay City El Campo area, which is just southwest of Houston.
And so, you know, what was unique about barrel is the fact
that it posed a threat to our entire coastal service
territory as it changed course throughout its development.
So before I talk about how our storm recovery progress is going, I'd like to
start by giving you a timeline of the preparations that we
did going into this. So before every hurricane season,
we do hurricane drills with our staff to
make sure that they're prepared for the season. And we did that this year on
April 23. And again, that was an opportunity
for everybody to kind of practice what it would be like during a catastrophic event,
to be ready to coordinate and all of those things.
But coming back to Barrel, starting on Wednesday, July 3,
which was five days before landfall, we initiated
the level one incident command system in accordance with the FEMA
national Incident management system guidelines.
Anticipating that bear would make landfall somewhere on our coast, we alerted
the commission as well as our community leaders that we had initiated this structure and
began making preparations for what would be the first hurricane of the 2024
season on Friday, July 5, three days before landfall.
The weather projection was assuming that barrel would make landfall near
the Brownsville area, and we started making preparations
for that. And so we did some estimations,
assuming what kind of damage we would take, what it would take
resources to restore power, get equipment back in store.
And we were planning for, again, three days before we
were assuming it was going to hit down in the valley area.
At this point, we also started coordinating with our state and local emergency operations centers
and working with our community leaders to ensure that we had the
latest list of cooling centers and critical care facilities to help prioritize
our restoration efforts. By Saturday,
which was two days before landfall, the weather projections had shifted
and barrel was now expected to make landfall just north of Corpus Christi,
still impacting the rest of our Laredo and RGV districts.
By this time, we had secured approximately 4500 resources,
or about 1200 crews that would be coming in from Ohio,
Indiana, Michigan, Oklahoma, Arkansas, Louisiana and across
the state of Texas to help. By Sunday morning,
one day before landfall, the weather projections had once again changed,
and this time it shifted, and it looked like barrel was going to make landfall
somewhere between Palacios and Matagora in
our northern Corpus Christi district. By this time, we had already established a gateway
center at the regional fairgrounds in Robstown and had checked in
approximately 2700 personnel that had come in
to help work the storm. When Hurricane barrel
finally made landfall Monday morning, we had approximately 35,000
customers out of service who had lost power,
and the biggest impacts were near Bay City, Palacios and El Campo.
I'm happy to report to you that as of this morning,
we now have 94% of our customers restored and
we're still working today and throughout until we get power restored to
everybody. Now, earlier this week, I had the opportunity to
tour the damage in the communities of Palacios, Bay City and El Campo,
and to visit the mobile command centers that we set up in the Bay City
Fairgrounds and the El Campo service center. I was shocked
by some of the damage that I had seen, but I was impressed by the
restoration operations that were taking place. I saw sections
of lines with poles snapped in, two lines on the
ground, and evidence of flooding. I also saw roofs damaged,
signs destroyed, and significant tree debris.
But one thing that caught my eye was the fact that even in the midst
of all of that, there were several lines that had recently been reconstructed
using our modern design standards that were still intact and
appeared to have weathered the storm just fine.
And this is a preview of what you will see in our upcoming resiliency plan
filing, because it really does show that some of the newer designs that we're seeing
coming out can make a difference in making the system more resilient.
At the staging center in Bay City, I also saw a steady
stream of trucks and crews coming in to pick up poles,
materials and supplies needed for their assignments before heading back out
to the field. I saw coordination and collaboration between
the service crews, assessment teams, construction crews and
vegetation crews with a clear focus on one mission,
which is to restore power as quickly and safely as possible.
This occurred despite the communication challenges that they
encountered due to poor cellular service in the area. So before I
close, I just wanted to share with you one story that happened during our restoration
operations that I hope will stick with you. I know as commissioners you will
likely hear everything that goes wrong in a storm restoration event.
I think it's important to balance that with a story of something that went right.
So on Monday, after barrel hit, we learned that the city of El Campo's
water treatment center, as well as their hospital had lost power from
the storm. AP Texas crews worked well into the night and
were able to restore power to both locations before there was a loss of water
pressure in the town or any backup issues from their sewage system.
After finishing that job around 10:00 p.m. the crew still
had to drive nearly 2 hours back to Corpus for their hotel because there
wasn't any available lodging near that site.
So on Tuesday morning's EOC call, the city manager and
the public works director shared their great appreciation for our line workers
late night efforts which allowed them to avoid having to pay for
a temporary generator that would have needed had they not been restored
by Tuesday afternoon. Municipal Judge Michelle Roy reached out
and asked if they could provide a lunch to our line workers
to show their appreciation. So yesterday, the local
Rotary club and approximately 3000
citizens arranged a lunch to serve 300 line workers
on national line Worker Appreciation Day.
One quote I wanted to share, El Campo City manager Courtney
Sladek said, I can't give enough props to your linemen for cranking it
out today. AEP's response to the storm was very much appreciated
and there are pictures and videos of this event on our social media accounts.
And it's stories like this that remind us of the dedication and commitment that our
line crews make every single day despite working in these dangerous conditions.
So overall, I am so proud of the team and the efforts that went
into restoring electricity to our communities and our customers.
We were fortunate this time. Barrel just clipped the northern
part of our service territory, but again, we were under threat for
the entire coastline. So even though we were lucky
with this storm, I want to leave you with the message that we were prepared.
We had made a lot of preparations before the
event even happened, and that's due to the large efforts
of our planning and logistics team. So with that, I want
to thank you for giving me the opportunity to share that and happy to take
any questions you might have. Thank you, Chad. Commissioners questions
(item:A: Commissioner's Questions to Chad Burnet, AEP TEXAS, Beryl, 56793) Chad, you mentioned that 94% have already been restored. How many
customers are left that are without power.
It's, it's just over 2000 customers are left without power
right now. Okay. When, when do you expect to have them restored? We have an
ETR. We're shooting for the, by the end of the day we'll have 95%.
There may still be some 95%, I guess, of all the customers that
can take power. We hope that will happen today, but there may still
be a little bit of cleanup that our crews will stick around afterwards. Thank you.
In a look back,
will you all be able to tell us what
types of polls you had problems with? We're going to get into this
discussion with resiliency a lot more again and again.
Is it spun concrete poles? Is it composite
structures? I think it would be good for us to
know that if we are going to continue to have problems with wood poles along
the coast or in these hurricane prone areas. You know what the cost differential
is, what the resiliency story is to get polls that
you don't have to put up every single time. So as you all are
going through that post analysis, will you make sure that
you let us know and let the staff know on our project the types of
poles that you're seeing damaged and the voltages of those.
Yeah, we'll be happy to do that. I'll tell you that just real quickly.
What we're learning is that by putting in our new standards, have bigger poles,
obviously, and putting them closer together. But like you said, there's a material component
to that as well. And all of that we'll certainly be happy to share with
you and will be included in our resiliency plan filing. One other
thing, and that is when you all were preparing on Friday and
Saturday, you said you had crews coming in from all of these other states.
Were those primarily AEP companies that were providing that
mutual assistance? It was not only AEP. We did pull a
lot from the AEP, but we used a lot of business partners across the mutual
systems system. And I know there were a lot of business partners that came in
from other parts as well. And I just want to point out, I mean,
mutual assistance is an imperfect but
very, very well oiled machine, the way
it works across these systems. And somehow
it just, it kind of happens. The people that know how to deal with mutual
assistance, actually it works. I went out to one
of our center points, mutual assistance centers, and they were
just getting set up. But there's a
reason for everything, and the reason is how
do you get people in? How do you get them lined up? How do you
get them safety procedures, how do you get them assigned to teams?
How do you get them fed? How do you get them sleeping
per OSHA rules? And then how do you get them out?
And it may be at some
point in time again in this process, good to have EEI
or the utilities come in and really explain how that is
driven. Give the staff a good understanding of that because it's
hard to do, it's hard to plan, but when it happens, it's pretty
amazing. And I
spent many, I had many text messages with Judith,
and they were great. She was great on giving us information there.
So thank you. Thanks.
Just a quick question on materials and supplies.
You know, we've seen that that's been an issue just across the
system in terms of infrastructure maintenance and development.
So any issues with getting the supplies in
order to affect the restoration?
We didn't with our storm, and I should have said this earlier, when we do
getting into hurricane season, our procurement folks build up an
inventory anticipation of our storm needs. And so
we had kind of built up, you know, a material supply
inventory already. But yeah, through this storm, we had enough
of what we needed to be able to restore. And again,
candidly, we got lucky that we only had a portion of our service territory
that were, that was exposed by this. But we did have the
materials we needed. One question, and it's
one I'll ask, of all the utilities coming forth, you mentioned
the water treatment center, and I know those are definitely on your list of critical.
Do you have water districts in your service area?
Yes, and we were coordinating with those as well. That was one of
the first things we do, you know, making sure that we've got, you know,
our local contacts with the local community. So you have an accurate list of what
those are? Yeah, our community affairs managers are actively
at keeping that updated. Thank you, Thomas.
I would just ask one other thing, and that is as all the utilities that
talk, and that is as staff is working
on our next project on this for
the utilities who really give us an idea, I hope we can get
this from cities and munis and co ops as well.
But how many of the fallen
trees were in the right of way and how many were outside the right of
way? It's going to be really important for us to understand that and the
effectiveness of vegetation management,
these plans, and if we can actually do anything about some of
those trees. I think I was astonished in Houston about the
number of large trees that were pulled up by the root ball as
opposed to broken at the top. And it
was, it's just pretty amazing. These are, you know, these aren't ones that
just require chainsaws. You know, you have to have cranes to get them out of
the road. And so it's kind of a different kind of storm from my
perspective. Absolutely. And I think, you know,
as we talk about kind of the next phase of our review and
assessment of everyone, we'll cast a wide net initially. You know, we got
to figure out what went wrong, what can be improved. And a lot of that's
going to be talking to folks who do this well, both in the state
and out of the state because I'm sure there are other places,
you know, there are other places Florida that deals with this a lot and,
you know, we can probably learn a lot from, from other places as well.
Thank you, Chad. Thanks. All right,
TNMP, do you want me to bring that up right now? What's that?
Florida. Florida. Yeah. So just, I had
put a, for everybody in the audience, I had put a
PowerPoint presentation that FPL had given me about resiliency
on their system. They started in 2024
or 25, five after they had
26, after they had four. They had two category four
hurricanes. And this is not
an inexpensive and it's not a short term fix
on the system, but resiliency works. And,
you know, this has some significant
reductions in the time and
expense to get systems back up if you harden them the correct way, if you
put in the right poles in the right places, spacing different
types of poles other than just wood poles, I think it would be great to
have them at least part of our discussion. But this was something that I
had had for months and was going to
share it with you all during our resiliency discussion. But clearly
that's here. Definitely. And I'm sure there are things that work there
that maybe wouldn't work here. We'll find a Texas solution, obviously. But, yeah, we can
learn a lot from other places and further, too, I guess the, the presentation that
you gave everybody, and I think a point that's well made is,
you know, they're reporting that along with better hurricane performance, their investments
improve their daily reliability and they're staying here by over 40%.
So shoring up the system in anticipation that
management of risk for that critical
event that you're trying to pay for that worst case scenario also
helps shore up your ongoing reliability, which is something we
can always use. Very good point.
(item:A: Stacy Whitehurst, TNMP, Beryl Efforts, 56793) Good morning, Stacy. Good morning. Thank you. For the record, my name is Stacey Whitehurst.
I'm the vice president of regulatory affairs for TNP.
Good morning. Chairman, commissioners and congratulations on your appointment.
First of all, our hearts and prayers go out to all Texans that have been
impacted by Hurricane Barrel. I wish to outline our preparedness and restoration
efforts during this challenging time leading
up to Hurricane Barrel. TNP took comprehensive steps to prepare for potential
impacts, including having our hurricane drill in May.
TNP subscribes to an advanced weather analytics service that provides
weather analysis on potential weather events that could impact our service territory.
We received notifications when a tropical disturbance is identified
in the Caribbean, Gulf of Mexico or the Atlantic Ocean and we received one
for when Barrel was just a disturbance. We closely monitor
the weather forecast and the development of Hurricane Barrel.
In addition, TNP participated in the early situational weather call
set up by the Texas Department of Energy Management to ensure readiness
after the tietum call on Friday, TNP activated its
emergency operations plan on Saturday.
In addition to our Gulf coast area employees, we had arranged for additional transmission
and distribution line crews to be deployed on
Sunday afternoon. Furthermore,
as vegetation management crews were staged strategically within our service territory
as part of our preparedness strategy, we began mobilizing internal resources
from other service areas and had additional contractor crews on standby
expecting Hurricane Barrel to intensify or shift closer to our service
territory. While initial projections in the previous
week had Hurricane Barrel making landfall further south, Hurricane Barrel
may landfall in Matagora Hurricane Barrel's path moved towards TNP
service territory. TNP's service territory is approximately 23
miles from where Barrel made landfall, but swiftly turned to our service
territory, hitting the Sweeney in west Columbia areas and
then moving northeasterly through Angleton, Dixonson and Texas
City area. Once the wind speeds dropped to a level that
allowed damage assessments to begin, TNP mobilized
to assess damages and initiate restoration efforts.
Our dedicated crews are working tirelessly under difficult conditions to
restore power as quickly and safely as possible.
We deploy resources strategically to address critical infrastructure needs
and prioritize restoration in affected areas. We had a peak
customer outage of approximately 116,000 customers on Monday.
We had eight transmission outages and had all but two restored
on Tuesday, with the remaining two restored on Wednesday.
The number of restoration workers that were on site were as follow. We had
74 internal T and P linemen. We brought
in 192 contract linemen and
had 250 mutual assistant linemen
contracted VM workers. We brought in 176
contracted VM and mutual assistant VM
102 contract damage
assessors. We had 50 of those
and we had internal damage assessors of 20 and
we had used drone to help
survey the area. We continue to add additional
vegetation management and alignment over the last two days we've added an additional 120
vegetation management ftes and we've seen that significant number
of the damages were caused by falling and uprooted trees that have
been brought down our infrastructure,
broken and down poles, broken cost arms and down conductor.
We are able to start repair the work but
the vegetation management must be cleared out first.
We have approximately 57,000 customers being reported out
on our website. We are having to mainly close outage tickets in
our AMS when received from outside assistance. We have
been analyzing our AMS meter data and based on that data
we can tell you that we have 75% of the customers
with power to the meter. This morning. TNP is able to
communicate with the meter and has been able to retrieve nightly interval data.
Our main staging area is in Texas City at the Tanger mall with
multiple material being staged throughout our service territory.
TNP restorations are going on 24 hours a day with
crews working 16 hours shifts. We continue to
provide update on social media and our website.
Customers can contact us through our IVR, talk to an
agent, report an outage through tnp.com dot.
Once we determined that there were external phone service issues throughout
our service territory make it impossible for customers to call
TNP directly and report through our IVR, we determined that
customers could email us TMP, set up a new email address hurricanemp.com
and posted this on social media and notify local officials
of this TNP is providing regular updates on
the tedium calls, provided updates to state local leaders,
including having someone staffed at the state operations center.
We understand that the restoration efforts affect our retail electric providers
as well. We have provided the following information to our retail providers.
We have stopped disconnects for nonpayment in the Gulf coast at this time.
For non AMS service orders we continue to complete
in our Gulf coast service territory where safety is not an issue.
For AMS service orders, we're trying to complete all AMS
service orders in our Gulf coast service area.
All service orders that do not complete through this automated automated
system will be dispatched to the field and complete if technicians are able
to access the area and completely work and complete the
work safely. For billing and usage.
TMP has been is attempting to generate billing and usage transactions
and files for all the AMSI easy
ids in our Gulf coast area. If actual data is not available,
we are we are estimating where available
when we know we use our outage information to prevent
normal estimation and generating files and when we
generate those files, we're actually inserting zero
readings in those 15 minutes intervals.
We will attempt to obtain actual data and send replacement files if and
when it becomes available. We know that our customers
want and need their power back on as soon we understand
their frustrations. Our employees are some of these same customers
that have no power. Our goal is to have the bulk of the customers
up this weekend, but understand areas with significant
damage may go into next week. We are constantly
discussing real time needs with our field supervisors and making sure the needs for
additional resources, materials or other needs are being addressed as a top
priority. The restoration and leadership team is in constant communication
with each other and are in the Gulf coast right now. TMP is
working hard to get everyone restored as soon as possible. I want
to thank all the men and women at TNP, our mutual assistant partners and
contractors that are assisting. I appreciate the opportunity to talk to
you and open for questions. Thank you, (item:A: Commissioner's Questions to Stacy Whitehurst, AEP Texas, Beryl, 56793)
Stacey. Something that caught my attention. So you were talking about crews generally,
but then you talked about vegetation management crews. So I think that's an
important point. So when you send crews out,
that's not like a crew of different folks
that can address different issues. That's why the assessment phase is so important,
because you have to assess the situation first, what needs to be addressed so
you can send the proper type of crew to address that issue. That's correct.
I know there's frustration that people will see our linemen on the
side of the road and just in their vehicles, but the problem is
they're having to wait for our vegetation management to clear all the
trees that are maybe in the road or causing
issues that they can't, that keeps them from going into and,
you know, setting new poles, setting fixing cross arms,
or pulling conductor. Did the assessment
phase this time take about as much as it typically does
historically? Did something cause it to take longer? It was about
the same time. The problem was, is the amount
of vegetation, uprooted trees was a lot
more than we expected. With these types of winds,
you know, with all the weather that's been down there between freezes and,
you know, pinchot, drought and heavy rains, some of these
shallow rooted trees that are very large just kind
of tumbled over into our service territory and trying to
understand from our vegetation guys, how long it takes
to actually cut some of these large trees to make path is
hard to estimate. Thank you, commissioners. That might be
good to ask the Forest Service for a little help in understanding that a little
bit more. So, Stacey, you said that
75% of your customers are restored today. Yes,
ma'am. So how many customers are out and how
many will be restored by this weekend and how many will be left till next
weekend? So we have 30,000 that are still out and
working on trying to get the final numbers
on when those customers can be out. But we're expecting,
we're bringing additional crews and we're trying to get the majority of those back
on this weekend with some left to next weekend.
So for the customers that are left to next week that
can't be restored, what are, like, the general reasons
why they can't be restored till next week?
So we have extensive damage on our backbone
of our primary. Our primary distribution system, where we've had a significant
number of poles that we're having to clear trees
from. Then we've had issues. We're trying to get line spotters,
the mark line, so when we go replace poles, we're not hitting
natural gas lines or. Or telephone cables and stuff like that.
And so obviously, there's a significant need for line spotting
and marking right now. Yeah. Is there a way,
or have you all been communicating with those
customers that they may be out till next week? We're looking
at trying to get that accomplished right now.
Okay. Again, and I didn't
ask this of Chad with AEP, but y'all, do you all have mobile
DG? We do not have mobile generation. We're waiting for the roles
to be final. Yeah, that was my understanding. But I would be interested in knowing
for the utilities that do have mobile DG,
how many they have and how many they've deployed and where.
Thank you. We know Centerpoint has mobile general, so I'm
sure we can cover that with them. Yes.
Commissioners, the same question. Do y'all have the water
districts in your area or no? We do. And as part of
our EOP, we identify critical loads,
and that does include water and
wastewater. And obviously, we do serve some of those customers at
the distribution and transmission level, so those are prioritized.
So same question. Any problem getting any kind of materials and
do you have a system? We have an integrated material supplier
named Irby, and they work very closely, making sure that we
have access to all the additional materials that we need.
And they're providing deliveries on a
constant basis throughout our service territory or our staging areas for our materials.
Staging areas. So not really waiting on materials either because
of the delivery or the system in terms of identifying
where it is or actually getting the. That's correct. Basically kind
of what, as AEP said, during getting ready for this
type of season, we do increase our material supply
stock so that we're ready. Obviously, there are certain
items that take a little longer to get that we try to such a transformers
that we try to go ahead and have as many as we can because
it's obviously a hard time to get during transformers and things like that
in certain materials when all the utilities are trying to get the
same material at the exact same time.
Thank you, Stacey. Thank you. We'll call up entergy.
Morning, Ellie. It's been requested that I put the,
the Florida power and light document that I handed you all
in the docket number so we will get that filed today. That's a good suggestion.
Your staff always on top of it for you. There you go. (item:A: Eliecer Viamontes, Entergy, Beryl Efforts, 56793)
Morning, Alan. Good morning, Chairman, commissioners. Good morning.
Olivia Montez, president CEO of Enterd Texas.
Thank you for the opportunity for me to be
here today. Before I say anything else, I want to thank first
and foremost our customers for their understanding and let them
know how much we appreciate serving them. We know that Hurricane
barrel disrupted their lives and businesses and damaged their properties.
We, too, live in the communities that we serve. In those communities have been
supportive. At the peak of the storm, we had 252,000
customers without power. And today, less than three days since the
hurricane cleared our territory, we've been able to reduce that to 105,000
with 60% restored. I am truly grateful
for our hardworking crews. Their dedication and commitment are the
reasons why we can safely restore power as quickly as possible
after a severe weather event. I'm happy to report that
there have been zero injuries while responding to
this event. Hurricanes, as you know, can create many unsafe conditions,
and there is a lot of pressure to move quickly. Safety is a way
of life at Entergy, and it's integrated in everything that we do.
I want to touch on the actions we took in preparation for the storm.
As you know, Entergy, Texas is a non ERCOT utility that serves
27 counties in southeast Texas. As a Gulf coast
utility, we are storm ready year round and storm
response is part of our culture. Prior to Hurricane
Burroughs landfall on July 8, we activated our emergency plans on July
3 and our storm command center on July 6.
Additionally, we readied our employees pre stage resources,
and throughout the year, we ensure we have sufficient supplies up
to a category for a major storm.
Now I want to move to the storm itself
and the impacts to our service area. So, first of all, every storm is
unique. We experience sustained winds of 60
gusts that were north of 85, even had a tornado that
touched down on the edge of our service area near Jasper.
The eye of the storm passed directly through Montgomery county,
specifically the woodlands and the Conroe areas.
These are the most densely populated parts of our service area and
are heavily wooded. In areas where lines are not underground,
flying vegetation due to winds and trees falling, especially from outside
of the right of way, were especially impactful across
the service area. We experienced the following 385
poles, 190 transformers over 2000 spans of
wire 44 substation, many of these
affecting industrial facilities, but notably none affect any
major refineries or any major chemical plants.
And then seven out of eight major transmission ties between the western
and eastern portion of our service territory
were lost, leaving one tie line from the north remaining to
our western region load pocket. And finally,
none of our generation facilities were forced out as a result of
the storm. Now let's talk about storm response.
I want to start first of all with an incredible example of
how our employees are keeping the lights on for customers. Monday night after the
storm had passed, we lost our last tie into our western region,
which includes the Woodlands and Conroe. This required a significant
amount of communication, coordination and precision for
the teams to manually balance a 60 hz frequency in the region
and during the overnight hours to avoid a load shed event while
our crews work to get the tie line restored and achieve system
stability. I'm extremely proud of that outcome.
Starting on Monday afternoon of the storm, we began damage assessment
and restoration efforts. Once a was safe to do so, we had
a goal of restoring 50% by the end of
the day yesterday, which we were able to surpass and we're at 60%.
As mentioned earlier, we have a workforce of over 2400
working on restoration efforts, which includes entergy employees,
embedded contractors and mutual assistance crews as well.
We continue to restore power around the clock and expect to have the
last set of customers in the most heavily affected areas restored by Sunday
night, with few exceptions. From a customer communication standpoint,
we know that it's important to provide trusted and timely information during emergency situations
so that customers can plan and make important decisions for their households
and businesses. This is why we stayed in contact
with customers prior, throughout and after the storm,
using direct calls, text messages, alerts on the entergy app,
and multiple updates on our website and social media platforms. Prior to
the storm, we had multiple press releases on the planning, preparation and
also safety reminders, down wires, generators,
etcetera. We held daily calls with elected and local officials to provide detailed
updates and information to pass on to their constituents and communities.
We held multiple media interviews, several of which I did personally, both in English
and in Spanish. We consistently updated our view outage map on the
Entergy website, which kept customers informed not
only the extent of the damage and estimated restoration
times, but it also helped customers understand the general progress and
where other resources might be available in terms of having power
generally restored geographically.
And we also had our call center available 24/7 during
and after the storm. So clearly the restoration
is still underway. We have a lot of work to do and as you can
see from my attire, I'll be headed back in the field after
the open meeting to support our field workers and continue to lead
the restoration effort. Looking back where we are right
now, and we also have a process where
we from a continuous improvement go through, what could we
have done better that is part of our culture and something that we will plan
to do after the storm. What stands out to me is that this
storm is further evidence of why hardening the grid is so
important, because that investment serves to reduce the extent and
duration of outages and reduces overall storm costs during
the event its clear transmission was affected.
It's imperative that we focus on efforts to enhance the transmission
system. Down trees and flying vegetation,
which damage lines, often from outside of the right of way, as mentioned
earlier, are a major contributor of the outages,
and we should continue to explore how best to manage that risk,
which can affect even hardened facilities.
And lastly, and it's clear once again that adequate local generation
is critical to maintaining the system reliability
and stability, especially in the case that I mentioned where you
had transmission lines compromised. Without Montgomery
county power station in the region, we would have not
had any other alternatives and likely would have experienced a significant load
shed event. So, commissioners, I am proud of the response
that the men and women of enterd Texas have undertaken.
I appreciate that what
southeast Texans have experienced with the storm.
I know it's extremely challenging and frustrating to be without power,
especially during the summer heat, and safely restoring
service for our customers is and will continue to be our top priority.
So with that, thank you for your time today and happy to answer any questions.
(item:A: Comissioner's Questions to Eliecer Viamontes, Entergy, Beryl, 56793) Thank you. Ellie. So you talked about local generation. Did any of your generating
facilities have sustained any damage or have any issues? No damage
at all. Not even Orange county, which was the one. There were no
damages. Thank you, commissioners. Ellie,
so you mentioned, just as I've been asking, the prior
company, 60% have been restored today,
105,000 are still without power. But you're thinking by
this weekend everybody will be back to restored power? Yeah. Our goal was
50% yesterday, which we're at 60% now Friday to be
roughly 75% or better, and then have the
vast majority over 90% by the end of this week and there's always carryover.
As mentioned earlier, you can have multiple poll damages. Multiple trees
will certainly double up and triple up on crews, whatever it takes.
Once you get to that last set of customers that have extreme
damage, there is a balance in terms of making sure we do
it safely. As you know, expediting that work
can cause more issues and can actually prolong the restoration event,
which is the last thing we want to do. So, yes, it could be minimal
carryover, but we expect by Sunday night I have to be essentially restored.
Thank you. I saw online it looks like
you all put out information for your customers to know when
they were going to get back online by area. Does that just started yesterday
or when was that first posted? We did that, I believe, and I apologize
because the night you're getting, I think it was the previous night that
we did that. And, you know, you don't have all the
information available, but we understand customers needed
information to make decisions and that's why they're estimated no later than times.
As we complete the damage assessment, as we get more
refined information, we make those adjustments and then
we directly communicate to customers after we have established
those general estimated restoration times. It's a dynamic.
I think those customers are appreciative of that knowledge.
So you mentioned that there was significant damage
in the transmission system.
Tree related. When I think about the structures that were impacted,
we know about half a dozen or so over the 25,000 transmission
structures that we have. But there were a lot of line sections that were impacted,
many due to vegetation. Five out of the six transmission poles
that were compromised were due to vegetation
outside of the right of way. So of course,
energy service area is sometimes in rural areas and
particularly the transmission that serves the more populated areas.
And one of the things that we saw in north
Texas and was kind of reported to us is that you bring in
lots of folks from outside the area to
help, but you need to have that experienced team
member with them, particularly when they're going out in
areas where they're not familiar with. And there could be, you know,
different challenges. So has that proven to be any
challenge in this restoration in terms of having the adequate number
of entergy folks with our outside people
that are coming in to help? The majority that of
resources that we secured early on in the storm were entergy
employees and contractors who know our system very well.
We did not need to process them or safety onboard them because they
already know the standards that we abide to. And that provided a
significant amount of efficiencies early on in the restoration process.
Thank you.
Ellie. How significant is it that
when the storm hit landfall came across
centerpoint territory and still in entergys territory that it was still
a hurricane? So that's, I mean, for those that
aren't familiar with that area, it's 120 miles from the coast
or something like that. Commissioner, I was surprised. I've seen
many storms in my career coming from south Florida,
and the sustained winds keeping
up that far inland was surprising.
And the
northeast quadrant of the storm was the section that hit,
which is the one that carries the biggest punch. That's the dirty side
of the storm from my experience. So you combine
that fact with the most densely area of our service territory
that also happens to be one of the most densely vegetated areas
as well. You literally have that perfect combination that
has caused the numbers to certainly
seem higher given a category one, but the damage is real.
You've seen pictures and have seen firsthand the vegetation. I've seen
it throughout this week myself. I think it was
a combination of factors that contributed to the number of outages.
Thank you. I hope you'll be personally involved as we look at this coming
from Florida power and light and having experience on the ground there.
Your experience will be great. Happy to help.
Thanks, Ellie. Appreciate it. Thank you.
And finally, we'll hear from Centerpoint.
Good morning, Jason. Good morning.
Good morning. Chairman Gleason and commissioners and the newest commissioner.
Congratulations. (item:A: Jason Ryan, CenterPoint, Beryl Efforts, 56793) My name is Jason Ryan, executive vice
president with Centerpoint Energy. We are still in
emergency operations, but I think it's important that we appear today
and appreciate the time to update you and the public on
the status of restoration at Centerpoint Energy.
We have the privilege to serve almost 3 million homes and
businesses in the Houston area. And I mean the privileged
word intentionally. So. Let me start off by talking to
our customers that are still out. We know that we
still have a lot of work to do and we will not stop the work
until it is done to our customers that not only have
power out but have significant property damage,
damage from the trees that we've talked about coming up from the roots.
Our hearts go out to you. Our hearts go out to our community.
And we know that after restoration is done, we have a lot of work to
do to support the community to get back on their feet.
I also want to say that since yesterday was national line Workers Appreciation
Day, call out the line workers that have done a tremendous job
with the restoration efforts so far, and I'll detail that work.
So far, no serious incidents or fatalities.
And with the number of mutual assistance crews and the dangerous
conditions that we've got. I think that's a feat of worth mentioning at the beginning.
Also, I'll mention at the beginning as it relates to customers so that they're aware.
We did early on stop processing disconnection
requests from the retail electric providers and we'll continue to assess
when that should begin under the terms of our tariff going forward.
So let me detail a little bit
of the, the event and then I'll go into
our preparation and restoration work. You do have a slide deck that
I prepared to give you some hopefully
helpful visuals as we have the discussion.
First, I guess we've heard a little bit about the storm, but it
was unique in a couple of different ways and the
visual on page two helps to provide that. You know, it was a
storm that formed very east
in the Atlantic. It formed early, it strengthened
quickly, was one of the stronger hurricanes ever to form this
early in the hurricane season and was clearly unpredictable.
We'll talk to meteorological experts after
this event and get their take on it, too. But I think one of the
things to point out that the map shows is the significant hurricane
force winds that were felt throughout the entirety of our service
territory. As Commissioner Glatfelty has already referenced,
you know, we were on the path
that is probably one of the worst paths a hurricane could take,
which is coming onshore
in the Matagorda area, very close to our service territory.
Our service territory is outlined in the black there,
which means that the entirety of the greater Houston area
was on the dirty side of the storm. And that what that means is as
the storm swirls from right to left, you've got
the strongest winds, most of the tornadic activity
and the most severe weather coming up on the right side of the
eye wall. So that was happening throughout the
entirety of our service territory. What the map shows is that
the entire 5000 square mile service territory of
Houston was in that dirty side of the storm.
And the one thing I'll point out, I know it's a little hard to see,
but there are wind speeds that are there on the various dots.
The wind speed at Intercontinental Airport was 83 miles an
hour. That is higher than Hurricane Ike.
Wind speed at Intercontinental airport. Right. So Hurricane Ike
being a major category two storm versus this being category
one, the wind speeds were higher further inland.
As the hurricane continued to go through Entergy's area into
east Texas, there was more cyclonic activity with the
storm than the entirety of some storm
seasons, hurricanes. There were 67 tornado
watches issued by the National Weather Service. As that storm continued
to push inland. So again, it was a hurricane.
I'll set aside whether it was a category one, two, three or four hurricane.
It was a significant hurricane as it came ashore.
As it left our system midday on Monday,
we had 2.26 million customers out of our,
almost 3 million customers that we serve.
Let me talk a little bit about the planning in advance of the
storm. So as the other utilities have described,
we also have a comprehensive planning process at Centerpoint Energy.
It doesn't start only in the event
of a storm. We do comprehensive training every
year. Your staff is involved many times in
that training process as well. We did that earlier
this year. As the
storm formed, we started tracking it about nine
days out, knowing that
there was great uncertainty in the path, that it was something that we should
keep our eyes on. As the path started
to shift, especially after the 4 July,
we started calling on mutual assistance crews.
We started with about 3000 mutual assistance
crews that we asked to come and pre position in
the greater Houston area. And what I mean by that, it's important
we don't ask those crews to come into the direct
path of the storm. So I'm not saying we ask them to pre position at
different places in Houston. That wouldn't be what we
ever asked them to do. They pre positioned outside of our service
territory. So as soon as it was safe to do so, they could come into
our staging sites. As the
path looked like it was one of those worst case scenarios, we upped that
mutual assistance request to a little bit greater than
10,000 crews. To give you an order of magnitude,
that's about eight times the workforce of Centerpoint
energy on any given day.
That brought our total workforce up to
about 12,000 men and women that could
address this storm. We also opened 18 staging sites
that were located strategically throughout our service territory where
they could be closest to the work when they end their work every
day and they start their work every morning.
I'll talk a little bit more about the staging sites in a little bit.
We also immediately started to deploy our temporary
emergency generation. I would have brought a list
if I knew you were going to ask that question about where they were deployed.
I'll get you a list to your offices. But they are in facilities
like cooling centers, hospitals, senior living facilities
and water facilities. We continue to look for ways
to deploy those assets and the way they can best
help our community going forward.
Also on the slide, I mentioned that we have very limited
issues with materials availability.
I unfortunately was speaking to you a little less than two months
ago about the May 16 de Racho that hit
the greater Houston area as well. We are able to replenish supplies
from that storm to be prepared for this one.
So there are no material issues causing any delays with restoration.
The one thing that we have asked for help with are for braces
for poles. So not every pole that has some damage
needs to be replaced in real time. You can brace it
and come back later. And so we have asked for some assistance having
more braces for poles during this event.
Let me talk a little about the damage that we saw from
the storm. Slides four and
five show some of that. We did not have
material damage to our transmission system, nor did
we see material damage to substations. We did not
see flooding of substations like we've seen in some
past storms. This was a storm
that was largely debris on the distribution system.
So you see some pictures that show that on
page five you see some of our work
to date. We have completed the vast
majority of our damage assessment work and expect to finish
that today. Let me pause a little bit about the
importance of that damage assessment work that's done in
the first couple of days post storm.
In order to effectively utilize not only Centerpoint's crews,
but the more than 10,000 crews that we brought in from
other places. We need to know what kind of crews to send
where. That's what our damage assessment workers do in the
early days after a storm. Not every crew
is the same. If I have substantial damage to distribution
poles, if I've got poles on the ground, I need to send a construction
crew. If I've got 250 poles on the ground like we
do in some places, I need to send significant construction crews.
If I have trees on lines, I need to send vegetation
management crews to go in and clear those trees. If I can
quickly restore service by
doing minor work on facilities, I can send much smaller
crews out to do that. We can't start sending
crews out until we get that damage assessment done. That damage
assessment looks like people walking,
literally walking. As of the end of yesterday,
8500 miles of distribution lines.
We have flown distribution lines with helicopters.
We have used drones to help us with that assessment as well.
So I know it's incredibly frustrating to see mutual assistance
crews in the early days waiting to do the work,
but we can't effectively rely on that
workforce if we don't know where to send them. If we send a
construction crew somewhere where a smaller crew could do the work, we're ineffectively
using that workforce. So I'm happy to report that
by the end of the day yesterday, we're 85% complete with that damage assessment work.
We'll finish it today. And we are restoring customers
actively with our mutual assistance crews. You see
on the next page some of the staging sites.
You see the dots on the map, exactly where those staging sites are.
Commissioner Glotfield, he mentioned he came to a staging site on Tuesday, the day after
the storm. That is where we do our initial
intake of crews that are coming onto our system.
It's where they get safety briefings. It's where they learn about different
design specifications for the work that they're going to be doing.
Things like how much clearance
on a roadway crossing do they need to do to comply with local
or state regulations? Right. They're coming in from out of state. They're not used to
working on our system, so we brief them on all of that. This is where
they come every evening when they're done with work, park their
trucks, get their food, get bused to a
hotel. The next day they're bused back to that staging site,
they get their food for the day, they get their work plans, and they exit.
So these staging sites are fairly significant logistical hubs.
We had the initial staging site set up less than half a day,
or about half a day after the storm cleared our system. So a lot of
work goes into putting those together. You can't put them together before
the storm hits. Right. So the big tents where crews
get briefings and get their food can't be put up before the
hurricane. So you see a lot of that activity, right, in those early
hours after the storm leaves.
On the next page, you see just a
list of our significant mutual assistance crews. I wanted you
to have the names of those companies. We're very thankful that they
send their men and women to help the greater
Houston area. Finally, let me get into restoration stats.
You see that on page eight. So as
of today, we have restored more
than 50% of the outages. So we've restored
about 1.2 million homes and businesses.
There's a little over 1 million homes and businesses
left to be restored. So I
like to rely on data as a good way to
judge readiness. We have never restored more
than a million customers a little over two days after a
hurricane before. And you can only do that with significant
readiness. We know we still have a lot of work to
do. We communicated to our customers last night.
We expect to have another 400,000 customers on by the end
of the day tomorrow. We expect to
have another 350,000 customers on, on by
the end of the day on Sunday. That takes you to
about 80% restoration by the end
of the weekend. We continue to assess
our workforce needs. If we believe that
we can effectively onboard additional crews in
order to speed up the work, we will.
That leaves about 500,000 customers that we currently
expect to have outages that go into next
week. We issued a communication to customers
today that said that by noon we
will start providing estimated restoration times for those customers
that are going to have outages that go into next week.
We will update those estimated restoration times
as we get better information on what those customers
should expect.
Let me talk a little bit about communications with our customers.
We did, as of the end of the day yesterday,
27 media interviews.
We had 72 social media posts keeping customers
advised of the work that we were doing, the process
that we were going through, where they
were in the process, in an outage map that
we posted. Are you in the assessment phase? Are you
in the phase where your outage is being assigned to accrue
for that work? We also encouraged
customers to sign up for our power alert service so that they could
personally get these estimated restoration times when we push
them out by either phone call, text or
email so they're no longer relying on just press
releases to understand when their estimated
restoration times are.
So again, we know
that some of the hardest hit areas are along the
coast and up the I 45
corridor, up to the Woodlands. So we will be communicating to
customers so they have situational awareness as we go into next week
where they are with that estimated restoration time in
the spirit of continuous improvement. We always do. After action
reviews, we have started to document
our lessons learned and I'm happy to talk
about that either today, Orlando, as this process continues.
I know, Chairman Gleason, this is not the first and last time we'll have this
discussion, but know that we
are undertaking that process as we speak and we will do a full after action
review at the end. Let me go ahead
and close again by acknowledging to the customers
that are out as we speak and especially to those customers that
will have outages for an extended period of time past
this weekend. We know we have a lot of work to do. Our crews
are working around the clock, 16 hours work shifts.
We will continue to assess whether or not we have the right number of
crews and whether we should bring additional ones in. And we will not
stop our work until the work is done.
(item:A: Commissioner's Questions to Jason Ryan, CenterPoint, Beryl, 56793) Thanks, Jason. Just before questions, just made one comment.
At the outset, you talked about rebuilding the infrastructure,
rebuilding the community. I'd say a third leg
of that stool is rebuilding trust a little bit. And I think that really
starts with effective communication. You touched a little on communication.
As I've thought about this. I would strenuously urge you all to
get out. Once everything is restored, get out into the community.
I don't know if that's town halls or what it looks like,
but go talk to your customers. Go talk to those residents about
what happened, about, you know, ways that you feel you all can improve.
Get feedback from them about their view on what
can be improved. I think that will make the next time that there's a storm,
make this go a lot better, because as we learned at this commission,
you know, after Yuri, communication is the key
to everything. I mean, you know, the infrastructure is going to break. Things are going
to happen, but if people feel they're being effectively communicated
with, it makes it a lot easier to go
through it. And so I'd say get out in the community and go talk to
your customers. I appreciate that. We're fully supportive of that.
And we'll make sure we coordinate with your office so you know what we're doing.
Thank you, commissioners. Yeah, Jason.
So you laid out the statistics that I've been asking for from the
other companies, and essentially what you're saying is that you
still have over 50% of the power outages out right
now when you provided a timeline through the end of the weekend, about half a
million extending into next week. Constant communication with
them, I think is important, as you've laid out, y'all are doing so they can
plan accordingly to get to a safe place if
they need to. And so what
are some of the reasons why that you're seeing, based on
your damage assessments, that it's taking longer to get to these half a
million customers? So those are in
areas where we are having to rebuild the infrastructure.
So in areas where it's removing
debris on the distribution system, what I mean by that is largely
vegetation, trees,
limbs, some in the right of way, some outside the right of
way. Commissioner, I will request that our folks keep good records on
what's what so that we can give order of magnitude where that was.
That is the kind of restoration that we will accomplish
by the end of this weekend, where we have to rebuild
large spans of infrastructure with
poles that snapped in half laying on the ground. You've got
a couple pictures of that kind of damage. That is
the kind of work that's going to lead to those extended
power outages. So as we,
again, as we continue to assess
our workforce needs and whether or not we
need to bring more people in. We will accelerate those
estimated restoration times, and we're going to start
communicating with customers today that are going to experience those
extended outages. Based on your review of your pre hurricane
inventory for materials and equipment, do you think that you have enough
equipment and materials to rebuild this infrastructure?
We do. The one thing,
and I know we're working with Tietum on this as of this morning, we want
to make sure we have sufficient diesel fuel for our emergency
generation because we expect this
extended outages in certain areas.
I don't want to say that we have a concern about it right now because
we are working through the appropriate channels there as we,
we don't have any material concerns. There's that fuel
concern that we're working through. But certainly, as we have
any unmet needs, we will work with our mutual assistant partners
and through state and federal channels to make sure those
unmet needs get met. Okay. With respect to the fuel
concerns, is there anything that can be done by
the commission, anything that can help you get
those resources so we're working the right channels. If we end up with some roadblocks,
we'll be back in touch with your office for sure. Fantastic. And back to the
mobile DG discussion. So I understand.
How many mobile DG units do you all have?
So we have 17 large ones. And what I mean
by that is either 30 megawatt or five
megawatt units. Those are best used
during load shed, but we are looking for
opportunities to use those units to pick up
parts of circuits where there may
still be damage going up to the substation. But you can mid
circuit and pick homes up. So as we
make progress on our restoration work, we will continue
to look for opportunities to use those mid circuit.
We then have more than a dozen smaller units,
two and a half megawatt units.
1. We have a vendor that allows
us to bulk up on that on a
temporary basis when we need them for storms like this, so that those smaller units
aren't just sitting in a yard somewhere. So we are working
with that vendor. As we identify homes
or businesses or critical facilities that can use those
smaller units, we will bulk up as the
need requires. We have also requested,
through mutual assistance, some additional generation.
So we've got sufficient generation for
the needs that have been identified so far. We continue to work
with critical facilities like water facilities
to avoid boil water notices. You know,
a lot of facilities like that that are critical have
their own backup generation,
but in extended outages, we have to be concerned about whether that
backup generation will be sufficient to power through the entire
event. So we're working very closely with those critical facilities,
working very closely with our government officials to make
sure that we're aware of what the status is of
any generation that they may have as backup for those facilities
that they're concerned about. I have
members of my team embedded in the emergency operations centers of many
cities and many counties right now, so that the information flow
in that regard is seamless. We have a
priority desk in our emergency operations center
that exists solely to take those
kinds of requests and work them. Whether we can accelerate
restoration of our facilities, if there's
a concern about those backup generation facilities
failing, or whether or not we can use our own
backup generation to go and augment what they have.
So, Jason, you mentioned the large ones can only be used when there's load shed.
Per the commission's rules. Are the twelve smaller ones subject
to the same? So it's not really rule
based, commissioner. It's really more just that a 30 megawatt
unit is more likely to be useful at a substation to
pick up entire circuits during load shed.
When there's damage on those circuits from a storm like this,
they are less useful in that scenario. But again,
we look to make sure that we can utilize all of our assets.
So if this storm, which didn't happen
this time, if this storm had caused
significant transmission level damage
and left substations without power,
but circuits that could take power,
that's when these 30 megawatt units could be used in a storm scenario,
that's not this storm. Okay. Yeah. I just asked because,
you know, there's a lot of frustration, as you said, and there's
a lot of discussion about out there, about the mobile gen units that your company
has, like 30 of them. I think it's going to be really important to
really explain, you know, why you
can't use some of them right now. When you deployed
the mobile gen units, it sounds like based on your damage assessments of
where strategically you can actually use them. But I think it's
going to be really important to provide that information in the after action report,
as you know, the issues with not
being able to use all of them when
they were deployed, where they were deployed, and,
you know, it's all in your presentation that amongst the critical care customers,
there's education centers. Did I read that correctly?
That's correct. So we have,
even though school is out, you have some facilities that
might be serving as daycares in the community or
providing other services in the community.
So we are looking at how
to lessen the impact on the community of power outages
and how to get the community back to normal quicker.
And so opening up facilities like that that provide those
kinds of services are critically important as well.
Jason, just real quick on a follow up to the mobile gen comments. So if
some of your units aren't really made for something like this,
can you, through mutual assistance, use other
tdus mobile gen units? Yes, sir. Did you do that in this case?
We did that in the May de Racho, and we've done it here, too,
I believe. I don't know how many encore has sent, but we have
asked for mutual assistance from Encore. In that regard. I think it would be
helpful, as you're showing where you located these,
to differentiate between your assets and then encore's assets
would be helpful. We'll do.
You mentioned the water districts. Sorry, Jimmy.
As the length of time prolongs, if they did have their own generation,
do they then contact you? Do you reach out? Cause I think after Directo was
some miscommunication. Has that gap been filled from your side?
Yes. So some are reaching out to us. We are also proactively reaching
out. So we have a way for
our local governments, water districts
included, to submit to us proactively
their critical facilities. That list
is long. And so in a storm like this, we keep track
of which of those critical facilities has
power, which one doesn't. As you could imagine, oftentimes when
they don't have power and they proactively call us,
we are also proactively reaching out to them. And like
I said, we've got people embedded in all of the local
emergency operations centers, and that's where that information can bubble up
as well. I won't say that the gap is perfectly closed,
but we're in active communication with that group
of customers.
Hi, Jason. Good morning, commissioner.
A couple things. First of all,
again, I think a lot of this is after
action. Like when we're looking back, how do we make sure that this is
better next time? I know the lieutenant governor, the governor,
the mayor have all, they're all going to be able to
voice their views to you all. There's a lot of displeasure in
west Houston and east Houston and in north Houston,
and I'm not,
you know, I think that comes with the territory, so to speak.
It's hard to plan for these when you don't know if they're coming,
and it's expensive if you plan for them and they
don't come, it's expensive for right payers.
What I hope you all can do on a hurricane
like this one is,
I don't understand how you get, how you ensure you have
the right mix of vegetation management folks versus linemen.
It's great to say we have 10,000 linemen, but if you need 10,000 vegetation
management folks and $5,000, 5000 linemen,
it'd be great to try to understand that in the context of a storm
like this, with all of this vegetation challenge as
we go forward to think about that, is that the
right mix? Might be, might not be, but I'd
like to explore that with you all. Yes, sir. Fully support
that. So the other one is Mark,
Stellen county. As we go through this, the one thing that
we cannot lose sight of is the fact
that these linemen are people and that I
haven't heard of a single incident, at least a death,
which would tell me that that's a good
thing. If we get through this storm and
the restoration with maybe 20,000
additional people touching the system every single
day for a week and a half or two weeks, we are
actually very blessed that nobody has an incident. And we
need to keep that in mind. And I think as we write up our report
and our story to the legislature, the human life toll that
the storm took is important, but also on the restoration because they're the ones who
are climbing the poles every day.
So if you have incidents on that or you have ideas or
thoughts on how to include that, how you can do safety briefings better
or how they've worked versus other utilities, I think all of that is important
in our after action report. Yes, sir. We'll work with your
office and staff on that as well. You know, again, I know customers
are frustrated at how long it may take,
especially in these prolonged outage areas. Safety is
our top priority. As you mentioned, these men and
women are working 16 hours shifts. It's important that they take the other
eight to rest because these are dangerous
conditions. It's hot out there. That's a
safety issue as well. A lot of these crews don't come from places where
it feels like 110 degrees. So if
our customers see crews standing on the side of
the road or in their trucks, it may be to cool
off, take break, stay safe. That's what we stress with
these crews that come in from, not the Gulf coast area,
to make sure that we can end this event with no serious
injuries or fatalities.
Certainly want to make sure that people get their power on as quickly
as possible. And you talked about about a half a million people
would go into next week any
idea geographically, where that is? Is it across the surface area
or is it in specific areas?
So some of the harder hit areas are
the Magorda County,
Brazoria county, parts of Galveston county where
the storm originally came ashore with
those high sustained winds that went
across the I 45 corridor or up the I 45
corridor. Once you get kind of inside the loop, I have a
map that I'm happy to share with you that shows that.
And that is going to be how we communicate
these estimated restoration times with customers. If they're in these particular
harder hit areas, they're going to be out the longest.
Most likely there will be small pockets
throughout the 5000 sq mi of our service territory that have
some prolonged outages. But the
vast majority of them are going to be in those areas that I just described.
So in terms of restoration, and again, going back
and doing the after action report, one of the things that
I'd be interested and you talked about how we have to get in and do
the assessment first. Right. But obviously
we're doing, I would think, many assessments.
And so, you know, what is that process in terms of,
you know, how do we carve out the service area to determine,
you know, how many assessments we should be doing at one time and then,
or progressively, and then as soon as that part of the assessment is
done, being able to get in and actually start the restoration work.
So a little bit more detail on the process and if there
is opportunities there, you know, for continuous
improvement. Yes, ma'am. And I also think that,
again, going back to the communication, we can
communicate earlier with our customers in advance of these storms,
the process that we'll use so that they understand it a bit
more. We have a process that we use.
We implemented our plans. That's what allowed us to achieve
50% restoration within two
days after the storm. But we can do better to communicate customers
for what they should expect to see and expect to not see.
That assessment is critically important to be done
to effectively use our crews, but it has added
some confusion by our customers of what
it is that we're doing when they don't see crews actively working because they're
waiting on those assessments to be completed. So that is part of the better
communication that we can do with our customers so they know what to expect.
When Hurricane Ike was the last major hurricane to hit our system
from a wind event hurricane, that was in 2008,
more than 15 years ago. And our service territory has grown a
lot, population wise, since then.
So we need to take that into account in terms of how we communicate and
to make sure that we're clearly explaining to customers what they should expect,
especially in the early days when
there are still so many customers out. I think people can accommodate
just about anything if they know what's going on. And so,
so important that we talk about the types of communication that
you're addressing as well as that ongoing real
time communication that's available through the
tracker, which I know you're working on as well. Agreed.
Thank you. Yeah, I'd say, I mean, you know, we've been fortunate. Like you
said, we had Harvey in before that we haven't had anything since then.
But, you know, and I think as we had discussed, you know, using the same
kind of playbook for communications, probably outdated. You know,
folks, the public expects more communication,
more frequent communication, different modes of communication. And so I think
it's definitely incumbent on all of us to look at the way we communicate going
forward because this commission,
the governor, legislative leadership, the speaker
and the lieutenant governor expect improvements in all of this. And I know
the residents deserve and demand it.
We'll be working very closely with you and all the utilities and other folks
that we can help bring their expertise and understanding to bear to make
sure that we help mitigate the impact of future storms like this.
Yes, sir. Anything else for Jason? Thank you,
Jason. Thanks for being here.
So I'd say to all the companies, reiterate those thanks
to the line workers and those crews, both from Texas and those that came
in from other states for their efforts in restoring the
system as quickly as possible. And I'd also be remiss if
I didn't thank all the folks at the state operations center. That's our staff,
that's all the staff from the utilities, from other sister agencies
that have been working 24 hours shifts since last weekend
or maybe even before to prepare for this.
And so we thank them for all their efforts as well.
Mister chairman, I have one thing to say, and that is each
utility service territory in the state of Texas has its
own unique weather challenges. And we've seen
hurricanes, we've seen fires, we've seen other
types of tornadoes and other things that affect the
citizens of Texas in a similar way, but a different
type of event. You know, I think about this in terms of
the fires up in the panhandle, and I
hope that as we are looking at this event, we can maybe put
in place some kind of structure that we can look at all of those events.
I think all of the citizens kind of understand, you know, deserve that.
If we're looking into something that's causing havoc, wreaking havoc
on the Gulf coast that in other parts of the state they get the same
benefit. Absolutely. You know, we'll have to address kind of
the acute onset issues that this brought forth.
I think a comprehensive look at all the different types of issues that
different tdus deal with in various areas of the state is well
worth our time. Thank you. Okay.
All right, so now we'll move on to the agenda. So,
like I said, we're going to take up item number 19 1st. But before
that, Sheila, will you take us through the consent agenda and the
recusal list, which for the first time, I do not lead.
I'm not the leader in the clubhouse on the number of recusals.
Good morning. Commissioners recusal memos were filed in project
number 52761. The chairman
is recused from items 18 and 19, and commissioner Yaltman is
recused from items 816,
1819, and 24 through 27.
By individual ballot, the following items are placed on your
consent agenda. Items 13, 11,
13, 14, 17, 23,
24, and 26, and also by individual ballot,
the commissioners voted to place items on the consent agenda for the
rolls and project section. No one signed up to speak on those items,
and so the commissioner is voted to also place items
39 and 42 on the consent agenda. Thank you,
Sheila. I'd entertain a motion to approve the consent agenda as described
by Sheila. So moved. Aye. Second. I have a motion. A second. All those in
favor say aye. Opposed. Motion prevails.
So item 19 I am recused from. So I will turn
the meeting over to Commissioner Kobos. All right, thanks,
chair Gleason. Sheila, can you please lay out item number 19?
(item:19:Sheila lays out Docket 54657) Yes, ma'am. Item 19 is docket number
54657. This is the application of the
city of Lubbock, acting by and through Lubbock power and light to change
rates for wholesale transmission service. Before you is a
SOA proposal for decision. Lubbock power and Light and the
Office of Public Utility, council and commission staff each filed exceptions
to the PFD. The SOA ALJ filed a letter in response to
the exceptions and did not recommend any changes to the PFD. The commission voted
to grant oral argument in this docket, and commissioner Copas
filed a memo in the Stockholm. Thank you, Sheila. Before we move
forward with laying out the party's oral argument,
I would like to recognize city councilman from district number six in
Lubbock, Tim Collins, who's here with us today.
Thank you for being here.
And various members of the Lubbock Power and Light board
of directors. So as my memo lays out,
I voted to hear oral argument in this case. I propose that we give
each party ten minutes to provide their arguments, and that
given the complexity of the issues in this case,
that my preference would be to defer the ultimate decision on this case to a
future open, open meeting date.
Are you good with this path forward, Commissioner Jackson? Yes, I am.
Okay, great. Sheila, can you please call up the parties?
Yes, ma'am. And for this, for oral arguments
for both Lubbock and. I'll just. I'll just preview this for SP's
as well. We're going to do this a little bit differently. Rather than calling up
the parties individually, we're going to have all the parties come up at once just
for a more efficient way of conducting oral argument.
So at this time, will the representatives for OPUC,
LPNL and commission staff come up? And just for
order of oral argument, under our procedural rules, the party
that bears the burden of proof can open
and close the argument. So we will start with the applicant,
followed by OPUC and then commission staff in order for oral
arguments.
All right, so we will
start with Lubbock power and light, if possible. Chairman and commissioners,
I'd like to reserve three minutes for rebuttal.
Sorry, Rosalind Duberstein, on behalf of Lubbock power and light.
Yeah, we won't have rebuttal. We're just giving ten minutes for all argument.
Okay, thank you. Commissioner,
is it possible to close per the commission's rules?
Yes. So, under our procedural rules, the party with burden
of proof is allowed to both open and close.
And so with the presiding
officers permission, would you be reserving
time at the tail end of that for that? Yes, that's fine. All right.
(item:19:Rosalind Duberstein, LP&L, 54657) Thank you, commissioner. Good morning. Chairman and commissioners.
Rosalind Duberstein, counsel for Lubbock power and light. On several
issues presented in this proceeding, the ALJ reached correct conclusions supported
by the evidence. However, the PFD's recommendation regarding the debt
service coverage ratio used to calculate the return is incorrect
and unreasonable. In its application, LPNL requested
a 1.5 debt service coverage, or DSC ratio, to calculate the
rate of return. This request is lower than LPNL's
current commission approved DSC ratio of 1.75.
A 1.5 DSC ratio is supported by the record evidence,
specifically by LPNL's bond covenants, and by the criteria of
the RFP. Despite this, the ALJ recommends limiting
LP's DSC ratio to 1.25.
The most crucial takeaway I have for you today is that a
1.25 DSC ratio will create severe
financial risk for LP and L and will cause LP and L to
operate at a loss. A 1.25 DSC ratio
is the minimum required by LPNL's bond covenants.
Use of this minimum to calculate the return would
provide no room for error. It would put LPNL
at risk of violating its bond covenants and incurring a
credit rating downgrade. This would jeopardize LPNL's
ability to borrow in the future and to continue contributing
to transmission build out in Texas. Like any MoU,
LP and L needs sufficient return dollars or margin over
and above its actual operating expenses to meet its debt service needs.
This is taken directly from staff's testimony in this case,
and it is widely known as a fundamental standard for
determining the appropriate rate of return for an MoU.
In fact, the PFD emphasizes this fundamental standard and
then contradicts itself by recommending a DSC ratio that
would be insufficient to cover LPNL's debt service costs and its
O and M by $3.4 million.
LPNL outlines this calculation and its exceptions.
This $3.4 million deficit based purely on
an inability to cover debt service and O and M does
not meet the fundamental standard for an appropriate rate of return.
Adopting a 1.25 DSC ratio will put put only more of a
penalty on Lubbock customers than they already bear
with that 3.4 million necessary to maintain transmission assets.
The ALJ also erred in not applying a 0.25 adder
to the DSC ratio. The RFP permits a
0.25 adder if a utility can show the cost effective
utilization of short term debt as a reasonable alternative to
long term financing. Since its last TCOSP proceeding,
LPNL's use of a form of short term debt saved transmission
ratepayers $3 million in debt service. No party
disputes this key fact. The ALJ focuses on
the conversion from short term to long term to disallow the adder,
but that conversion was the strategic utilization of short term debt.
It resulted in cost savings, and that would not have been possible but for
the short term debt. This evidence, in combination
with the financial insufficiency of the ALJ's DSC,
is an unreasonable and financially harmful result
for LP and L. As you know, the opportunity for an
adder is a recent revision to the RFP and a deviation from
many years of precedent where a 0.25 adder was presumed reasonable for
mous. LPNL has presented sufficient evidence to meet
the criteria of the adder in the most up to date RFP however,
if the commission finds LPNL's cost effective use of a short term debt alternative
does not satisfy that criteria, it begs the question,
what will qualify for the adder? The RFP change has far
reaching implications for mous and may warrant clarification.
As a final and crucial point, LPNL's projected $3.4
million deficit does not include the hold harmless credit required
by the settlement in docket number 47576.
Staff and OPEC's focus on that credit is a red herring.
The claim that LPNL's requested DSC ratio is based on
the credit is blatantly false. As opux witness specifically
conceded in testimony, the hold harmless credit is not included
in LPNL's requested tcoss. In this case, the hold harmless
credit is not and has never been funded out of tcos revenues.
The credit is only paid by LPNL's native load customers
in Lubbock. Here are the key facts for the
hold harmless credit. LP and L has been paying it in compliance
with the settlement. This is easily verifiable.
LPNL has never recovered that credit in tcost and it is
not proposing to do so in this docket. This is equally
verifiable in the last commission approved tcoas rates and
the rates requested in this proceeding. Discussion of the hold harmless
credit in the application has been misconstrued throughout this proceeding.
The concern that's mentioned in LPNL's direct testimony is not
that the hold harmless credit is in any way recovered through TCOS rates.
The concern is that LPNL does not have if LPNL,
excuse me, does not have tcos rates that are based on a
sufficient DSC ratio, then its retail customers
will be forced to subsidize subsidize. But those same customers are
already funding the hold harmless. This will increase the penalty
those customers already have to pay. LPNL respectfully urges
the commission to evaluate these verifiable facts regarding the hold harmless
credit and approve an appropriate DSC ratio that will
not impose this deficit on LP and L. I will
note that there are additional concerns about the consequences of this decision,
which are addressed in the letter from the chair of LPNL's board, Gwen Stafford.
It was filed in the stock in on June 10 and in summary,
LPNL contends that adopting the 1.5 DSC ratio that's
substantiated in the application is a reasonable outcome. It will
give LP and l appropriate financial protection and will not impose unfair costs
on transmission ratepayers. LPNL respectfully asks the
commission to reject the ALJ's DSC recommendation
and instead approve a ratio that will not risk LPNL's financial
stability or harm its retail customers. I'm available
for questions and I have representatives from LPNL here with me today as
well. Thank you.
All right, let me pause for just a moment and record. You'll have three minutes
and 335. Thank you. All right,
the next party that senator speak is the office of Public Utility Council.
If you'll state your name for the record, please. Good morning commissioners.
(item:19:Julie Davis, OPUC, 54657) Julie Davis, special counsel with the Office of Public Utility Council.
I'll keep my comments brief. I have two points that I'd
like to address. The first, speaking to the debt service coverage ratio, we agree
with the ALJ that the 1.25 is appropriate.
I believe we and staff are aligned on this. The direct testimony of Mister Harvey
hall clearly identifies the hold harmless payment as a category of debt.
And despite what council would have you think, our statement continues.
While we admit that the hold harmless payment is not a specific line
item in the requested revenue requirement, LPNL is requesting
a DSE of 1.5 to provide sufficient revenues to meet the cash
obligation that the hold harmless payment supposedly
is included in. So we do believe that that hold harmless payment
is being a basis for that debt, and we think that's inappropriate to make
the recipients of a benefit pay for that benefit.
This was a condition of settlement and docket number 47576
and we believe that the commission's decision in this case, along with the
ALJ, should uphold that settlement as it is.
Further, the ALJ's recommendation in the PFD won't cause a
perverse use of short term debt by other agencies, as LPNL would have everyone
think. The rate filing package clearly requires a
showing that the debt was a reasonable alternative to long term financing,
and while we don't contest that at the time it was, it no longer is
being used as that. Utilities that use short term debt
as a mechanism to simply achieve a higher DSE ratio will
not be in a difficult position to prove that that funding was reasonable.
Adopting LPNL's position in this case would mean that
any utility that has ever used short term debt could argue for the
additional 0.25%, which undercuts the change
to that policy. The second point I'd like to make
goes to the ALJ's recommendations regarding the recovery of
pilot in this case. We disagree with the ALJ on that point, and I'd like
to speak a bit to that. Generally, the law does recognize
allowances for mous like LPNL to collect general fund transfers,
but unlike the other cases LPNL relies on in its briefing, the LJ
found that public Utility Regulatory act section 35.009
instead applies in this case, and that's because LPNL is required to have
a CCN for transmission facilities in ERCOT.
This section creates a specific condition when mous can recover payments
in lieu of taxes, just as some background those pilot fees
compensate municipalities for property tax revenue they otherwise can't
collect from an entity due to some tax exempt status.
35.009 says in relevant part that Maus can recover pilot
fees it pays to cities through wholesale taxes, unless their governing
body is also the governing body of that taxing entity. And in this case,
it's undisputed that LPNL is governed by the city of Lubbock.
The ALJ's recognize that LPNL's governing body is the governing
body of that taxing entity. However, determine the
outcome, which is the natural occurrence of this statute would be absurd
because it does exactly what it's designed to do. We recognize that
change is difficult in this, LPNL's first rodeo on this,
but this is the natural result of applying that statute.
So this argument really turns on whether or not the absurdity doctrine is being
properly applied. And we argue that case law, not only from the United
States Supreme Court, but the Texas Supreme Court, weighs in favor of finding that
the absurdity doctrine should not apply in this case.
The absurdity doctrine itself sets a high bar to counter the natural
outcome of legislation that, while inconvenient, broad, or even unattended, is nonetheless
clear. Further, the ALJ found that no ambiguity
in the statute existed, and LPNL did not argue that such an ambiguity existed.
As a result, this may be an unanticipated outcome,
particularly at the time the statute was passed, but it is the application
of law, and we would caution the commission from
reading into the statute rules or words that do
not exist that would change its meaning.
So we urge the commission to find that this pilot should not be
recovered and should also be removed from the cash working capital.
I'll conclude my statements there, but I'm happy to take any questions. Thank you.
All right, the last party to Senate for oral argument is commissioned staff.
Will you state your name for the record? Yes.
(item:19:Andrew Aus, Comission Staff, 54657) Andy Ous for commission staff. Good morning,
chairman and commissioners. My name is Andy Aus. I am a one of the attorneys
who had the pleasure to work on this very complex and important docket for commission
staff. Just by way of introduction.
I went to tech for law school, so I did spend three
years in Lubbock. I think it's a great city with even better people.
But staff does find themselves at odds with
LPNL and Lubbock regarding a couple of issues with this
docket. You've already heard both parties before
me talk about the debt service coverage ratio. I'll talk about
that first, with the hold harmless payment being up.
I'll mention the hold harmless payment first and then move into the short term
debt issue afterwards. And then I will touch briefly on the
assignment of debt to transmission function, that is
before the commission today. With regard to the hold harmless
payment agreed upon in docket number 47,576,
the company stated that it needs the additional 25 x coverage in order to
recover the 22 million a year payment. It pays
for the hold harmless payment and accordingly, this was the reason why LP
and L requested a 1.5 x dsc ratio
because this payment was an integral part of the commission order in docket number 47576.
The hold harness payment is in no way a cost of LP
providing transmission service. It is a payment to ERCOT
transmission customers to mitigate the increased cost those customers would face
as a result of LP and L transferring load into the ERCOT system.
Accordingly, the hold harmless payment should not be used as a justification for
LP and L to increase rates for the very customers it
agreed to hold harmless. Moving on to the short term debt
issue for the debt service coverage ratio,
we believe that the SOA ALJ's decision in the PFD
regarding the treatment of short term debt is correct. LP and L and
there are exceptions to the proposal for the decision, states that by adopting
the rule as set forth in the PFD, it would create an artificial
requirement that every MoU always must employ a short
term debt during the test year to qualify for the 0.25
x adder staff does not agree with this assessment.
Staff evaluates an MoU's use of short term debt and whether the MoU
utilized such debt prudently and in cost effective manner
during the test year. LPNL's direct revolving note program,
otherwise known as DRNP, which staff agrees was short term debt,
ended in August of 2021. If LPNL is
allowed to rely on past instances of prudent short term debt use,
LPNL is effectively arguable that any past non current short
term debt should allow an MoU to qualify for this 0.25
x adder. Staff again reiterates that a 1.25 x DSC
ratio leaves LP with the ability to cover 100% of
its debts while maintaining a 25% cushion,
simply because LPNL's bond covenants require a
1.25 DSC ratio does not mean that LPNL
lacks a financial cushion. A DSC ratio of of 1.25 x
would allow LPL to cover more than 100% of its debts.
In other words, the 25% cushion is already contemplated here.
LPNL next argues that by adopting a 1.25 DSC
ratio, it will be forced to operate at a loss staff know. So the
result of this rate proceeding will be a commission authorized revenue requirement and the
LPNL, and that LPNL has a number of tools available,
including the filing of interim tcost proceedings up to two times per year,
that would allow to adjust and timely recover transmission costs.
I'm going to move on briefly to another issue before the
commission for consideration, and that is the assignment of debt to the
transmission function. Specifically in this case,
staff respectfully disagrees with the SOA ALJ regarding the decision
to allow LPNL to assign higher cost debt service to
the transmission function, which would result in different rates of
for different utility functions. The PFD misapplies the burden of
proof, resulting in a proposal that violates pura 35.004
A and 16 TAC section 25 192 C,
and it would interfere with the competitive market and conflicts with commission's
rate filing package. A. Utilities financing cost is a system
wide cost properly applied on a total company basis when setting
rates, and neither LPNL nor the PFD cites to any exception
to this practice. It is undisputed that LPNL's debt obligations,
which consist of general obligation and revenue bonds, are financing
cost for the LPNL system as a whole, with these bonds
being backed by LPNL revenues from any source in the LPNL system,
not just revenues originating either from transmission or from distribution
services. LPNL's debt issuances are still
backed by the revenues from its entire system. They are system wide cost and
the cost of repayment cannot reasonably be associated with any single function
as LPNL and the PFD propose. Pura section 35004
A requires a utility to provide wholesale transmission service
at rates comparable to its own use of its system. By allowing
LPNL to assign higher cost debt to the transmission function and lower cost
debt to the distribution function. LPNL's transmission service customers
across ERCOT would be burdened by rates that are based on a higher
rate of return than rates for LPNL's distribution customers.
The effects of this is to inappropriately and inequitably shift the
system wide financing costs from LPNL's local distribution
customers onto all other customers in the ERCOT system,
which is unreasonably discriminatory on its face because LPNL,
acting as a distribution service provider, essentially pays itself
for the transmission service it receives from LPNL acting as
a transmission service provider. Using the LPNL system,
rate of return for transmission and distribution service, as recommended
by staff, produces a wholesale transmission rate for LPNL that
are comparable to the LPNL's own use of its system, as the same
overall rate of return is applied for both transmission and
distribution services. Further, of note, many tsps are
non opt in entities that own and operate generation resources
in the competitive wholesale market. Adopting the precedent proposed in the PFD
would open the door to allowing these entities to shift the higher cost of financing
associated with the generation resources into regulated transmission rates,
effectively subsidizing their competitive operations through
their regulated rates. Such an outcome would clearly harm
competitive generation providers who have no captive customers to
shift cost onto and theme, and it would impair
the healthy functioning of the wholesale market as a whole. If adopted,
the PFD proposal might also open the door to allowing investor owned
utilities to assign higher cost equity financing to transmission
customers outside of their distribution footprint. This could result in an entire
new avenue of disputes as parties review and litigate the financing
situation associated with each and every utility project,
a burdensome and I contentious process that is unnecessary
if these financing costs are properly recognized and treated
as the system wide cost that they are. And with that,
I thank you for your time.
Give me just a moment.
Are you ready? All right. Roslyn Duberstein,
LPNL I'll start with the assignment of debt. In responding to
that issue, staff has not relied on any precedent or citation for
the total company basis rationale, and the ALJ correctly acknowledged
this. Whereas LPNL's direct assignment of the transmission
debt to the transmission function correlates to the projects that the debt
has funded. This is in line with direct assignment
and the cost causation principles that are outlined in the RFP and
generally accepted in rate making commission staff
makes the claim that LPNL is assigning higher cost debt to the transmission function.
This is plainly incorrect. The evidence has shown that the 2.76
interest rate that's assigned to the transmission function for the test year
is actually lower cost of debt than LPNL's last five issuances
since 2014, and that is available in the record evidence.
LPNL cannot selectively assign higher cost
debt. ERCOT must issue debt when their larger infrastructure
projects and capital needs are present. I'll move on
to the pilot issue raised by OPEC.
If the commission were to find against the ALJ
on this issue, it would overturn a longstanding practice
of ERCOT, including a pilot transfer in their TCR rates.
While the legislative history is of course not binding, it is highly
informative in this situation. It shows that
this was designed to be a completely separate taxing jurisdiction
and that it's for projects that are outside of the city limits.
This would be an overhaul of the types of
transfers that have been routinely included in TCR
rates, and an application of a statute that we've never seen before.
I will say that the ALJ, and in a different recent
TCR proceeding 52715 found
against this argument and that the commission affirmed that decision.
Also, OPEC's witness in this case has historically promoted
the inclusion of pilot even after this legislation was enacted. So I think
the position seems inconsistent, consistent with precedent and the routine
inclusion of pilot in TCR rates. Finally, on the debt service
coverage ratio,
the hold harmless credit is a consideration in the overall finances
for LPNL for both its retail customers and its TCR.
It is not the basis for the DSC ratio.
Request 1.25 is the minimum required
by the bond covenants, and if LPNL has
any error or anything that slips up, they risk violating
those bond covenants. That is the number one rationale.
The adder is supported by the short term debt, as I
mentioned earlier.
Excuse me, sorry. As I mentioned earlier,
it may warrant some clarification as to the recent RFP change
because LPNL has shown that they've used short
term debt and they've done so in a cost effective manner. No party
has disputed this fact. So it is unclear how that is not a
reasonable and cost effective use of short term debt. It is inherently
in lieu of long term debt because LPNL specifically utilized
short term debt at that time instead of long term financing.
I would also say that staffs argument with regard to
maybe limiting the short term debt to use during the test year or
any other timeliness limitation. There's no such thing in the language of the
RFP that's reading in something that is not there,
and they have conceded that
it was the cost effective use of short term debt. So we
would ask the commission not to impose any test year
time requirements when they do not exist in the RFP.
That's not in line with the general financing that would
be required. There's an overall financing strategy
over the course of many years. It couldn't possibly be limited. So we ask that
you grant the 1.5. Thank you.
All right, that concludes oral arguments. Okay.
And I would request that we defer decision to
future open meeting. Y'all are good with that?
Yes. All right, thank you all.
So, Sheila, it is 1128 and 32 seconds.
So I think that's all we're going to get through before we meet
with the attorney general at 1130. So like
I said at the outset, we have a time certain to meet with our outside
attorneys at 1130, and then we'll take a lunch.
So what we'll do is we'll convene our closed session,
then come back out and start the open meeting back
up, but not take. Not start back up on the contested case
docket until 01:00 time certain. Does that work for everybody?
Okay, then. Having convened a duly noticed
open meeting, the commission will now, at 11:29 a.m.
on July 11, 2024, hold a closed session pursuant
to chapter 551 of Texas Government Code.
It will consult with its attorney pursuant to section 551.071
of the Code, deliberate personnel matters pursuant to section 551.074
of the Code, and deliberate security matters pursuant to section 551.076
of the Code. We'll be back at 01:00 okay,
we will reconvene our open meeting at 01:05
p.m. so just a bit of procedural
stuff to cover. We have some folks
that want to comment on item number number 16.
So I'm going to take that out of order so we can hear from them
and then deliberate that docket so they don't have to sit here
the rest of the time. And then because we grant oral
argument on the SP's case, and we are going
to give them 15 minutes, I'm going to take that up at the end of
the contested case dockets. End of the contested case dockets. Got it.
Okay. All right. Sheila, will you call up
item number 14, please? Item number 16, please.
(item:16: Sheila lays out Docket 56354) Yes, sir. Item 16 is ducat number 56354.
This is the application of undying, LLC for authority
to change rates. Commission staff filed an appeal of order number three. The commission
heard oral argument from the parties at the June 13 meeting, but did
not take action on the appeal at that time. The appeal
is before you now, and Chairman Gleason filed a memo in this document.
And as you mentioned, we have two members from the public,
or perhaps parties that signed up to speak on this item.
Ed, I also believe is the mayor from League city here
as well,
and the mayor from the. Nice to have you, sir. All right,
so since this is a bit untraditional, do you want.
At what time limit do you want to set for public comments on this.
Let's do two minutes. Two minutes. All right. And just so everybody
knows, typically we don't take public comment on contested cases, but I know you
all were told to show up today and so happy to hear from you.
Yes, sir. Yes, sir. Would you like to start with the mayor? Yes, sir.
All right, if you'll come up with.
I'm Ken Panton and I'm the mayor of Beach City.
And I do appreciate,
mister chairman and commissioners, for allowing us to speak.
It's just really nice of you to do that for
us. As you're aware,
Undyne used test year April 20 April 1,
2022 to March 31,
2023 for proposed rate increase.
And Undyne stated this test period was
to reduce time and expense required to prepare
new rate code. In order to change rates,
the commission requires that the application
be based on a test year as the most recent
twelve month period beginning
on the first day of a calendar or fiscal year quarter
for which operating data for a retail public utility
are available. It is clear that the test year
that Undyne used does not meet this requirement.
And on April 29, as per the April
29, 2024, as per the record, commission staff
filed a recommendation that Undyne should cover the period
from January 1 through December 31,
2023, unless operating
data is not available and that Undine
has not sufficiently demonstrated that operating data
for the period covering April 1 through December 31,
2023, was unavailable.
On behalf of the residents of Bay Ridge
Oaks, Houston Point and Ocean park
in Beach City, that Undyne, we ask
that Undyne's application be denied.
So I appreciate it, and thank you very much that
you all let us speak today. Thank you, sir. Thank you for being here.
Thank you, sir. Thank you.
All right, there's one other person that signed up to speak, and I'm
trying to butcher this name, but the first name is Anders. The last
name may be Moomoolitus. Said it
perfect. Welcome. How do you do?
My name is Anders Dimitri Moomilitas. I am a resident
down in Beach City and we've had a
never ending list of troubles with this particular utility.
And it wasn't just them. There was the utility before them as well.
The last price increase that came was, I believe, in 2017
or 2018 when it was still owned by
Niro. I believe Niro utility.
Now, the price increase came and we were
expecting, you know, that to be put towards capital improvements.
We've had a distressed water system for
many decades now. It's been triaged
with patch after patch after patch, but never a
fix. And definitely never a change. And now
they've come across and they're asking for another price increase to
bring this up. And we were told very specifically and pointedly
on that first price increase with Niro that if we came
and appealed to the Public Utilities Commission, that they
were going to jack our rates even higher and
to not come here. So it was kind of an intimidation tactic. And now
we've been told by undying directly that
they are not. They're not bound to do
these things. You know, this increase is coming one way or another.
They're not very interested in bringing that up. And I
have problems with this because in my job, you know,
I do work in compliance and accounting.
And seeing some of the numbers that have come through,
we found three different sets of numbers
about their test, their test year numbers. We noticed.
We got our notice that came to us,
which was drastically different, much higher.
And then Undine had sent a representative out, Rick Melcher
was senior vice president of
PR, I believe, who came to our community and tried to
tell our community that this is going to be a very small,
effective rate increase, and it does not seem
that way. So thank you. Thank you for being here, sir.
Okay, so, as Sheila said, I filed a memo in this
docket, you know, really focusing on the burden of proof
that undine has. And so,
you know, and not feeling like we can grant the good
cause exception to the test year requirement. Do you have any thoughts on the memo?
I'm in agreement with your recommendations. Your memo.
I'm also in agreement with your recommendations,
and I will entertain a motion to grant, in part, staff's appeal of order
number three, consistent with my memo in this discussion. So moved.
Aye. Second. Have a motion? A second. All those in favor say aye.
Opposed. Motion prevails. Thank you both for being here today.
All right, Sheila, let's start back over at the top. So I think that
item one was consented. So that brings us to item number two. Will you lay
that out for us? Yes, sir (item:2: Sheila lays out Docket 54662). Item two is docket number 54662.
This is the petition of Highlander SM one LLC
to amend crystal clear special utility districts CCN
in Hays county by streamlined expedited release. Before you
is a motion by the petitioner requesting to withdraw the application.
No responses were filed to the motion, but the petitioner stated in their
motion that they had conferred with crystal Clear said, and that crystal clear does
not oppose the withdrawal. And Chairman Gleason filed a memo in this docket.
So same thing in this memo. I recommended that the commission find good
cause exception to allow the petitioner to withdraw its petition.
Thoughts? Agreed? I agree as well.
Then I will entertain a motion to find that good cause exists to grant
the motion to withdraw and dismiss this petition without prejudice,
consistent with my memo. So moved.
Aye. Second motion a second. All those in favor say aye.
Opposed. Motion prevails. Thank you.
So item that takes us to
item twelve. Item twelve is not going to be taken up,
so that'll bring us to item 15. Sheila,
you weigh out item 15, please?
Yes, sir. And just may I add one thing?
Can we go back to twelve for just a moment so I can give the
commissioners an update? Commissioner advising filed a draft preliminary
order in this docket. We would like some additional time just to review
that and bring it back to you at a future of a meeting. I just
want to put that out there in case there are any questions from the parties.
Thank you for that clarification. And then we'll go back to 15, if that's all
right with you. Absolutely. All right.
(item:15:Sheila lays out Docket 56328) Docket number 15 is 56328. The ratepayers
appeal of the decision by crossroads utility services
and south puta water control and improvement district number one
to change rates. Before you is a proposal for decision that
recommends dismissal of this appeal. No corrections or exceptions were
filed if filed, a memo recommending changes to the order.
And Chairman Gleason also filed a memo. So,
memo, basically to adopt the PFD consistent with commission
council's memo. Thoughts? Approved.
Agreed? Yeah, I'm agreed with that. Then I will entertain a motion to adopt the
PFD consistent with my memo and commission council's memo. So moved.
Second. Have a motion. A second. All those in favor say aye. Aye. Opposed?
Motion prevails.
Okay, so that'll take us to item 20.
Sheila, will you lay out item 20, please? (item:20:Sheila lays out Docket 54812) Item 20
is docket number 54812. The application of El
Paso electric to update schedule number Covid-19 in
compliance with docket number 52195.
Before you is a SOA proposal for decision. The city of El Paso
filed exceptions to the PFD. The SOA ALJ filed
a letter stating that she does not recommend any changes to the PFD.
and I filed a memo recommending changes to the order. Thank you, Sheila.
So I initially will say I
thought about consenting this, and then as I talked about it and thought about it
more, I know another one of these is either going to be filed
or has been filed. I was a little struck as odd
that we were going to keep booking Covid-19 expenses.
I thought that was a little strange. And so we worked through it in
my briefing, and I know that there's. It's authorized in an order,
but I really think we need to talk about how long and
in the order that was signed. There's no end
date for this, which I thought was odd as well.
And so, you know, after the briefing, I think we're in a position that
I'm going to say we should approve this, but I think we need to
have commission, council, and staff look at how long we
should be doing this, and if there's a way that we can
go back into that project potentially and have an end date to this,
because I don't know, going into 23,
24, 25, what kind of COVID related expenses we're
going to have. And so, like I
said, I'm in favor of moving forward with this, but I think we
need to maybe look at this expense going forward and
how appropriate it is. I'm in agreement.
I think that's prudent. I had the same thoughts as well as where's
the end date? I'm good.
So I don't know what the right path forward for this. I know,
Sheila, we talked about posting project number
50664 for a future open meeting once you
all kind of look into what a path forward might be for us to address
that order. The initial. Yes, sir. We will work on that and confer
with you on bringing this back to the future. But meaning for project number 50664.
Okay. Thank you. I might say that this is also another reason not to settle,
not to have black box settlements. You're almost going to
get me to agree with you.
Okay. And just to clarify and taking
action on the PFD at this point. Correct. So with that,
I'd entertain a motion to adopt the PFD with the changes to the order
recommended by commission council. So moved. A second.
A motion. A second. All those in favor say aye. Aye.
Opposed? Motion prevails.
All right, we're going to skip over 21
and save that for the end. So, Sheila, that'll bring us to item number 22.
Will you lay out item number 22, please?
(item:22: Sheila lays out Docket 55995) Item number 22 is second number 55995,
the compliance filing for Centerpoint concerning rider,
SRC and ADFEt refund of system restoration
charges before you as a proposed order. No corrections or
exceptions were filed. Chairman Gleason filed a memo in this docket.
Follow another memo. Thoughts, comments on the memo?
I'm in agreement with your recommendations in your memo.
I am as well, supportive.
Okay. I'll entertain a motion to modify
the proposed order consistent with my memo. So move
a motion a second. All those in favor say aye. Aye. Opposed?
Motion prevails.
All right, Sheila, I think that'll take us to item
number 25. We lay
out item number 25, please. (item:25:Sheila lays out Docket 56225) Item 25 is ducat
number five. 6225, the application of El Paso to
update its generation cost recovery rider
related to Newman. Unit six before you, is it draft preliminary order.
And chairman Gleason filed a memo in this docket as well. Filed a
memo in this docket. Thoughts, comments on the memo?
I'm in agreement with your findings on the briefing issues.
I am as well. I think that you're filing
each one of these memos consistent with the number of recusals
that you have. And I think that's great. I'm trying to carry my weight.
That's what I'm trying to do. That's what we do in my office. Totally supportive.
Supportive of your memo. Thank you. I will entertain a motion
to approve the preliminary order consistent with my memo.
So move aye. Second. I have a motion in a second. All those in favor
say aye. Aye. Opposed? Motion prevails.
26 was consented, Sheila. That will bring us to item
number 27. (item:27:Sheila lays out Docket 56693) Yes. Item 27 is docket number 56693.
The application of Entergy Texas to amend its
certificate of convenience and necessity to construct a portfolio of dispatchable
generation resources. Before you is a draft preliminary order.
So I was okay with the draft preliminary order and
would approve it. Happy to hear any thoughts.
I was okay with it as well. Yeah, I'm in agreement as well.
Very much need the generation. I think we should
approve it. It's incumbent upon the competitors in this market out
there and everybody else to prove that the costs are warranted and the generation
is needed. And I expect them to do it. Okay. All right,
then I'd entertain a motion to approve the preliminary order consistent
with our discussion. So moved. Second. I have a motion. A second.
All those in favor say aye. Aye. Opposed?
Motion prevails. Okay, so we are going to
go back to item number 18,
an item which I'm recused, and I will turn it over to Commissioner
Kobos. All right, thank you. Sheila. Can you please lay out item
number 18? (item:18:Sheila lays out Docket 52728) Item number 18 is docket 52728,
the application of the city of college station to change
rates for wholesale transmission service. The commission's order on
rehearing in this docket was filed on May 23.
The city of College Station filed a timely second motion
for rehearing, and Commissioner Kobos filed a memo in this docket.
Yes. So the memo essentially would grant the second
motion for a hearing for limited purposes and making the clarifying changes in the memo.
I think the clarifications are right on. I agree as well.
All right. With that, I would entertain a motion to grant
the second motion for rehearing to make the clarifications set
forth in my memo and issue out an order on rehearing. Shall move
aye. Second. All in favor say aye.
Aye. Any opposed? All right,
motion passes. All right then,
next we will finish out by calling up item number
21. Sheila, will you lay out item 21, please?
(item:21:Sheila lays out Docket 55255) This is docket number five 5255. The application
of Southwestern Public Service Company to amend its CCN
to construct generation facilities in Lamb County, Texas and
Lea County, New Mexico. Let's see before
you is a SOA proposal for decision. All the parties filed exceptions.
The SOA ALJ filed a response that recommended Anhejdehe recommended
adding one ordering paragraph to the PFD. The commission voted to hear
oral argument in this docket. Chairman Gleason filed a memo
in the stocket. I'll leave
it to you there. Thank you, Sheila. So follow the
memo on this one. You know, we spent a lot of time, my briefing on
this pretty complex issue. So my
request would be that we hear oral argument today
and then I make a decision on this at a future open meeting,
if you are good with that. Yes. Sheila,
will you call up everyone for oral argument, please?
Yes. We have six parties that have signed up for oral argument
as we did previously for the LP nautical. We'll have all the parties come up
for the order. We will start with the party that bears the burden
of proof. In this case, the applicant commission staff traditionally goes last
hope for the parties know the order in between those. So let's see
parties go ahead and come on up to the table.
All right, we'll start with the company.
(item:21:Andrea Stover, SPS, Docket 55255) Good morning. Andrea Stover, on behalf of SP's and with
me today is Adrian Rodriguez, president of
SP's and Brooke Trammell, vice president,
regional vice president of regulatory and pricing.
Mister chairman and commissioners, SP's appreciates the opportunity
to speak to you today about the merits of its CCN application pending
in docket 55255 and to answer
any questions the commissioners may have. Like much of the rest of Texas
in the country, SP's is facing significant load growth on its system
and it must also meet the requirements of the Southwest power pool,
including complying with the planning reserve margin instituted
recently. SP's takes its obligation to
serve its customers safely and reliably very seriously.
And it keeps that obligation top of mind
as it plans its future capacity needs in 2022.
As impacts from the pandemic were receding, the extent of SPSS future
load growth began to crystallize. Its load projections for 2026
and 2027, coupled with SPP's increased planning reserve margin
from 12% to 15%, spurred SP's into action,
and it issued a request for proposal for generation capacity.
Ultimately, SP's conducted an
RFP overseen by an independent evaluator, which was open
to all types of generation resources to evaluate
the bids. SP's used quantitative and qualitative criteria and
analyzed the potential solutions using a sophisticated power planning model
called encompass. SP's selected
the most reliable and economic options among the beds,
and its recommended portfolio includes the life extension of two existing
gas plans, the three self build solar projects,
a single self build battery project, and two ppas, one with an existing
generation, a gas natural gas generation, and one with a
new battery project. Each of
the resources in the recommended portfolio reflect different benefits,
including dispatchability, zero fuel costs,
and significant tax credits that will be passed directly back to customers.
The SP's selected the recommended portfolio based on the available alternatives
that were provided in response to the RFP.
It did not compare the bids to other hypothetical resources
that were not available to build. We appreciate the
hard work of the administrative law judges, and we support the PFDs recommendation
to approve the SP's billed solar projects and to grant SP's a good cause exception
so that it may flow those tax credits back to customers as
soon as possible. However, we disagree with the PFD's
conclusions on three issues. First, we request that
the commission approve the proposed self build battery project.
This project provides critically needed dispatchable energy to
serve SP's customers and to meet the SPP planning reserve margin.
SPSS selection of the battery involved rigorous analysis of the resources bid
into the RFP and was a reasonable choice among the available options.
Second, we asked the commission to reject the imposition of performance guarantees for
the solar projects, which are unprecedented, unnecessary, and not
supported by the record.
The guarantees are particularly problematic because there's no provision to address force majeure
scenarios in which SP's has no control.
The removal of these guarantees will not relieve SP's of its obligation to ensure
the solar projects are operated prudently and available to the greatest extent
possible. And finally, we request
the commission reject the requirement that SP's flow tax credits to
customers before it begins recovering its costs for these projects.
SP's proposed to flow tax credits to customers through its fuel clause so that
customers would realize those benefits as quickly as possible
because SP's will likely have to transfer credits in order to realize their
benefits. Because of its current tax position, it's doing so,
and it's flowing those credits to customers before it
will be able to realize it themselves.
But the tax credits are benefits intended to offset the cost. The projects
themselves and to credit customers before those costs are reflected in SP's rates
would be inequitable. I'm going to reserve the balance of my time to close
as the applicant. Thank you.
All right, which party is going to go next?
(item:21:Jule Davis, OPUC, Docket 55255) Good afternoon commissioners. Julie Davis, special counsel with the Office of
Public Utility Council. I appreciate the opportunity to speak today on
these issues. While we understand where the ALJ was coming from and agree with
several of the findings, we disagree with the overall conclusion and urge the commission
to reject the application in its entirety. As a preliminary matter,
though, I do want to address the letter issued by President Adrian
Rodriguez. This letter should not be included in the record for the case and should
not be considered by the commission. One it is procedurally
inappropriate. No puck joined the letter filed late last night in response.
Mister Rodriguez is a licensed attorney in the state of Texas and has practiced
before. This commission is fully aware of the procedural requirements
when a party is allowed to give exceptions to the PFD.
Reply to the exceptions to the PFD and we
see that this letter is nothing more than adding arguments
outside the bounds of the procedural schedule set. For that reason, we ask
that this letter be clearly kept out of the official record and precludes from being
offered as evidence or considered by the commission pursuant to section
20010 60 of the Texas Government Code and under 16
tact 22.226.
Going to the substance of the case before us today, the RFP
clearly favored renewable resources and was fundamentally flawed.
As a result. While it was technically open to
all resources, it was placed on Excel's webpage for renewable developers.
Every page listed this as a renewable RFP.
So while it was technically open to all resources, it was clearly
indicative of a preference for renewable energy.
Further, SP's did not propose any self build thermal projects for
consideration, nor did it solicit bids from thermal developers
to counteract influential statements favoring renewables from its
leadership on its webpage and again in the RFP itself.
So it's no surprise today that thermal resources are not before us
and were not seriously considered by SP's in developing this renewable
recommended portfolio. Conveniently, it also meant that it didnt
compare the cost of potential thermal development to the relatively high prices
of the resources in the CCN today.
To my second point, SP's has not shown that the self build solar projects
will improve service to customers. SPSS load forecast
has load forecasts have changed throughout
this proceeding. Initially, they showed a need starting in
2024, increasing to 947 mw in 2027.
That was later adjusted to start in 2026 up to
606 mw. That was the number used in the RFP.
Further adjusted showing a need starting in 2025 up to 948
mw in 2027. So in pinning down the improvement
to service, it's been hard to get a baseline for more than a couple months.
To this point, though, OPEC does not believe there will be an improvement in
service, particularly when the projected capacity need is at its highest.
In looking at the data SP's provided, opux expert lined
up the hours from both sets of data and looked at when the load was
at least 95% the annual peak demand for
76 hours. SPSs own data showed that the net generation of
the solar facilities will be at or below zero megawatt
output for 162 hours. Net generation will
be at or below 25% of rated capacity.
Opex expert also looked at the hours when SPSs firm load obligations
were within 606 SPSs annual peak for 2027.
And again, that's the number used in the RFP. We found that
net generation of the solar facilities will be at 0 mw for
552 hours and at or below 25%
of rated capacity for 759 hours.
So if you think about it, if you had a car that didn't start three
times out of the ten you needed to, even if you had another vehicle,
you'd probably reconsider that car. To my third point,
SP's has not proven that the resources are economical and will lower consumer
costs. SP's cannot definitively support its position because
it again did not consider any thermal resources in this RFP.
Even as a comparison, in looking at the cost per credit
capacity, the solar facilities cost well above $2,000 per kilowatt
each, and in one case reaching almost 3000 kilowatt, or $3,000
per kilowatt. And as the ALJ agreed, the battery is
very expensive at roughly $2,700 per kilowatt.
Even accounting for the ITCs, the battery cost is at
$1,900 per kilowatt of equipment credit capacity.
Finally, SBS suggests that the avoidance of fines for having
lower capacity than required is somehow a savings to consumers.
And in the same way, I would save money today by not running a red
light. Only if it was true that I budget for bad driving. There's a
difference between a savings and avoiding a new cost. Because the
RFP was flawed, SP's did not and could not prove the economics of the self
build projects. And the data SP's provided shows
that consumer would bear significant financial burden for resources that
will disproportionately underperform. And for these reasons,
OPEC respectfully requests that the commission reversed
the findings of the ALJ as appropriate and denied the application in
its entirety. Thank you.
All right, which party will go next?
(item:21:Ben Hallmark, TIEC, Docket 55255)Ben Hallmark for TIEC. Thank you for the opportunity to provide oral argument.
This is a complex case, as the chairman noted, and we
appreciate you giving it the time that it deserves. Now, you're going to hear a
lot of arguments today back and forth about potential costs and potential benefits.
And I think it can be at some level easy to get lost in the
clutter in a big case like this. So I think it's important to
start at the sort of bedrock place which is
what the legislature has told us that a CCNA requires.
The commission may only grant an amendment, a CCN amendment
if the commission finds that the certificate is necessary for
the service, accommodation, convenience or safety of the public.
SP's has unequivocally failed to show that
the battery is necessary and should be approved. It's a
purchase of a 36 megawatt battery,
but given where they're putting it, it will only be able to
provide 24 accredited capacity. It would
be about 2.5 times the cost of a CT
per kilowatt of accredited capacity, even assuming the
full investment tax credit. And it would only have half
the useful life of a CT 20 years versus 40 years.
Glaringly, SP's, despite stating that they would run
the battery to provide energy arbitrage savings, has not provided
any energy savings analysis in this case whatsoever.
To be clear, this is not the case where you usually see, which is
someone like me arguing with the utility that your energy savings analysis
is flawed. This is a case where there is no energy savings
analysis. SP's selection so there
is simply in our view, no basis in the record to
support certificating this battery as the ALJ is found
now, SPSS selection of the solar project also suffers from
flaws, including a failure to consider adding any
new thermal resources to its system to meet the need.
The result is three solar facilities that would provide accredited
capacity at a cost that is roughly 4.5
times spss estimate of the cost of a CT,
again on a per kilowatt hour basis.
This type of purchase places substantial risk
on ratepayers but given its heavy rate based cost,
it could also be a boon to shareholders. And of course the solar facilities are
not dispatchable and will only provide capacity when the sun is
shining. However, given the potential for the
benefits of production tax credits and avoided energy costs from the solar
plants, we come down differently than ERCOT. While we appreciate
their concerns, we believe that with the proper rate making protections,
ratepayer protections, the solar plants can be approved and meet
CCN muster.
You heard earlier a comment that it would be unprecedented
to have a performance guarantee applied.
But I'd like to point out also that it would be completely unprecedented
for this commission to approve a capital intensive renewable
project without ratepayer protections, including a cost cap
and a minimum production guarantee. This commission has also in the past
adopted a cost cap or capacity resource over the
utilities objection. So we believe that our recommendations,
which were partially adopted by the PFD, are well within the bounds of commission
policy.
Before I move on, there is one particular assertion
in Mister Rodriguez's letter from yesterday that I'd like to address. He referenced a
partial stipulation in SPSS parallel PPA case.
I just wanted to clarify that it's partial because while the parties
agreed to the extension of the natural gas PPA in that case,
the parties did not agree to the battery PPA, in that case the
interveners in that case, at least the retail ratepayer interveners
all opposed that battery, just like all of the interveners.
Retail rate payers in this case oppose the battery. In fact,
it's worth taking a step back to reflect on the fact that you have a
pretty broad cross section of interveners in this case. You have OPEC
representing residential and small commercial, you have AXM representing
the cities and the affected territory, and you have tiec.
None of us want this battery approved and none of
us are asking you to approve the solar facility without the conditions.
So how did we get here? One of the most important issues in
this case that was flagged in the preliminary order is how these proposed
facilities compare to all viable alternatives when
it comes to providing reliability on a cost effective basis.
It's in the preliminary order of paragraph 22,
but we don't know how the proposed facilities compare to adding
new thermal capacity to spss system. That evidence is just
not in this case. SP's didn't consider any new thermal options
as part of the RFP process. We have discussed in detail
how that came to be in our brief, but the bottom line is
that SP's and their self bell team could
have offered natural gas resources out of the RFP. They admit that,
after all, they like to tout that this is an all source solicitation. So yes,
they could have offered a natural gas options at their existing sites,
but they didn't do that. They only offered solar and batteries.
So what you have before you is an application requesting
to spend $770 million in ratepayer money on additions
that are for capacity, where the utility never modeled a single
new thermal addition as an alternative.
There is no economic analysis in this case showing that solar and
battery resources are better fits than natural gas options.
None. Instead, we just have conclusory arguments
that it made sense to grab the solar and batteries because tax credits
made them attractive. There's not an analysis that actually
shows they're more economic. And we know that utilities continue
to build natural gas resources like the CT. This commission recently
certificated for El Paso Electric, but SP's didn't consider those
options. We've also seen conclusory arguments that it may have
been difficult to get air permits, but we have not seen an analysis
showing that that couldn't happen. And again, utilities are building
plants, and we know that the cited provisions of the Clean
Air act do not even apply to cts in most cases.
So we think that that's a problem and that feeds
directly into the need for conditions on the solar plants
under the facts of this case. So we end up with these three solar facilities
selected as capacity resources. But they constitute a
very expensive method of obtaining a relatively small amount of
accredited capacity, if you view them as capacity resources.
If we go down that frame that SP's wants us to go down, they are
providing accredited capacity again, counting degradation
at over four times the per kilowatt of a CT.
So in isolation, you would never do that, right? No,
but there is the potential for offsetting PTC and energy savings,
which are not something you get out of a CT. However, the extent
to which those benefits will accrue, I should say not to the
extent with respect to energy savings. However, the extent to which
those benefits will accrue cannot be reliably predicted in the future.
It turns on how much output these plants are actually going to provide.
It turns with respect to energy savings on what lnps they're
going to avoid years and years and years into the future. So absent
conditions, there is a risk that the plants won't perform is
the risk that the plants don't perform is purely on
the ratepayers. If the plants are approved and put in rate base, SBS will
earn a hefty return on them estimated at over 833 million,
regardless of performance. Now this
is the risk that comes from choosing a capital intensive method of
obtaining capacity. Given these asymmetric risks,
and given that potentially cheaper options were not adequately considered,
conditions are necessary here. The PFD recognized
this in adopting a minimum production guarantee. However,
it did not recommend a cost cap. We believe a cost
cap is necessary for the same reasons that the PFD adopted the
minimum production guarantee. Here, the projects pose an unreasonable risk
to ratepayers of being an unreasonably expensive
option to provide capacity, and the prospect of cost overruns
just pushes that risk even higher. And for the same reasons,
it's not adequate. As I imagine SP's will argue
that you can have an after the fact prudence review.
SP's is the one that chose this extremely expensive way of
obtaining capacity, and its shareholders stand to gain from that choice.
Therefore, it it should not matter, especially given the absence of consideration
of alternatives, whether the reason if these plants are to underperform
or have cost overruns was outside of SBS's control or
not. Certainly it's not in ratepayer control, and our argument is
that we should not bear 100% of the risk for this type of acquisition.
As I noted, all of the previous renewable projects this commission is approved
were agreed to under settlements with conditions.
We would also note that the conditions that TIEC
and AXM are proposing here would not shift all of the
risk to shareholders. SP's would still be able to put the full estimated
cost of the plants, including the contingency, into rate base,
and it would only be on the hook for the minimum production guarantee.
If it failed to reach an output level that it projects, it will meet in
90% of the modeled cases. This is about balancing risk
and trying to find a win win on a renewable project.
With respect to the battery. However, we believe there are no conditions
that can save that. The battery was added at the end of the process
after SP's had already selected the solar facilities. SP's forced
the battery into its model based on its theory at the time that it
needed about 70 extra capacity or so, which I'll get
to in a minute. When the battery was forced into the model, it was compared
only to other batteries, no other types of resources.
The battery cost almost 3.5 times as much as a CT per kilowatt
hour of capacity without the ITC. And even if you treat the
ITC as an offset to capital cost, as I mentioned, it's nearly
2.5 times with the ITC and
the battery only lasts 20 years. SP's has provided again
no energy savings to justify the battery, even though it
says it will operate it for energy arbitrage.
SP's can't tell you what they think the battery would provide in terms of
energy savings therefore. But what we do know is that whatever that number
would be, SP's would seek to retain 10% of it under the
off system sales margin sharing as an additional issue.
Further, SPSS decision to add the battery was based on
a load forecast that it no longer considers accurate.
So as I mentioned, they evaluated the RFP
using the spring 2023 forecast, and after they had
selected the batteries, they decided that under that forecast they needed
an additional 70 capacity or so. So this was
the rationale to sort of reach out and pick these batteries as opposed to using
the modeling process. They were right sized according to
SP's at that time. However, then comes
the summer 2023 forecast in which SP's now has a much greater
need. So they are no longer right sized to meet that need.
And SP's is now planning a ten RFP for
this year of up to ten gigawatts. Which obviously raises substantial
concerns that there may be additional costs coming down the pipe for
ratepayers, making it more important that we get this right and nothing
acquire extremely expensive small batteries.
Now to take a step back, as you may have seen in our briefing,
we don't believe that SP's has actually proven up their need
conditions, their need contentions with respect to the
battery. We think there's been a problem with a lack of transparency around
those load forecasts. But as the PFD recognized,
you don't really need to reach the details of that issue because
there's simply no support work for the battery under any of these forecasts
in the record.
Again, just to make clear, in addition to
these other issues with the battery, it is a 36
megawatt battery that they're putting at a location where it can only provide
24 capacity, assuming you also approve the solar.
So that's an additional problem. So we would submit that under
these facts, the only way that SPSs battery could be approved is
if the CCN test was the utility has a need, it should be
allowed to acquire any resource it wants, regardless of whether
the size or economics makes sense and regardless
of what alternatives were considered. But that is not the CCN
standard. Indeed, as I mentioned, with the ten gigawatt
RFP coming down the pike, it's especially important
that ratepayers not be stuck with with unduly expensive resources in
this case. If SP's believes that batteries are part of a
solution going forward, we would urge them to bring those back
as part of that next RFP process, support them with adequate
analysis, and let the commission and the parties take a look at them at that
time. But this battery does not pass muster under the
CCN test and we ask that you deny it. Thank you
very much.
All right, which party is next?
(item:21: Sergio Herrera, AXM, Docket 55255) Mister chairman. Commissioner Sergio Herrera for
AXM AXM echoes the points and the
concerns raised by Mister Hallmark and Miss Davis in regards to the letter
filed with Mister Rodriguez yesterday, so I won't repeat those
same arguments. My main focus today is to
stress what the PMD largely got right and the
one critical thing that it got wrong. First, the PFD correctly recommended
that the proposed battery project should be denied. The battery project
is simply too expensive for providing only 24
accredited capacity. I would like to add that the cities
that comprise AXM and SBS have
a very good working relationship, something that we work towards and we're very proud
of, so we don't take the recommended denial of this project
lightly. However, the commission serves as a substitute for
competition, and regardless of whether SP's is proposing the
battery project to meet a capacity need or for an economic
reason, costs must always be considered.
For these reasons, Aggs emerges the commission to adopt the PFD's recommendation
to deny spss proposed battery project in
regards to the solar project outside of the PFD's failure to
recommend a cost gap, the PFD correctly recommends what the record
evidence in this case demonstrates, and that is that approval of the solar projects
is reasonable if approval is conditioned upon certain
customer safeguards. Specifically, the PFD correctly
recommended that approval of the solar projects should be conditioned
upon a minimum output guarantee to protect ratepayers
against asymmetric risks presented in the event SBS's objections
proved incorrect and the PFD correctly recommended that
approval should be conditioned upon a production tax credit or PTC guarantee
so that customers receive 100% of the ptcs earned by the solar
project, and that there is no delay in crediting ptcs
to customers. Any delay in crediting customers with the benefit
of these ptcs would result in customer forgoing the
benefit of these initial ptcs because the ptcs
are only available for ten years. Moreover, the benefit
of the ptcs is largely what makes the solar
projects potentially more economic than alternative and
dispatchable sources of generation that have significantly lower
upfront capital costs.
What the PFD got wrong is that it failed to recommend a cost
gap as a third condition for approval for the solar
projects. During the hearing, SBS admitted that a cost contingency
is already built into its projected $702 million construction
cost for the solar project. Therefore, AXM's recommended $720
million cost cap for the solar projects would provide SBS with
additional breathing room in the event that the company incurred additional
cost pressures not covered by its contingency that's already
built into its cost projection. Ultimately,
ratepayers must be able to rely upon SBS's expertise in
constructing any type of generation resource, and to do so on budget,
but especially ones such as the solar project that has such high upfront capital
costs. It's important to remember,
and Mister Hallmark touched on this as well, that even if SBS misses the
mark on its projections and the solar projects fail to provide the
ptcs, the energy benefits and the fuel savings
that the company projects they will provide, SBS will still earn
a return of and on its investment. For this reason,
a cost cap in conjunction with the PTC and
output guarantee that is recommended to the PFD is crucial.
At bottom, none of the conditions that AXM is urging the
commission to adopt, not the outlet guarantee, not the PTC guarantee,
and not the cost cap, hold SP's to a higher or some
unfair standard. AXMS recommended conditions wouldn't
require SP's to construct the solar projects at a lower
cost than the company projected. They wouldn't require for the solar projects
to produce more energy than SP's projected,
nor would they require the solar projects to produce more ptcs
than SBS projected. The conditions AXM has advocated for,
and is advocating for, are simply there to safeguard against the fact that if
SPSS projections miss the mark and prove wrong,
rate payers will be stuck footing the bill for a very
expensive and potentially underperforming non dispatchable generation
resource. At the end of the day, the cities that comprise
AXM rely upon the commission to hold the utilities accountable.
These conditions for approval of the solar projects will help do just that, and in
a fair manner. For these reasons, AXM urges the commission to
adopt a $720 million cost cap as
outlined in the direct testimony of Mister Scott Norwood.
AXM also urges the commission to adopt the PFD's recommendation to deny
the battery project and to adopt the PFD's recommendation
to condition approval of the solar projects on an output and PTC guarantees.
Thank you.
All right, is the next party going to be golden spread? Yes. All right.
(item:21:Todd Kimbrough, GSEC, Docket 55255) Good afternoon, Mister chairman. Commissioners Todd Kimbrough here
today on behalf of Golden Spread electric cooperative golden
spread's perspective on these proposed projects differs somewhat
from TIC, AXM and OPEC simply
because we are uniquely situated as a neighboring utility
to SP's and come with that
perspective in mind. And as a result, Golden Spread's
focus has been particularly heavy on the operational impacts of the proposed projects.
Golden spread does not address the questions of economics or the
proposed projects or cahps, or any of the things that you've been hearing about
prior.
Probably somewhat obviously, as a member of SPPA,
Golden Sprite is particularly interested in the issues of planning, reserve margins
and some of the things that were outlined by Mister Rodriguez's letter yesterday,
and we'll want to spend some time talking about that in the course
of this afternoon. It's probably best to
actually start by just walking through the unusual chronology of the
selection of the proposed projects. The proposed projects use
old sites at Planx in Cunningham, where 60 to 70
year old plants experienced unplanned outages in the summer of 2022.
In the docket, we learned that SP's had considered retiring these units
several years prior, 20 17 20 18 20 19,
something like that, but chose not to do so. We also learned that SP's
engineering reports began identifying problems at those plants
decade or more prior. SP's did not issue rfps
or file a CCN application for new generation at those
points in time in the past passed. It only came after
the units failed in the summer of 2022,
about four months after the unplanned outages of those old units.
This would have been in November of 22, SP's issued
the RFP for the replacement capacity and
for previously unforecasted load growth. The proposed projects
are the result of that RFP. About seven
months later, summer of 2023,
SP's had evaluated the RFPs and filed the
application that is underlying this docket in
the course of the hearing. In this docket, SP's actually testified,
though, that a proper resource planning time
horizon is something more in the line of five to ten years,
not 18 months. This is especially noteworthy
again when we think about the fact that those
60 to 70 year old plants at plant X and Cunningham had
known problems and SP's itself had begun considering retirement.
About five years ago,
about two months after filing the CCN, SP's began
the SPP interconnection study processes for the proposed projects.
So at the time of the application, the potential transmission interconnection
costs for the projects were unknown and the application assumed
them to be zero.
Some, but not all, of the SPP interconnection studies have
been completed by the time of the SOA hearing. There are in fact still a
few SPP studies that remain incomplete, and the potential for
interconnection costs remains. If upgrades and
other interconnection costs are required, it is possible that some of those may actually get
assigned to SP's neighbors, including golden sprout.
I think it's fair to say the process of selecting the proposed projects
and the related diligence likely would have been quite different
had the five to ten year planning horizon been used instead
of the roughly twelve month process that was actually used
here. It's noteworthy in the PFD, the ALJ's note
I'm quoting here, the ALJ's find that SP's provided little
explanation for why it was only in 2022 that SP's
discovered a need for capacity as early as 2024.
Had a five to ten year planning horizon been used instead,
there would have been a lot more options and a lot more information available in
the course of the selection process here.
SP's in the course of this docket testified that thermal projects
and projects at other sites outside of the old plant X and Cunningham
locations could not be used because the interconnection process would
have taken too long, given the quick process and quick turn
around for their need. Somewhat obviously,
with a five to ten year planning horizon, there would have been time for these
interconnection studies to have occurred, and that would have opened the door to potential
thermal projects and potential projects from other third party entities.
Going back to the SPP aspect of that, and going
back to Mister Rodriguez's letter from yesterday, that's particularly
noteworthy because different types of technology and different projects get
different capacity credits for purposes of the planning reserve margin.
As a rough shorthand, you should expect a higher capacity
credit for a nuclear plant than you should for a solar, and so on,
and it's going to vary technology to technology.
A five to ten year planning horizon also would have given SPP
enough time to give us comprehensive analyses of the interconnection
costs. It would have given some surety to neighbors like golden spread
that there wouldn't be potential interconnection costs shifted
onto the neighbors.
All of this has actually then led golden spread to recognize the
need for certain conditions. If these projects are approved
first, SP's should accept all risks and costs associated
with the upgrades derived from the SPP interconnection
facility studies for each of the proposed projects.
SP's should also accept all costs associated with
compliance with pending NERC and IEEE standards for
new ibrs. Each of these projects are inverter based resources that
are pursuant to FERC order 901. That's the new
order related to voltage ride through and frequency ride through for
these proposed projects, lest there be any sort of transmission
solution that then again is shifted on to neighboring utilities.
And then lastly, SP's should be required to submit
periodic reports to the commission on the status of the interconnection of
the generation facilities, the determination of costs for
any potentially needed modifications related to the interconnection costs,
and then also with compliance with SPP, NERC and IEEE
standards for those proposed projects.
Again, golden spread does not dispute the fact that
SP's, and frankly, utilities all through the region are needing new capacity.
That I think is a truism. The question is, how do
you do it in a way that doesn't have an adverse effect on your neighbors?
And with that, I'm more than happy to answer any questions.
Thank you.
All right, and the last party or
argument before we go back to the company is commission Stan.
(item:21:David Hrncir, Comission Staff, Docket 55255) Good afternoon, commissioners. Thank you for providing staff with the opportunity to lay out
some of the major issues that we've had throughout this document. While staff
does not take a position on whether the commission should approve SBS's
application, staff recommends that the commission impose certain conditions on these projects
if they are approved. There are five major issues I want to go through today.
The first is the weatherization standard. The second is the cost cap.
The third the prudence review. The fourth,
the treatment of production tax credits, or ptcs. And the final
issue is how this commission treats the other rate
making issues requested by SP's for the
weatherization standard. Staff respectfully disagrees with the PFD.
SP's proposes designing facilities to adhere to NERC reliability
standard EOP 0121.
Staff recommends that the commission require SP's to incorporate
the ERCOT weatherization standards as laid out in our testimony
and briefing into the design of the plant X located in
land county. Generally, it benefits the public
interest to have the most resilient and weatherized grid
in Texas as possible. This can be achieved through following
these ERCOT weatherization standards, which are the established parameters
for most of the state. ERCOT sets these
guidelines because Texas is a region that has its own unique
extreme weather patterns and although Plan X is not included
in the ERCOT weather zone, it borders the zone directly and
would be relying on weatherization standards that were established
based off of the weather in the county right next door,
rather than relying on solely federal government standards, as argued by
SP's staff urges this commission to apply
the ERCOT weatherization standards as they're developed in Texas.
The second issue is on the cost captain.
Staff respectfully disagrees with the PFD regarding the cost cap.
Specifically, staff recommends that a cost cap of 100%
of the total estimated costs of the four projects be applied.
As identified by TIEC.
Staff's recommendations for cost cap aligns with commission precedent established
in previous capacity cases. Ultimately, staff's recommendation
aims to establish a guardrail that would prevent SP's from overspending
on a project at the expense of its customers, and imposing such
a cap should be seen as a necessary precaution in this case.
The third issue is the prudence review. Staff agrees with the PFD
and appreciates spss lack of opposition to staff's recommendation
that the commission select a third party consultant to conduct a prudence
review. Fourth issue is the production tax credits.
Here, commission staff agrees with PFDEM that flowing
the grossed up ptcs to ratepayers as eligible fuel expenses
as they are earned is the most efficient method
to ensure that ratepayers receive the full benefits of any
approved facilities in a timely fashion. This recommendation is consistent
with what this commission has done with the hale and Sagamore wind projects.
If the commission agrees with SP's and determines that customers should receive
credits once cost recovery commences, then the
commission should ensure that any or SP's should ensure that any credits
earned prior to commencement of cost recovery are preserved in a regulatory liability
for the benefit of the ratepayers and not kept by
SP's for its own benefit. Staff further recommends that
the commission should not impose a condition on approval that SP's must not
place the facilities into service until the commission has issued a final order in
a rate proceeding. The treatment of these ptcs staff
also recommends that the commission should not pre approve recovery of
any transaction costs associated with the transfer of unused ptcs
in this proceeding. The rules for implementing the iras
new transfer provisions are still under development, so doing
so would be premature. Instead, this commission should preserve
its right to review the reasonableness of any transfer costs actually
occurred in a future proceeding. And finally,
the rate making issues SP's asked this commission to
address several rate making issues in its application and staff supports the
commission's determination during the discussions of the preliminary order in
this case that, with the exception of ensuring ratepayers receive the
full benefit of the ptcs and renewable energy
credits in a timely fashion, that this commission will not address rate making
issues in this proceeding as requested by SP's staff reiterates
that rate making issues should generally be left to rate proceedings where actual
costs are known and not addressed. In CCN proceedings like
this one, where costs are only estimated, that's the conclusion
of staff's issues. Thank you for giving me the time. Could you please put your
name on the record? Oh, David Berlin for commission staff.
All right, we will go back to SP's for the remaining time.
(item:21:Andrea Stover, SPS, Docket 55255, Closing Remarks) Thank you, chairman and commissioners, for this opportunity. First, I'd like
to start with the discussion that a lot of the intermediaries
were addressing related to the identification of the need
and the timing by SP's. As I mentioned in
my opening statement, SP's during the pandemic
and shortly thereafter, like a lot of utilities, was seeing a drop in load
and was, as it came out of the pandemic,
its load projections started to change. And in 2022
that change became acute and it coincided with
the SPP's change to its planning reserve margin, which it up from twelve
to 15%. SP's does resource planning
on a long term basis, five to ten years out.
The issue is its load projections were changing rapidly
given the conditions in the country after the pandemic. So the idea that
they could have anticipated what was happening not only with its load growth,
but with what was happening at SBP in 2019 is
not realistic as it relates to the RFP
process and the concerns that were raised by TIC and OPEC,
primarily during the proceeding. The idea
that some of the statements that were made by the,
the company, the parent company of SP's and
other folks at the company were
somehow influencing what happened during the RFP process
was dealt with during the proceeding, and there was no
evidence to support that at all. In fact, when you look
at the response to the RFP process, which was open to all resources,
as I previously described, SP's received bids for natural
gas, hydrogen, as well as batteries,
solar and wind. It received bids from all types of resources and
ultimately selected a PPA with a thermal resource
and extended the lives of two natural gas plants. So this recommended
portfolio includes thermal resources and other
new dispatchable technologies like the batteries as well.
Some of the criticism from the from the interviters has to do with SP's
not proposing a natural gas facility in this proceeding.
This goes back to what we were discussing before,
where, because this need arrived
on a very quick timeline. In order to be sure that they
had the capacity in place by 2026 and 2027,
they had to look at resources that they could build and have interconnected
in a timely manner to meet those needs,
natural gas facilities can take longer because of permitting
issues, construction issues. And in SPP,
the interconnection process takes up to seven
years. So if you were to build a new gas plant at a
greenfield site on a new interconnection point,
there was extreme concern about being able to get that capacity
online and serving its customers and meeting the
needs of the PRM in time for the 2026 and 2027
years.
You know, the other issue is that the criticisms about
the RFP, the PFD actually found that the RFP process
was fair and reasonable. It took issue with SPSs selection of
the battery, but it did not take issue with RFP process
overall. And in fact, no party pointed to any part of the
process, save the selection of the battery, as being unfair
and reasonable. Or it also, you know, this process included
an independent evaluator who oversaw everything that the company
did in reviewing bids and making the selections.
And no party took any issue with the independent evaluators assessment,
which was that the RFP process was fair and reasonable.
You know, Golden Spread has mentioned interconnection
issues and concerns about costs that will be applied to it.
To golden spread, should there be some further analysis from SPP
related to interconnection?
We've filed the reports from SPP that were associated
with the cost of interconnection. There are
no costs that are going to be uplifted to other customers.
And the PFD recognized that and did not agree with
golden spreads proposals related to those issues as
it relates to the selection of the battery. The party's criticism
of SPSs selection of the self build battery assumes that there was
only one way to select resources and that it must be spit
out of the model that SP's used to evaluate the different resources
that it got through the RFP process. But the model is a
tool. It is a tool to evaluate the projects,
to see how they fit within the larger portfolio of resources that
SP's has, and to determine whether or not they were economic.
For example, in reviewing the RFP results,
SP's took the bid. I'm sorry. The bid evaluation team discovered
that the model was required to select more costly and lower scoring projects
to fill a small capacity need in 2026. This would
have resulted if they had just let the model run that way. It would have
resulted in much higher cost projects being proposed.
So they looked at that. The team included, then decided to include
an assumption for a Mattix two life extension and re
optimize the model. This lowered total systems cost substantially,
about $43 million in the present value revenue requirement cost.
The team then re optimized the model to assume short term capacity purchases
as a proxy for the life extension of Cunningham two. This further
lowered the system costs for SP's. Those were actions
that the SP's bid evaluation team took in managing the
model. They did not just let the model make those decisions on its own.
No party complained about the choice of the life extensions
as part of the recommended portfolio. Those were very
economic decisions to make. They're gas, they're thermal.
Plants that the companies now allow will continue to run and provide
good service to its customers.
After it made those decisions to extend the lives of Cunningham two
and Maddox two, SP's then directed the model to evaluate
the battery resources after the model had selected a
much larger solar and battery project that was located in the northern part of SP's
service territory, so a good distance away from the load
growth that it's seeing on its system and would likely
be subject to congestion. It decided
that so that project had low qualitative scores
in terms of whether or not that project was going to serve SP's needs.
The evaluation team identified the battery resources as an alternative
because they were of a comparable cost. So the battery resources
did not cost more than the other. The other project that the model
would have selected and then used that
and re optimized the model again and
evaluated the battery project in that context.
Although the parties argued that the only right way to select a resource
was the for the model to choose the resource, no party argued that
SP's should have proposed the larger solar and battery project if they
were so convinced that the model needed to choose the projects that
SP's brought forward, one would think that that's what they would have
proposed. The fact that SP's made judgment calls
about how and when to optimize the model so that the portfolio best meets SP's
needs was evaluated and selected does not mean that the selection of the battery
project was unreasonable. Instead, it indicates that SP's team was thorough
and thoughtful about right sizing the project. Mister Hallmark
brought up the right sizing issue and both OPEC
and TiUC had mentioned the load forecast issue again.
I think we're all familiar with the fact that load forecasts are increasing exponentially
every time they are performed. Given electrification and
other economic forces
that are affecting the amount of load that utilities are seeing on the system,
SP's wanted to be forthcoming about its load projections.
So it obviously presented its load projections that
it was relying on when it issued the RFP and made
the selection of the resources it did, and during that time it
chose the recommended portfolio because it met those
needs without, you know, being oversized.
We, during the proceeding, we were forthcoming about
our updated load projections which indicated
a greater need. The parties would have you believe that because we now
have a greater need, that means that the load projections
no longer justify the projects that we're coming forward to ask
for approval of, which seems to be illogical.
If our need continues to get greater, how is it that it's appropriate
to reject these resources that will help us meet this growing need?
The company has plans to come forward with another RFP as
mentioned, and it intends to do
everything it can and continue to
make robust analyses to choose the right projects to
bring before the commission. It would really appreciate guidance
from all of you and the best way to do that. It believes
that it had done so in this application and
does not believe that what the parties have proposed, which is to compare
the resources that were bid into this RFP to projects
that were not available to it, there were no thermal, there were no
large thermal resources that were proposed besides the ones
that we selected. And there was not any indication
that we would have been able to build any thermal resources in time to
meet the need that we identified. I think I'm out of time,
(item:21:Chairman Gleeson to Hallmark & Herrera, Cheaper Alternatives, Docket 55255) sso thanks to
each of you for your comments. Before I open it up, just really
quickly. So Mister Hallmark,
Mister Herrera, just real quick, help me understand your
position on the solar facilities. So if
a cost cap was put in place in addition to what's
in the, in the, what came in the PFD from the ALJ,
you'd be okay with the solar facility,
but you still say that there would be
cheaper alternatives? A CT would still be cheaper, is that correct?
Well, a CT could potentially be cheaper.
We don't know because there's not an analysis in the case, but it could potentially
be cheaper, at least on, I'm talking about the capital cost component
of it, the sort of the installed cost versus solar. If you compare
the amount of accredited capacity you're getting,
but you know, like I've said, there is the potential for the ptcs
and energy savings to sort of make up the difference.
And we understand that and we understand that's why SP's proposed them.
And our view is, is that if the protections
are in place, that these would be acceptable resources,
the solar facilities, to provide
capacity, even though the CT may ultimately be cheaper?
Under the facts of this case, we think so, yes. And we have
a similar view. Our cost cap is a little bit different.
But in general along the lines, if we can take advantage
of the PTC and the fuel savings,
and put those as ratepayer protections in the form of conditions along
with a cost cap, then AXM would
be comfortable with the approval of the solar project.
Commissioners? Yes, Andrea, I have a couple of questions
for SP's. So there's two
reasons why you feel you have a capacity. One is the
load growth that is changing since the pandemic and
is increasing as time goes
on. Is that load growth that you're talking about?
Is it SP's Texas specific, or is
it the whole system? For SP's, the load
growth is occurring across the system. There is maybe
more market increase on the New Mexico side, but it is, they are experiencing load
growth across the system, and they're receiving large
interconnection requests from customers, as well as just generalized
increased load growth. So the
SPP prms, at least the one that applies to this case, is the
increase from where SPP took action to increase the summer
PRM from 12% to 15%. That happened in October
of 22. And so when
the company looks to meet SPP's planning reserve margin requirements,
does it look to meet those requirements on
a system wide basis like SP's
system wide basis, or on sort of a jurisdictional basis?
Texas, New Mexico, the company looks to
meet those requirements on a system wide basis.
You know, it. I don't know if you're referring to the fact that there's been
some discussion in the proceeding about the fact that we've got
certain resources that were not approved in Texas but
were approved in New Mexico. And it
was the company's position in the proceeding that,
you know, when it initially did the analysis of what its needs were,
it looked, looked at it from a New Mexico
basis, mainly to include those resources that had not been previously
approved in Texas. But then it also looked at it from a
Texas basis as well.
And it's the company's position that it's not appropriate
to attribute capacity from resources that are
not being recovered from customers in the jurisdiction
in Texas. But overall, when it
has concerns or when it's interacting with SPP
and there's a determination of the planning reserve margin, it's on a system
wide basis.
Okay. Thank you. Sure.
Would it be possible for me to speak to the cost cap questions
that you asked? Tic and axm?
Sure appreciate it. I just want to note,
you know, this commission has, the last time it
instituted a cost cap, it did so in,
I think it was a SWepco case. It was related to, it was a capacity
case, but it was related to wholesale capacity.
And most recently, in docket 42487,
the commission decided that a cost cap was not appropriate.
And in part because there was concerns about whether if
the cost cap was set too low, that entergy might not
proceed with the plant. And that plant was very sorely needed.
This is a similar situation here. This capacity is sorely needed on the
SP's system. And if there's a cost cap,
it's not suggesting that that would necessarily be the case.
But we wouldn't want to be in a situation where it might turn
into something that the company wouldn't be able to pursue.
Because cost increase. SP's is very concerned about the cost to customers.
And in fact, in the case, its projections are
that customers are not going to pay anything for the recommended
portfolio, likely until 2036.
And even then resident the impact to residential customers is going to be
$1.78. So a lot
of the cost discussion that was happening today was surrounding
was quoting costs that don't account for the PTCs
or the energy savings from the solar.
From the solar project. So I just wanted to make that clear.
Mister chairman, May. I'm sorry, I did have one question.
The whole subject of weatherization came up and I guess there was a recommendation
that we follow ERCOT standards. Would you be agreeable to that?
You know, I think SP's opposed that during the proceeding.
Mainly because it believes that the NARC requirements
are sufficient. But I don't. You know, I don't know if either
Mister Rodriguez or Mister want to speak to that on the ERCOT
weatherization standards.
May I ask something related to that too? Because in
a prior docket, in Entergy's OCAP's docket, we applied
the ERCOT weatherization standardization. And I'm noticing
had been through my reading that three of the proposed plants are
in two of the solar and one of them one of the batteries that do
Betsy go. So I'm wondering how we can extrapolate ERCOT
standards into New Mexico. Right. I think.
May I provide a clarification on staff's position for
the weatherization standards? So staff's
position is just for plant x, which is the one located in
Texas. So those weatherization standards we. But not for
the ones in New Mexico. Thank you Mister
Homer. I think I understand. I'm good with your position.
It was kind of on a different. I was looking for something different
when I asked you to what Miss Stover provides. So I think I'm
good on this. Actually, I just wanted to clarify one thing on the SWEpcO case,
if that's okay. I think it was misstated. I think we're okay. I think we're
okay. Appreciate it. Any other questions?
Okay. Thanks to each of you. So, yeah,
like I said, a lot going on in this case,
obviously. And so I think another meeting
to kind of delve through all this would be helpful for me and, I think
for everybody.
All right, so that'll take us to the end of the contested
case proceedings. That will move us to rules and projects.
(item:28:Public Comment) Item number 28, Sheila. Is anyone signed up to
give public comment? Yes, we have several people that have signed
up for public comment. We'll see if everyone's still
in the room. Let's start with.
I don't know if that's the first name. Correct. It looks like Camille.
Cool.
Did I mispronounce it? Cook. Cook. I'm sorry?
Cook. C o o k e? No. C o o k. Got it.
All right.
Yeah. Thank you. And just before you start, just clarify three minutes for each
person, all right? Yeah. My name is Camille Cook.
Thank you. Good afternoon, commissioners. My name is Camille
Cook, and I work with public citizens Texas office. I'm here to speak
about Hurricane Barrel and center point. What's been happening in Houston
since Monday morning has been an absolute disaster, a disaster that could
have been avoided. Centerpoint had days to prepare for barrel's approach,
and even before that, months and years of evidence of
weak resilience and had months and years of evidence of weak resiliency in their
infrastructure. With each new storm, Texans are losing more
and more confidence in center point. It seems like every year there is another
storm that wreaks more havoc on the city than the last storm. I mean,
at this point, it is becoming a monthly thing. People are still recovering from the
thunderstorms that knocked out power in May. The third largest city in the country should
not be plagued by resiliency issues like this. What may be
the most reprehensible, though, is the lack of communication with the many Texans who rely
on Centerpoint. I get it. It's difficult to fully weatherize every
single wire and poll in Houston, but the kind of communication we've seen
has been absolutely too low. 72 social media posts does not replace
the lack of a working outage map. Why hadn't it been up on Monday?
And why hadn't it been up before this storm? This lack of accountability to
the people for something as pivotal to modern american life as electricity is
a shame. And the weakest and most vulnerable in our society will pay for this
lack of accountability with their lives. Y'all commissioners exist
to protect the weakest and most vulnerable Texans from utility incompetence.
Y'all have the power to ensure that reliability and resiliency standards
are methadone upheld. Advanced and ready, y'all can
ensure that homes in Texas are more energy efficient, that wires and poles
in sugar land and Manchester are more resilient, and that
centerpoint is communicating to Texans in a clear and responsible way.
Chairman Gleason and all of y'all, I appreciate y'all's comments on the importance of
communication. I want to end by asking one question. If Centerpoint
is not beholden to the public, to the average texan seeking a better life,
who is centerpoint beholden to? Thank you. Thank you
for being here. You're welcome. The next
person that signed up to speak is Dave Cortez.
No, Hendeli. All right. The next person is,
I believe, is it Michelle Christensen?
Yes. Good afternoon, I'm Michelle Christensen.
Thank you for allowing me the opportunity to speak before the commission today.
As a concerned rate payer and member of the Windermere Oaks Water Supply
Corporation, I feel compelled to bring to your attention the ongoing
mismanagement of our small utility, which serves just 300 taps.
Without immediate intervention, we face a very real prospect of bankruptcy.
Currently, Windermere has four open cases with the PUC and
has recently hired a new law firm, John Carlton,
incurring significant legal expenses for unnecessary matters.
Despite the final order of the rate appeal, setting the legal budget at $3,000,
Windermere has already exceeded this amount by $48,000
this year and is on track to spend a over $100,000.
This mirrors the previous situation where rates were raised
to cover excessive legal fees. While significant resources
are spent on paying attorneys, crucial upgrades to the utility continue
to be neglected. During a recent board meeting,
the contract operators of the utility reported that although the
water quality meets all requirements, the nearly 40 year old
pipes are in dire need of maintenance. It stands to reason why
over the past three years we have repeatedly faced line breaks and water shutoffs.
In March, the IR's initiated an investigation into the
practices of Windermere Oaks Water Supply Corporation,
specifically scrutinizing their non member income and financial
management. Subsequently, the president and another
board member resigned, followed by the secaret treasurer and an additional
board member, leaving only the vice president in place.
The vice president, the last remaining member of the board who was
a board member that signed an agreement between the PUC staff and the utility
in PUC docket 56 167,
which was about Windermere failing to operate as a nonprofit corporation
in compliance with Texas Water code section 13.00,211
and section 24 included in the final commission order
that Windemere was required to sub file various reports by
June 1. However, to date, none of these required
reports have been filed with Windermere, opting instead
to repeatedly request extensions.
On June 26, 2024, the ALJ in
this case denied Windermere's latest extension request, finding the
corporation out of compliance. Despite this,
the vice president, who had agreed to the terms, failed to ensure
the reports were filed by the additional deadline of July 8,
2024, thereby causing the water system to miss
this deadline. So not only did we
fail to meet the agreed deadlines, but the new deadlines set by the
ALJ. Finally, in PUC
docket 56272, the compliance docket,
the rate appeal related to refunds and surcharges Windermere failed
to file an accurate report as they incorrectly reported refunds
to customers who were not entitled to them and not charging surcharges
to customers who should pay for them. In closing
at can I do go ahead? Yes, please.
In closing, at the most recent board meeting, the vice president stated that
they have only four months of income left to pay their bills.
This situation is dire and underscores a severe mismanagement
and lack of direction in this member owned and controlled water system, putting this
future at serious risk. Putting its future at serious risk thank
you for allowing me to speak today and for any assistance you can provide us,
including appointing a temporary manager. Thank you.
Thank you for being here. The next person that signed up is
Jamette Rosas.
Good afternoon. Thank you for allowing me the opportunity
to speak with the commission today on the issues with the Windermere Oaks
Water Supply Corporation pursuant to Texas
Water Code section 13.4132
A and 16 Texas Administrative Code section
24.355 a, one that the
commission is vested with the authority to appoint a willing person to
temporarily manage and operate a utility in instances where
the utility has effectively abandoned its operations.
Under 16 Texas Administrative Code section 24.355,
actions constituting abandonment, but are
not limited to a utility's failure to
adequately maintain its facilities, failure to provide
sufficient facilities leading to potential health hazards,
extended outages or repeated service interruptions and
demonstrating a pattern of hostility towards or repeatedly
failing to respond to directives from the commission or
inquiries from the utility's customers. The Windermere
Board of directors has fiduciary responsibilities to
act in the best interest of its members who are also its
customers. Their continued neglect and mismanagement are
not only a breach of these responsibilities, but will inevitably burden
the members with additional unnecessary expenses and
potential fines while jeopardizing the utility's ability to
provide continuous service. This situation cannot continue.
We believe it's necessary that the commission initiate proceedings
to appoint a temporary manager to protect the assets of the corporation
and ensure the reliable provision of utility services before
the situation deteriorates further and leads to a potential bankruptcy.
Thank you for allowing me to speak today. Thank you for being here.
Person that signed up is Danny. And is it plunker?
Yes. Okay.
If I mispronounced it, please state your name for the record. It's Danny Flunker.
F l u n k e r. Good afternoon,
commissioners. My name is Danny Flunker, and I'm here today as a concerned member of
Windham Roaks Water Supply Corporation and here to address serious issues
that have affected our community and to request your urgent intervention.
As some of you all may know, that we just had the PUC rate
case 50788, and the commission found that the 71% rate hike was
unjust and unreasonable. Over the past several years, our community
has endured a tumultuous period where board members
have spent millions to defend and conceal their misdeeds.
Today, the board continues to violate the Text Public Information act.
One of the new directors even admitted to deleting texts claiming they were personal,
when in fact, they were business related. I requested the financial information
in December of 2023 to assess the co op's financial health.
In response, the board spent over $4,000 merely reviewing this request.
To date, I have not received the requested information, and the board has
recently engaged the Texas attorney general to once again conceal other
public information from us. I would be remiss if I
did not mention that this has been an unsuccessful and very costly approach
to our board over the last several years.
In closing, regarding Docket 55454,
Windemere entered into an agreement with the commission staff acknowledging
its failure to comply with several statutory requirements and,
as the others had mentioned, that they've missed their deadlines
for submitting the class D annual Report 2023 annual report for
both June 1 and July 8, and they have
not had an audit. In fact, I don't believe Winter has ever had a financial
audit.
The lack of financial transparency is alarming and raises significant concerns
about the management of our resources.
The current board has also spent over $48,000 in legal fees,
March, April and May alone. I have requested
January and February and have not. They have
not been made available, and I request in June, and that has not been made
available to me either. So they
are on track at the $48,000 to spend more
than any previous board in this fiscal year.
Therefore, we formally request the appointment of an emergency manager to
oversee the operations of our water out. Thank you.
Thank you, sir. And the
next person is Bruce Sorgen.
Hello, commissioners. My name is Bruce Sorjen. In 2016,
the Windermere Oaks Water Supply Corporation sold four acres that it owned in the Spicewood
airport. The board sold it to a sitting director, who was also a realtor for
$203,000. It was never marketed.
She produced an extremely undervalued appraisal for $185,000
by an appraiser who later testified in court that he never laid eyes on the
land. Nor did he mention the word appraisal.
Nor did he mention the word airport in the appraisal. He appraised it as farmland.
This entire transaction was never mentioned on any
agenda. The board claimed it was simply a clerical error. The next board
spent more than $2 million of our money fighting not to get the land
back. I ask you, why would they not want this land back?
The four acres has since sold for more than $1.1 million. The said
director was found guilty in district court, breach of fiduciary duty and
conspiracy to harm the water company. As you
know, this said about a four year rate appeal.
Meanwhile, many struggle just to pay their water bill.
Our current board is headed down the same road. We have six acres
left that appraised in a 2016 forensic
appraisal for $760,000. Now, today,
the board is suddenly in a mad rush to sell this six acres. No appraisal,
no marketing. Why? Last month, a buyer
showed up at a WWSC board meeting, handed the directors
three offers and walked out. The first offer was for
a million dollars, and if signed in the next 19 hours,
it was valid. After that, it was void. The second offer for $800,000,
was good for 30 days if signed, and the third offer for $600,000
for the 60 days if signed. It was a setup.
The board knew what the details of the offer offers
were before evening, opening envelopes. Without even opening
the envelopes, did the board sign an offer.
Who knows? They're blowing through legal fees like a teenager with a credit card,
even engaging the attorney general in an attempt to block releasing information.
The $3,000 annual budget that you gave them lasted about five minutes.
They've spent $48,000, as others have said, in legal
fees for March, April and May alone.
I have here an anonymous letter sent to me last week by
the vice president of the water board, claiming that we,
quote, dissenters, have cost this community $1 million.
More than ten people have resigned from the board in recent months.
Recently, it was down to one director, who ran it for two months
alone by himself. This lone director has since hand
picked the replacements, refusing to have an election.
This community has proven time and time again that there are too many bad actors
that can't be trusted to run this water supply corridor corporation.
It's time for this commission to step up and stop this dysfunction. I am asking
this commission to install a temporary manager. Thank you.
Thank you, sir.
And the last person that signed up to speak is Norma Cortez.
That concludes the public comment section. Thank you, Sheila. I want to thank each
of you that showed up today, waited through the morning, through lunch,
and sat through this. Thank you for coming.
All right, so 29 will not be taken
up. I don't have anything on 30 or
31, so that'll bring us to item 32,
(item:32:Chairman Gleeson lays out Project 55999) project number 5599, reports of ERCOT.
So I think, Davita, if you'd like to come up.
Good afternoon. Good afternoon, chairman and
commissioners, the vita de wire with ERCOT.
One topic that we wanted to remind you all
of, and provide a public update on was the cancellation
of the summer contract for capacity. ERCOT issued
a market notice on June 21 announcing the cancellation.
As I'm sure you'll all recall, we had been seeking up to 500
capacity demand response capacity to provide relief on
certain transmission constraints. In response
to the RFP that we issued, we received submissions
totaling 21.5 mw. Based on the
size of the response and the operational complexity and expense
that would have been incurred, we decided to cancel the RFP.
And I'm here available to answer any questions or take back any questions
that I'm unable to answer, if you have any,
commissioners. Debbie,
does the expectation still that ERCOT
will work with the stakeholders to come up with some kind of a framework using
the lessons learned from the prior two demand response RFPs?
Yes, ma'am. Absolutely. And I'll note that
some of the lessons learned from the winter RFP,
particularly with respect to process and making sure that
you all were informed and involved from before the get go,
were ones that we tried to incorporate in the summer. And we intend,
when we have the resources to do so, to put those in the protocols so
that everybody has a better understanding of the process going forward.
And we will follow up with you all to make sure that if there are
other lessons learned, that you want to make sure that we're incorporating, that we do
so. Yeah, I think this process was much better
this time around. Thank you. Thank you.
All right. The other topic is earlier this week,
and I apologize for the timing of the filing. We filed it as
soon as we were able. We filed an update
regarding the good cause exception that you all graciously
granted us with respect to the timelines for issuing a request for
proposal for must run alternatives to the CPS Bronag
units one through three that CPS
announced they were planning to retire at the end of March of next
year. We filed a timeline consistent with the order that
you all issued, and I am available to answer any questions or
address any comments that you have, commissioners questions,
comments on the timeline.
Glad you're doing it. Thank you.
Thank you, Divia. Thank you. We'll submit a market notice with this
timeline as well as the filing that we've already made. Thank you.
Thank you. So next,
(item:33:Chairman Gleeson lays out Project 54445) so I know we don't have any protocols to adopt, but I'm going to call
up project number 54,445, review of protocols adopted by
the independent organization. Rebecca, you want to come up?
So I know in response to the board
adopting 1224 PotoMac, the IMM
filed comments earlier this week. I don't want to
get into a back and forth between ERCOT and Potomac,
but I did want to offer up. If ERCOT feels
it's appropriate and would like to respond to those filed comments, please do so.
ERCOT can work on a response and follow before the next open meeting.
Rebecca is there was for ERCOT.
And I know typically we ask for things to be filed a week out.
Show some grace on this. Try, I would
say try to get it a week out, but if you can, it's understandable as
well. Now that you
brought this up, Chairman Gleason, I'm wondering because we're, I guess, on the
way to consider this NPRR at the July 25 open
meeting. I'm wondering if we should allow stakeholders
respond to the IMM or provide any additional comments
that we may want to consider over here before we take up the protocol.
Yeah, I mean, my feeling, I'll just say my feeling, personally, I, you know,
a lot of what was raised in that filing, I think is ERCOT specific.
And so I think my preference. You know, we had the whole stakeholder
process out at ERCOT. I think if everyone's okay with that, I think my preference
would be to let ERCOT respond to the.
And leave it at that. I'm with you.
That's okay. That's fine. Okay.
Okay. We will file comments in response. Thank you.
(item:34: Chairman Gleeson lays out Project 54584) Next. Up is item 34, project 54,584
reliability standard for the ERCOT market. The discussion on cost
of new entry Chris
good afternoon. You all follow the memo.
Good afternoon commissioners. I'm Warner Roth with commission staff.
At the request of the commission, during a previous open meeting,
staff filed a memo providing our recommendation on the cone study
results for this open meeting. In this assessment,
Brattle used a reveal preference methodology to identify
which generation resource technologies have been built recently in ERCOT and
which resources are in the interconnection queue and will be built in the foreseeable future.
From this, Brattle identified an aero derivative combustion
turbine located in Harris county as the recommended reference
technology. Through its analysis,
Brattle calculated that the cone for this arrow derivative CT
would be approximately $293 per kilowatt year.
They provided a couple of alternative calculations, including cone values
that have been used in PJM, an alternative reference technology with
a solar plus battery hybrid, and the sensitivity around a conventional
combustion turbine. The values for all these technologies are included in
staffs memo adjusted the 2020 $6 given
the current uses for this cone value, staff recommends that
the reference technology not be changed from a conventional frame turbine at this time,
and we recommend that you use the $162 per kilowatt year value
for a conventional combustion turbine that Brattle used as a comparison point
in its cone assessment. So there are currently two
primary uses for cone in this context. First, it's tied to
peakernet margin. If the reference technology is
changed, we believe that this formula would need to be
reviewed thoroughly. Currently, the Peakernet margin accumulates
for any settlement interval where the real time energy price exceeds ten
times the natural gas price index. Essentially, this aligns when
a conventional CT would expect earned revenues
in excess of the cost for that unit to operate.
Copying this formula over to a different technology without a thorough review would not be
appropriate. And as an easy to understand example, a solar
storage hybrid would have different operating costs and would earn different revenues at
different times of the year. So simply copying a
solar storage hybrid into this speakernet margin calculation would not be appropriate.
The differences between an error derivative ct and conventional frame CT are
less extreme, but they still need to be fully understood. All else being equal,
if both technologies are earning similar margins over their operating costs,
the industry should be picking the cheaper technology.
The reference technology will also play an important role in the market design discussions
around the reliability standard and the performance credit mechanism. Picking a
more expensive technology would impact the analysis of the PCM,
as the outcome would need to provide for the necessary price signal to incentivize investment
that builds the new reference technology to achieve the reliability standard.
This should not be done without explicit commission direction. To do so,
and to end the memo, staff provided several considerations for future
iterations of the cone study. First, staff recommends
that the study should include the determination of cone values for
several technologies as recommended by ERCOT at the last open meeting,
within the context of the broader market design review, this should also
include an assessment on the expected revenues each technology would expect to
earn in an energy only market. To better inform the commission on
whether the current market design is providing necessary investment incentives and
if not, what targeted adjustments would be needed.
Next, we believe that geographic diversity absolutely needs
to be considered in future cone studies, even if the current interconnection
queue shows a high concentration of resources being built within a single
area. This cone value is being used to assign
a cone for the entire ERCOT footprint. And so having a cone established based off
of a technology located within a specific zone may not show
the true cost of new entry for the entire ERCOT footprint.
And just as a couple of examples, miso calculates the
cone each year for each of the local resource zones, so it has ten different
cone values that it uses. And then, looking at Brattle's
most recent cone assessment for PJM, they provided four cone values that capture
differences in the constrained areas of the PJM footprint, so it is common
to have multiple geographic areas when determining cone
for different isos. Next,
when the commission conducts its system wide offer cAp program review in 2026,
staff recommends that the commission consider whether the low system wide offer cap
is further needed. During the emergency
pricing program rulemaking, some stakeholders provided comments that recommended the
elimination of peaker net margin and the LCAP, as they felt these efforts
will be duplicative of the consumer protection value that the emergency pricing program
provides. And to be clear, staff is not recommending the elimination
of the LCAP at this time. But given its ties to cone, we recommend
that the ongoing need be considered during the review of the commission's system wide offer
cap programs. And as a last note, ERCOT has requested guidance
on the timeframe for updating cone. Staff recommends
that, at a minimum, that a cone study should be conducted every five years
to align with the review of the system wide offer cat programs and the broader
market design, if approved in the current reliability standard rulemaking.
And with that, I'm happy to take any questions. Thanks, Werner. Appreciate it.
Just quickly. So, to the reference technology,
Brattle's recommended technology, they're a derivative,
so the thinking behind that is that's what's currently being built is what you
said, correct? Yes, that's correct. That is the cost for a new
era derivative to be built. Yes. To your knowledge,
are new era derivatives actually being built in Texas.
And while I can't speak to every single era derivative CT that's out there
in the interconnection queue, my understanding that they are primarily refurbished technologies
and Brattle was not able to ascertain
the cost of that, as that is some competitively sensitive information for those
that are building those. So that is not the technology that's
being prevalently built? I would say no. Okay. I do think some
were bid into the TEF application. So that
goes to, you know, and I talked to a number of stakeholders about this as
we talk about timing, of updating this. I think, I don't want to do this
too often, but I think perhaps after we set
the first one, maybe the next time we shorten that because we'll have TEF,
but we'll also have the build of facilities
that are not TEF, but are looking to get the completion bonus.
So we'll have a wide breadth of information that will come not too
soon after we have to adopt this. So I think the way I sit right
now, and I'll be honest, and, you know, I'm not ready to make a decision
on all this today. I still have. I want to talk to ERCOT some more
and staff and some stakeholders. But I think, as I said today,
you know, we are going to get a lot more information. So I think the
first iteration of update may need to come sooner than we
would, you know, on an ongoing basis. And I'm in agreement,
based on my discussions with ERCOT and Brattle, their snapshot
that they took for the preferred or the reveal preference
technology only looks back three years. And what's in the interconnection queue
right now, they have no visibility into the TEF. So I think that
that's important to have a broader snapshot of
what's actually being built more into the future.
I think the other thing you're going to see is we have an aging fleet,
right? And so a lot of your baseload generation would
not necessarily be the peakers. It might be the
alternative technology that staff is recommending.
And also, I think there was some work that was done by Brattle on
the alternative costs that kind of supports what staff
is recommending on the.
Not the roct, but the frame Ct.
Werner, as far as in the analysis, the useful
life of these facilities was pegged at. What was
it 20 years. I believe it was 20 years, yes. And typically,
we do this on 30 years. Is that correct?
Correct. I know different parts of the country
do it in different ways. The last assessment I saw was 25 years,
but I would need to go back and confirm that. So what I got from
ERCOT and Brattle was that they recognized that
power generation plants, their life cycle is like 30,
40 years plus, but they set the amortization period
at 20 years because that's when the generators want to be able to recover their
costs of the plant.
So it's not necessarily the life of the plant, but when the generator want
to recover their costs,
I think you start to see. I think that's right. I think you have,
once you get beyond 20 years, you have banks that increase
financing costs. If you're going beyond 20 years for facilities, you also
have outages that you increase beyond 20 years.
But also remember that the plant that you put in in
year one is not the same plant that you're running in year 20 because
of maintenance that's happened over those 20 years. Sure,
I think. But shortening it is just, I think, is more indicative
of changing that variable is going to
have an impact on the analysis if we've done different timelines in the past.
So comparing those to previous assessments, you're not necessarily
comparing apples to apples. I think that's fair. Yeah. And in
fact, that is something that I requested from Arkady and Brattle is to provide us.
I won't get into the preferred technology just yet,
but my thoughts on that. But with respect to the amortization
period, to look at something like between 20
and 30 years, like a 25 year period, just to kind of get an
idea for competitive purposes, of the magnitude of the impact of just
extending it a little bit out because the
amortization period has a direct dollar impact
on the ultimate cone figure.
So I would like to see 25 years.
You'd like to see what it looked like, but yes. And then
make the decision whether it makes sense, whether it's 20 or 25 years.
Yeah, because I think we're seeing the plants stay out there for, like,
more than 40 years. Actually, a lot of the plants I've toured recently are like
50 to 60 years old. So, I mean,
I just like to see the figure.
Other questions for Warner.
One other thing that I like, maybe not so much of a question. Well,
a question and then a request. Did y'all look at the
impacts of levelized real versus nominal dollar
analysis? Chris Brown
Commission staff so all the values recorded in this table are in constant
2020, $6. So there's.
They're all adjusted and updated for inflation pegged to 2026.
Yeah, I'd like to see the. Once we figure out what reference technology
that we're going to use, whether, you know, I know you all recommended a frame
CT, I would like to see what the
real levelized real dollar impact is for frame CT,
because the way I understand real versus nominal is that nominal is
taking, you know, you're looking out to the longer horizon,
and that's capturing inflation, inflation that could be out there in the future and
applying it earlier in the period of the life of the plant.
So real is actually the actual cost of the plant, year by
year inflation or not. So it
seems to be a little bit more accurate
on what the costs are on an annual basis, the real,
the levelized real dollar figure.
So I would like to see that. And I requested that from ERCOT and Brattle
as well, on whatever reference technology, or we could apply it to
the CT frame you all proposed, just for comparative analysis.
We'll take that back and we'll be sure to come to the next open meeting
ready to discuss that.
So I'm going to, you know, I'll take the next two weeks. Like I said,
talk to staff, talk to ERCOT. I'm going to reach out to certain stakeholders to
talk to. I think it's probably, probably also
something to think about if we would want to hear from any stakeholders next
time, so. But I'd like to give them
an appropriate amount of time to get prepared to actually come speak. So I'd ask
if you want to hear from anyone, please let everyone know,
maybe by the 18th week out. I don't want
to just spring this on, folks, so we have a good discussion.
Does that work? Warner,
Chris, thank you. Appreciate it.
(item:35:Chairman Gleeson lays out Project 55826) Next up is item 35 55, project number 5862.
Texas Energy fund in ERCOT generation
loan program.
David, good afternoon. Good afternoon, commissioners.
David Smeltzer, commission staff this should be
an easy rulemaking. As you know, we previously adopted a rule
for the Texas Energy fund in ERCOT loan program.
When that rule was posted to the secretary of state's website, there was an administrative
error leaving off some of that text. So the staff is proposing a
rulemaking to readopt the rule exactly as we adopted
it before. But we have to go through the formal rulemaking process. So this
is the proposal for publication for that. And I would emphasize this does not affect
any ongoing applications, application processes,
and should result in no changes to the rule as adopted. We are just working
to correct this quick error. Thank you.
Will result in no changes. Well, obviously you
can adopt staff recommends no changes. Yeah.
Yeah. Okay. I just like said, I wanted to have
you up here just so we'd make that clear so no one got nervous that
we were making changes. Correct. And for clarification for stakeholders,
the version of the rule that is posted that, you know,
that was signed and in the interchange and is posted on the commission's
website is the correct version of the rule that
you should look to. And then when we complete this rulemaking,
the version on the secretary's website will align with the rule that we previously adopted
and everyone will be on the same page.
Okay. Thank you. Thank you.
I don't have anything on 3637.
Sorry. I need the commission to vote to approve publication
in the register. I would entertain a motion to approve publication.
So moved. Second. A motion. A second. All those in favor say aye.
Opposed? Motion prevails. Thanks, David. Thank you. Appreciate you.
I don't have anything on 3637-3839. Was consented.
(item:40:Chairman Gleeson lays out Project 55718) That brings us to item 45 5718,
reliability plan for the Permian Basin. Yes, chairman,
I was going to call Arkada, too. Commissioner Kobos.
Hi, Christy. All right. Good afternoon, commissioners.
Christy Hopps with ERCOT.
Christy? Yes. If you can, please lay out your July monthly report,
some of the highlights that have happened recently since the last report.
Absolutely. So it's been a little bit since we've given you an update.
Just want to kind of recap where we've been
and the progress that's been made of. So, as you recall,
you directed us late last year in the direction
from HB 5066 to do a transmission reliability
study for the Permian Basin region.
I'd like to take a moment here to really thank my staff for the
amount of work that they've done. It's been a fast and furious
six months for them to get to where we are today.
Also appreciate the cooperation with the TSPs and the. The consumers
of the region providing us the information that we needed to get this
study timely provided for you.
We did a study scope that was laid out earlier
this year. We studied load growth forecasted for
2030 and 2038.
And just to put that kind of in perspective,
the previous load forecast that we had studied based on
purely assigned interconnection and I.
The last study we've done was just over 16,000
information we received from the S and P global study as well as
the TSP's in the area. The amount of load that we studied
grew over 40% to just under 24,000
mw for 2030 and just over 26,000
mw for 2038.
To put that in perspective, what does that mean?
The Permian Basin is now about the size of the
coast region, which has cities like Houston, Galveston and Victoria,
as well as the north central zones, Dallas Fort Worth
area and Waco. So we're talking about a large
amount of load in the Permian Basin region. And that region also
does not have a lot of conventional generation located in it.
What that brings us to is the need for a lot of both local
improvements to the transmission system as well as import pass to
transfer power across the state to the region.
We have had numerous meetings with TSP's.
It's been monthly updates to the regional planning group. We most
recently held a workshop where we went back through the entire kind
of study process. The assumptions that were made, decisions that were made,
reviewed that at the end of June and then opened
up for one last comment period with the stakeholder process and
that closed yesterday. So we're processing any final comments that
we received. We're now working to finalize
our report, which we are on track to file by the end of the
month. We're right now getting target filing that by July 25
here at the commission. So we're just over two weeks out
from getting that report finalized for you. Some of
the highlights as I mentioned,
quite a bit of transmission needs both in the local area as
well as those import pass. Because of the incredible
low growth not only in that region but as well as across the state.
We have expanded our study planning process to also look at higher
voltage transmission. Currently the highest voltage that's operated in the
IS 345. Our planners took a look at options
for 500 kv as well as 765 kv.
And we've got information related to all
of those that we'll be including in our report for you,
for your consideration. Thank you.
Christy, if I could just real quick. I was just told that
our court reporter would really appreciate a 15 minutes break. I know we're
near the end but want to take care of our court reporter and so maybe
thank you for your layout and then if we could just take a 15 minutes
break. So let's take a recess until 318.
We will reconvene our open meeting at 320
and continue our discussion on item 40,
reliability plan for the permit.
Christy, were you done with your report? Right. I was just, you know, kind of
what's, what's next? So we. As I said,
we just closed comment. The final comment period yesterday.
The team will be taking a look at those addressing any of those questions,
we'll be finalizing our report. We,
the project is on the agenda one last
time at the July RPG meeting, just really so we can address any
questions or comments that came in that we need to address.
And we'll be filing our report with you all and then be prepared to
help answer questions, participate in your workshops.
The next steps here. Great. And so are you anticipating
that the plan will still be filed no later than July 25? That's correct.
Okay. And so you'll have an rpg discussion one
last time, collect some stakeholder feedback. My understanding from our
staff is that we'll provide feedback to the stakeholders at that rpg meeting on what
our next steps will be here at the commission once the plan is filed
here. So, you know,
we received a filing recently from Texoga
on ERCOT's division of the plan into
2030 and 2038. Can you touch
on that again as to why the plan was divided into those phases?
That was a part of the initial scope and that was the way the forecast
data was provided to us. And so we,
we took that study approach, which we communicated
since the beginning. What we see in
the 2030 plan is,
you know, a need for a substantial amount of the local transmission
to serve the local needs. As we extend
that into the 2038 forecast, that's when we start adding additional
import path capability into the region for the additional load growth
that we see.
Okay,
so you allude
to some information on the high voltage lines in Miso.
And is that, are those, are those cost estimates for
the current 765 in Miso, or are they for the long range transmission
planning discussions that are happening right now in tranche? I believe it's the long range,
but I will confirm that and get back to you. Another thing that we've
been doing in the interim that was, you know, just initial
estimates. We've also reached out to different providers
that have been working in 765,
development or implementation, and getting additional cost estimates
that we'll be able to provide a range to help validate
that information that we obtained from ISO.
In your presentation for the various options, 345, 765,
500, you include an addition that says
additional new dynamic reactive devices required in
your report that you filed the final plan at the commission.
Can you provide us any kind of an average cost that that may
be? Because I would hate to have any, you know,
surprise costs added to the overall total cost
of the plan. Right. That would be a part of the report. Okay,
great.
Let's see here.
Also as part of your cost estimates, and I
understand you're providing the high voltage aspect as an additional option
to consider to complete that last leg to
get to 2038.
I know you're going to provide some data on that and I guess some of
the information you've gotten so far from Miso and whatever you can
at this point because you're still in the process of completing the higher voltage study.
That will be done a few months after we
approve a plan. I don't know about
in this plan that you file, but definitely in
the study that you file. I think it's going to be really important to
understand what supporting transmission infrastructure,
facilities, equipment will be needed to take
the system from 345 to 500 or 765.
What are those additional components to help us step
up to the higher voltage and what is that cost?
And that's all I have. I'll open it up to any questions that you all
may have commissioned. Yeah, I got a couple. I got, I do
have a couple. One of them is on your slide number eleven. You talk
about 765. I see that you have it on the other slides as
well. But you say that total new right away is approximately
1200. A 20% adder was included for the new
lines. Why did you add 20% for
the new right away? A 20% adder? So the reason
for, and we did that on each of
the options that's included and the reason for that is right
now we're giving you estimates from, you know, point a to point b.
Right. Recognizing that after the, once land is approved,
then the transmission service providers have to go through their routing
process, acquiring land. And what we've
been observing is the days of building straight transmission
lines are no longer. And that helps to account for variations
that the TSP's may have to accommodate. I would say that that
is probably right in most of Texas. But as you get out into West Texas
where there are less trees, less structures, there's less impediments,
it might, 20% may be high when you get out there.
It's not a big deal. But I note that because
the 765 line, which I'm totally in favor of,
could be as little as 1000 miles. The 20%
additional adds 250 miles of 765.
So 1000 miles quite a bit.
Do you all in your study, are you going to have the
total capacity volume?
I don't know if that's the right word of import or
export. We're working through that. Okay.
On a per voltage basis. Right. So what we're trying to
lay out is as much information as possible. Now some of it may
not be all in this report. Right as we start taking
a look at the broader system. But the benefits of
higher voltage are not just, you know, reduced right aways in the
cost. There are a lot of additional benefits, as you're
alluding to that we need to take a look at for the whole
picture right now.
I guess the final question that I have is I
expect you all to come back with a 345 solution. Do you all.
We will have a. So are you talking about for the permian or
are you talking about for the entire state, the Permian? Yes,
we have a 345 solution.
And I guess, let me back up the way we're laying out the report.
There are, if you think about a menu, no matter
what decision you make about the import pass, they are common
amongst all. And so we'll lay that out for you. No matter which
option you take, these are definite routes
that are needed. And then if
you stay with 345, you need this additional piece to be added.
Or if you go to a higher voltage, you need less 345
and underbuild and this additional
build for the higher voltage. So we're going to lay out those options so
it hopefully will make it easier for you as you're reviewing through those.
And will you have a final recommendation or will you just be laying out the
options for us to look at? We will be laying out
the options for you to consider. Okay.
So it sounds very similar to a prior process we've had.
Yes. So I have one question. Sorry. On the.
On the 345, the 500 and then the 765.
So you'll have the capital cost. Okay. But you alluded
to there are other benefits. So you also going to define
what those other benefits are to the best of our ability in
this plan, but that is ongoing work for the entire state.
So we recognize this is new
territory for the last time, a step up change in
the system. You know, we're, before many folks in this room were probably
even born. So we want
to make sure we're laying out all of the information that you need
both, you know, right of ways, miles costs
and a whole host of other benefits. There's stability,
voltage benefits between the different voltages as well.
So line loss. Yes, exactly. Resiliency.
Right. Okay. So you're going to try to quantify that. Yes.
Okay. So do you have anybody at ERCOT
that's really supporting 500,
765 or do you have most engineers that are, like,
falling back, like. Well, 345 is a safe solution?
I would say if I had to survey an informal
survey based off of discussions, I've had. At first there was some
hesitancy. But once we're starting to see the results and
the potential savings and benefits, there's excitement
about being a part of this opportunity to provide a better
solution for the consumers of Texas. Okay. And at this point
in time, HVDC is not being considered.
You looked at it initially, but for this, it's not an
application you're considering. It is not. And the reason why?
One was because. Because of several reasons.
The main one being the market design changes that would have to
come along with it. And we're seeing the need for this
increased transmission in the near term.
And so knowing the process needed
to go through market design changes to be able to operate that in the ERCOT
market, we felt would be longer.
The bigger issue would be actually getting converter stations. So I've
recently heard that the supply
chain backlog on those is quite some.
It's like over 22,033.
So I yielded my questions and now I have more.
So you've done your due diligence on looking at
supply chain to some degree for the converters
that Jimmy just referred to. Have you looked at what
supply chain looks like for 500, 345 kv auto
transformers versus 765
345 auto transformers? We are looking at that.
So far, I've gotten feedback from one utility and
we've got outreach to a vendor, some vendors
and additional utilities to try and get different information
so we can give you a good range,
maybe a good idea to understand how many vendors there are.
Because I've heard that there's only two vendors that actually make those
two manufacturers that make those higher voltage auto transformers.
So which leads me to kind of
just, you know, in your exchange with Commissioner Glotfield. Just so
I understand. So your plan will have a baseline
set of common transmission projects that will be 345
kv transmission projects and the local projects that will be needed,
you know, just to support the heart of the plan.
And then there will be optionality for
the imports. Correct. But the imports from
the top of coming in from the north side, those have always been 345
kv. Are you looking at higher voltage coming in from
the top or is it just 345 kv? I guess. Are we
just only looking at higher voltage for the long line coming into the permian for
the long lines? Okay. Water needed. Okay.
All right. I think that's all the questions I really have this time.
All right, thank you. I'll get your report soon. Thank you. Thank you,
Chrissy. (item:41:Chairman Gleeson lays out Project 56000) That will take us
to item 41, project number 5600.
Firm fuel supply service, Harka.
Good afternoon, Harika. Basaran commission staff and I have Tyler Nicholson
with me. He will go over the core of the memo
and I will talk about the process and the next steps.
Good afternoon, commissioners. So last week,
staff filed a memo providing its recommendations for
the firm fuel supply service program parameters for the 2024 to
2025 contract period, which is the third such
period. In consultation with
the independent market monitor in ERCOT, staff recommends the following
for the upcoming contract period. Basically,
we recommend keeping the status quo from the last two contract periods of
the megawatt procurement quantity having a no megawatt limit,
the budget cap being 54 million, the obligation
period being a max of 48 hours and a single clearing price
mechanism. The big change is the offer cap price
changing to 12,240 /mw based off
current fuel oil prices compared to the previous years.
And another thing we are recommending to ERCOT, and we already started
discussion to maybe perform a new survey. We think
that this market now in the third year, it's still the same players
and it has not been any new entrance or any
new thing. We really think that we concerned about the competitiveness
of this market. So we just want to ERCOT
to do another survey. How can we expand it? How can we
have new solutions and just look at the
program again overall.
So I'm in favor of the recommendation. I'm good with everything.
I do think we need to look at ways to expand this program.
So I think a survey is a good idea to do that again,
to see what barriers we may have and how we may be able to expand
this for the next procurement period.
I think. I would disagree
with that. I mean, I think the question. I mean, it's been less than
a year since we went through this discussion about how we get
in the first firm fuel procurements, and there was
one issue about the.
On the gas supply system, you know, where the resource resides on
that system and is there interruptible power between them and the
resource? I think we found that when we
made that decision that there
couldn't be anything in between the resource and
the firm fuel storage facility.
We got zero responses. And the question becomes,
if those are the responses that we want in
the system, do we need to go back and do a whole new survey to
do that, or do we need to adjust? Adjust what? We thought
we just adjust what we had done
before and say, look, there are other
natural gas facilities that can provide firm fuel service in
addition to just diesel or fuel oil.
And can we do that today without a
survey? Is really, I guess what my question is. I think we can.
I think we know this is out there, and I
think a survey would just help us confirm that.
Okay. And I guess I would add, because we had a
pretty extensive conversation, and I think to your point, Commissioner Glotfield,
we made a decision not to have certain, you know, you know,
resources behind LDC's because the fact of the matter,
what hasn't changed is that the rover commission prioritizes residential gas.
Electric plants are not prioritized. What hasn't changed either is that
ERCOT doesn't have visibility into the natural gas system. So there
were some clear issues that came up when
we went through this entire deliberation that resulted in us ultimately
not looking at those types of supply arrangements that we
spend a lot of time looking at. So unless we're going to be okay with
moving resources out from behind LDC's or we're going to get some
additional visibility into the gas system that we don't
have now, then I'm not sure what a survey is going to get us.
At the end of the day, we're going to end up at .1 unless we're
willing to take on more risk, willing to
take on more risk to get more firm fuel out there. But,
you know, I just feel that at the end of the day, we have
to kind of take a step back and look at the fact that even
with the amount of firm fuel we have right now, we've never even used all
of it. And that's because it's been very
actually strategic, the use of it because of
the curtailment with the pipeline that runs through the center of Texas and that it's
been like clockwork and it's worked well,
I think, you know, I'm not opposed to expanding. Expanding is fine.
But to what? And for what? And how when
there's additional risk that we're going to take on that we clearly saw from all
of ERCOT analysis that went on for months. And so
my thing is, you know, I don't know what a survey is
going to get us other than, you know, there's still interest out
there from firm fuel supply arrangements that we.
That can't comply with ERCOT's existing process. And if we
modify the process, then what does that look like? And what
risks are we going to shoulder as the regulators over here at the end of
the day for this very important product
that is still. I get it. No liquidity,
you know, it's not competitive enough. I'm wondering if there's changes that could be
made within the existing product. Right now that can be made,
that can make the product more competitive, because I
just feel like. I feel like we've had this circular sort of
situation going on for the last two years, and I'm
just wondering, like, what the survey gets us
at the end of the day. But back to .1 and debating this out and
trying to figure out how we're going to make this work or Jimmy this in.
So we're going to be okay. From a risk standpoint,
maybe what end up is changing the program. Maybe just become
a cost based program just for certain specific units
and it's not a competitive product. So we don't have to
go through this. Maybe that will be an option if we, again,
after the survey, and again, we will run the survey before
it goes out with every office and we'll get your feedback about questions
we may be asking. But at the end, then we can make a decision.
And this could be a more like a course based program.
So cost based program for the existing dual fuel capability
would make it more competitive within what we have now.
But I think my broader comments were just on trying to
go out beyond. It would be great to do
that. Right. I mean, but, I mean, it's tough.
I think what we found, the information we got the last time around, is that
there's a lot we don't know and a lot we just don't have
jurisdiction over certain things that put us, the commission
and ERCOT, in a tough position to, you know,
go and pay for those arrangements. And at the end of the day,
we may have no control over any of it. So I
think just a couple things. A survey would help me, just as another data point.
When that last decision, when the risk tolerance was talked about last time, I wasn't
up here. And so I think it would be helpful to me to know what
else is out there. I think there's a chance we may be able to get
more for less money than we're currently paying potentially. And so
I'd like to know that, because I think risk is a trade off.
And so for me personally, I think a survey is
worth it to get that data point to know what's out there and what we
could avail ourselves of, and then we can make another determination about the risk profile
that we're willing to take on. And is that something that we can do for
this winter? No, no, no. This is for the following.
So I guess that begs the question, if we have winter storm
URi number two this winter,
the risk that I see is that we don't take the pipeline
storage piece of this as firm fuel, and because
we're doing a survey and. Sounds kind of
administrative, but it's, you know, it's part of the bar process.
I mean, I will. I think we know what the universe is out
there. I totally respect that. You weren't sitting
up here. You were sitting right there, though,
and I was. My vote didn't count down there.
True. So I just. Again, I would
say that I think we know what going to get in this. You know,
I know you want that information. I appreciate that. I'm not
totally dead set. I just. I'm a little weary that if we go on
this new survey, then we're going to lose a whole nother
year. You know? I don't know.
I don't. I don't know that we. Why would we lose another year, David?
I can't tell you. Surveys. I don't think it takes that long. I don't think
we lose another year. Hello again.
David Dwyer with ERCOT. I did want to point out that
currently in the protocols, the protocols specify what resources
are qualified to provide the service. So if you
wanted to expand for this next year, we would have to get a good cause
exception to the existing protocols and all that that entails.
We've already started talking with staff about potential timing for the
survey. If you all want to move forward with that, we think we could
conduct it likely in the October to November timeframe,
get y'all results in November and December for you all to decide whether or not
you'd want to change the qualifications. If so, we'd be able
to pull out a protocol and have it through the stakeholder process before
the issuance of the RFP for next year, next year
being the next winter obligation period after the upcoming one.
Listen, mister chairman, I appreciate that you
want that information, and I'll defer to you on this. I just.
I think we're going to get 80
or 90% of what we already know.
But I'm happy to defer to you and let you get the survey
and let you get the data that you need to make the decision. Yeah.
And like I said, I think you're right. I'd just like to confess to.
I'd like to know the University of what's out there. If we
redo the survey, is there additional information
or questions that we'd ask after being, as we've
operated it for a couple of years, is there any different questions
that we might ask that we didn't think about asking at the onset?
That's actually a topic that we've raised with staff. They talked
about barriers to entry. Our past surveys were kind of
asking what resources exist and are interested in providing
the service. Exploring what barriers to entry there are
would involve different questions, and we're happy to develop those. And as staff mentioned,
I'm sure there will be a process to run those by you all.
I think we are thinking more than just what's out there. Like,
thinking more creatively, thinking more out of the box. I think
there's value to that.
I think a survey is a great idea, mister chairman.
Thank you, commissioner.
And I'm fine with that. Yeah. I mean, I am, but it's
just, you know, having gone through this a few times, I'm like, kind of like
Commissioner Gotfeldy. I'm like, I don't know we're gonna get. But I respect the fact
that you want to kind of see, and we'll just kind of figure it out
as long as it's not applying for this winner. Yeah, plenty of time. And we
will work with all of you before we publish the survey and get your
feedback as well. You said risk tolerance. That's a good idea.
In that concept of. Let's ask about the barriers.
Exactly. Thank you, Haru.
Thanks, Tyler. Thank you, David, for coming up.
All right, item number 42 is consented. I don't have
anything until item 53. That would
(item:53:Update from Executive Director Connie Corona) be an update from our commission council and executive director.
Good afternoon, commissioners. Just one brief item.
Staff will be hosting a staff led workshop on
the performance credit mechanism parameters that recently.
That we recently received comment on. That will be on
July 25 after the next open meeting.
Thank you, Connie. All right.
And for me, as we discussed at previous
HIPAA meeting, we scheduled additional meetings this year to give us maximum
flexibility, particularly for the many rules and projects
that are in front of the commission in addition to the tested cases.
Right now, we have two meetings in July. Today's meeting, the 25th.
We have three scheduled for August, the first, the 15th
and 29th. I've converted Connie and Barksdale,
and we agree that while there's a lot of upcoming work for the commission,
that in the next two months, it's best to just have two meetings in
August. We can accomplish the work in two meetings. And so with
your agreement, we'll cancel the August 1 meeting but keep the August
15 and August 29 meetings.
I think we're probably all okay with that. All right.
Jimmy will be here. That's the way
to end Sheila on a high note. All right. Something everybody likes.
Okay. With there being no further business before us today this May. And the public
Utility commission of Texas is hereby adjourned.