Uh, good morning, ercot, board of directors and guests. I'm bill flores and I hereby
reconvene and call to order the december 8th and ninth 2025 meeting of the board.
this meeting is being webcast live to the public on kots website. I would like to
provide puc chair thomas gleason, the opportunity to reconvene the open meeting of
the public utility commission of texas. Thank you, mr. Chairman. This meeting, the public
utility commission of texas will come to order to consider matters have been duly posted with the
secretary of state for today, december 9th, 2025.
uh, thank you chair gleason. The antitrust admonition and security map
were included with the posted meeting materials. Uh,
and we, uh, are now open for comments. Chad, has anyone expressed an interest in, uh,
commenting to the board today? No one has expressed an interest chairman. Okay. Thank
you, chad. Uh, our first agenda item is, uh, ercot,
ceo. Pablo vegas is going to make his presentation with the ceo
report, pablo.
all right. Thank you, chair flores, and thank you everybody for your
participation today and your interest in the important work that we are doing at
ercot. In this morning's update, I'm excited to share
erco t's new vision and mission and values.
the, as the grid has evolved, our strategies have evolved along with it,
and we're aligning our core vision and our mission to the needs of the market. And
we've established a set of values that we believe reflect how our employees
want to work and experience their careers at ercot. I'm gonna touch base on
some of the changes in our supply mix since last winter. I have
an update on our mobile generation solution that we've been talking about in san antonio,
as well as the related reliability must run con, uh, contract with the bro three
unit. I'm gonna discuss some of the progress being made on the provisions in
senate bill six and the roadmap ahead of us as it relates to our op operations
and markets and planning work. And then I'm gonna close, like I always do, with some thanks
and appreciation for some of the incredible accomplishments that have been,
uh, delivered since our last time together as a board.
here we go. A year ago,
we defined the concept of ercot 4.0 and
what it represents in relation to earlier periods of ercot
operations. And at a high level, it represents
a transition in our market that is characterized by high and very rapid
growth of intermittent and short supply, uh,
short duration supply resources. It's characterized by a rapidly
changing customer base that includes price responsive loads like crypto
miners, rapidly growing large scale data centers, and
continued penetration of distributed energy resources throughout the grid
from people's homes to their businesses and locations across the distribution system.
it's a significant shift in operational requirements, and it represents an opportunity
to create a more resilient and cost-effective grid for the benefit of
all texans. This shift created an opportunity to
re-look at our vision and our mission, and to make sure it was aligned by the success opportunities
that ercot 4.0 presents. And that success depends on keeping
reliability as the bedrock of our organization.
reliability in today's definition of reliability, which includes
a society that depends fully on the availability of
electricity for nearly every facet of modern life. And to do so, we're going
to have to embrace innovation as one of our core success factors to keep up with
the pace of change. Our new vision is to be the
most reliable and innovative grid in the world,
not just in texas, not just in the united states, but in the world.
we are one, if not the leading grid globally when it comes to operational
and technical complexities. And to be successful, we
need to be a clear leader on a stage that represents the entirety of this planet,
the impact of what texas represents to the global economy today.
and if you look at it just on energy, we produce more than 40% of this
country's oil. 30% of this country's natural gas
have a total refining capability of about 30% of what the
united states uses. That's just an impact inside of texas
and the united states. But to be important in the future, to be successful, we're
gonna have to be a global leader on that stage. Our mission
is what we do every day to achieve this vision,
we will ensure a reliable grid with competitive and cost
effective electricity markets. That is our mission. It is the
re again, reliability at the core of it, and we recognize the critical importance
of a cost-effective grid when it comes to a thriving economy.
and then our values that we developed, we did that directly with input
from many, many ercot employees. We held focus groups and gathered surveys
from hundreds of our employees who spoke to what it should feel like to work and
to be a part of this organization, and what a set of core values that
will create an environment that will foster both individual and organizational successes.
I'm not gonna review each one of the values that are on this slide, but you can see that each
one of them builds upon and supports each other to create an environment where we
can achieve our vision and achieve success in our daily mission.
so changes that we've seen in the grid since last winter, 2025
a year, 2025, is gonna represent a year with tremendous supply growth
on the ercot grid. We expect to see nearly 16 gigawatts
of new supply connected onto this grid in 2025, just
since the end of last winter. This is a chart showing from march 1st through
november 1st. This year, we'll have connected approximately 11 gigawatts
of new capacity. You can see the large majority of it continues to be in
the two resource types we've been seeing over the last several years. Storage. We're
now representing storage as with both the capacity, uh, peak
capacity number, as well as its energy capacity, because since storage is duration
limited, the energy measure is a more appropriate measure of its capacity.
and while we are still seeing low numbers in our natural gas connections into the grid,
we are seeing significant improvements in the natural gas pipeline expressing
potential interest in connecting into the ercot grid.
I think it's helpful to show this comparative, I've done this in the past as well as
we get into the winter season, understanding the impact of supply additions
in both the winter and summer peak conditions. And you can see from this
integrated slide, there are very significant differences in the low carrying capabilities
between these different resources at peak based on their production type.
I share this to try to help explain some of the differences why during this past
summer, during the peaks, we haven't really been experiencing scarcity grid conditions
because the significant additions of solar and battery storage
are optimally positioned to help during those summer peaks in
the afternoons and early evenings. As the sun is transitioning out, winter
still represents the higher risk period in the ercot market because fewer
of these resources that are being added are available during the winter peak
periods, which tend to be in the mornings before the sun rises, or in the
early evenings right after it sets.
I think it's important to highlight some of the progress that has been made on the weatherization program
through our first four years, and this is a focus on our winter weatherization.
since the inception of this program in in, uh, december of 2021,
we have completed over 4,000 winterization inspections of both generation
and transmission facilities. We inspect them for various preparation
measures that are intended to reasonably ensure sustained operation at weather
zone specific cold and hot conditions.
we held a winter weatherization workshop, uh, in october on the 16th
this year, we had over 200 people attend that workshop and
it highlighted best practices presentations from three of our market participants from
lcra, from cps energy and from an l
the winter 2025 and 2026 inspection period. Started a week ago
today on tuesday, and we plan to have a minimum
of 450 inspections over the course of this winter.
I included this, uh, graph on the right side, the winter cure periods
because I think it's important that not only are we going out inspecting, but this shows
how we have been seen progress on the performance of those inspections
over the course of time. And so the cure period is
a measurement that's found when we have found instances of non-compliance with the weatherization
rule. And then the dealing with those, uh, we give them a cure period in
order to deal with those findings of non-compliance. And you can see from beginning in the winter of
2022 to 2023, the instances that we had
a total of, uh, 75, 55 of those were at, uh, transmission
service. And, uh, 20 of those at, uh, supply resources. And those have decreased
over time to a total of only five over the last winter. And
we've had similar, similar benefits and performance, um, as well
in the summer periods. Our cure periods have gone from about 15 in 2023
down to three this past summer. So significant pro improvements
in performance and findings of non-compliance. Over the course of
the three years we've been run running the weatherization program the three, four years,
I wanted to give a brief update on the lifecycle power mobile generation
units that, uh, are, have been brought over into the san antonio area to help with
that south texas, uh, transmission constraint as of october 22nd.
all of those mobile generating units had had been able to initially
synchronize with the ercot grid, and as of this week, all 15
of them have been successfully tested and are available for dispatch under emergency
conditions. And as a reminder, the contract for these mobile generation
units runs through march of 2027, and we have the right
to terminate that earlier if the reliability need no longer exists going forward.
related to that, an update on the reliability must run agreement that we have in
place with cps energy, uh, on the rig three unit, the outage,
it began last march, if you recall, after the approval by the board last december
a year ago, uh, from now and to date, the biggest and
most significant issue in that outage period was a replacement of that number nine boiler
super header, uh, super heater header. The work was completed
for that replacement in october, uh, end of october this year. Testing
completed most recently in november, we had a issue
identified by cps that there were some impurities in the turbine bearing lubrication oil,
and some additional work was gonna need to be done to, uh, refurbish those installed
bearings that could cost an additional 1.8 million, potentially
add about a 10 day delay to the schedule. So as of today,
it's currently scheduled to return to service on december 15th. There is a little bit of
risk to that schedule based on the refurbishment work that needs to occur.
so shifting gears into the, um, regulatory and policy arena,
we've talked about senate bill six and its broad impacts several times in, uh, in these
board discussions. It's driving four significant new rulemakings. One
is focused on the load forecast standardization for large loads,
very significant part of the provision, which is intended to give us better clarity
and better accuracy on the numbers that we expect in that load forecast, which as I discussed
in my, in my last update a couple months ago, is really the foundation for all
of the planning and all of the reliability reporting that we do. We
have another rule making on large load, uh, interconnection standards,
a third one on cost allocation for transmission infrastructure, and then
a fourth on the net metering rules, which is addressed in this slide. We've established
an interim net metering review process that aligns with what the proposed rule is
that's gonna be going through. We already have seen two net metering arrangements
formally submitted for our review at this time. And we're gonna need,
our requirements are we have to go through and complete our analysis within 120
days of noti notifying the puc that we've received all of the completed
information for these net metering arrangements, and we're coordinating very closely with
staff on those puc staff on those. We expect all of these
rulemakings to under to go through the process in 2026
with the net metering and the forecast standardization proceeding first,
and then followed by the other two, uh, rulemakings.
I had like to give a little bit of a look ahead as to what's still on the agenda
and, uh, important work coming up. So from a current operations,
I'll, I'll really highlight the noer 2 45. If you recall. This is the operating
guide change that is related to the requirements for ride through requirements
on inverter based resources through, we probably will be looking at
reviewing the submissions that we've received in for extensions
and for exemptions for, for compliance with that rule through
the second quarter of 2026. And then the actual reliability assessments
that we then run following, having all of that data in will
proceed in the second half of 2026 with decisions on what can be exempted, what
can be extended in terms of timing and compliance. For the noga 2 45 rule,
there's quite a lot on the market design plate, the drrs,
dispatchable reliability reserve service, we talked about the two npr r related
to that yesterday. We've got the residential demand response program,
uh, that we also discussed in yesterday's update. We have a new large
load demand response program that is coming out of, uh, senate bill six. And
so we'll be working on the development of that. And then, of course, from the prior
legislative session affirming requirement, that is a significant
piece of market design, uh, protocol work we're gonna be doing in 2026,
and that needs to be completed by the end of this, uh, next year.
and then at this time of year, from a planning perspective, we publish a lot of end of year
reports. We publish the capacity, demand and reserve reports. That looks out five years
gives a kind of a projection if certain amounts of resources
are built and certain amount of load and materializes based on well-established
criteria that we've used for many years. Then what does the reserves look like under those conditions?
we've got the 2025 regional transmission plan that's gonna come out. This,
uh, this month we publish a constraints and needs report. This is a
focus on transmission constraints. We've also have the reliability
standards analysis that's gonna be taking place in 2026. This will be the first formal
evaluation of the new reliability standard that was established for
ercot in 2024. We'll be doing that full scale analysis in 2026.
all of these reports are going to indicate similar messaging, but
in the very short term, the additions of supply have been helpful in
improving the reliability characteristics of the grid. In the long term, there's
increasing risk if the load materializes and infrastructure development doesn't keep
up. The messaging and the, the, the risks that are
identified are consistent with reports we've seen over the last year, and depending on
the amount of load that comes and the pace at which it comes really is the key drivers
to the degree that that risk may or may not be materialized.
we hosted, um, a grid x event here at, um,
uh, the, actually the met center here just a couple weeks ago.
nerc does this every year or every other year. They do a large scale grid x exercise,
which is intended to practice a response to both cyber and physical attacks
on the electric grid. This year, we participated in, in three different ways.
one, we had our it and our cyber teams compete in a hands-on technical
exercise to identify and stop cyber attacks. Specifically. That was done
a little bit earlier this year. The overall ercot leadership team,
in addition to participation with the public utility commission, the texas department of emergency
management, the fbi and other state agencies
all gathered together, and we did a tabletop exercise that was focused on
decision making, coordination and communication during a very complex
cyber physical attack scenario. That was a couple weeks ago. And
then our ercot operations team used their training simulator to emulate
and respond to grid x attacks according to their regular training cycles.
so, very active engagement in business continuity and disaster recovery
preparations. These tabletops are extremely helpful in aligning roles
and accountabilities during a crisis event, and making sure that our communication capabilities
are both agile and ready for the challenges of the moment.
I'd like to remind everybody coming into the winter season through of the various communication channels that
are available at ercot to get information. Our website, you can
see that on the top right of this slide, we have about a dozen different dashboards that help to inform
what's happening on the grid in real time. We also have our texas
advanced notification system. Texans, you can sign up to get email updates if there
are changes to grid conditions that require any kind of awareness or response
by the general public. And we also are on social media. You can follow us
on linkedin, on x, on facebook, and on instagram.
so lots of different channels and avenues to get real time updates, as well as to get
informational and educational updates on what it is that our is focused on, on the priorities
of the organization.
and then I'd like to finish with, uh, some employee recognitions. So
we've had three things that I wanna recognize. The first, and we talked about this yesterday, and I think matt
marinas did a fantastic job of acknowledging the breadth, the complexity
of this implementation and go live. And I wanna, again, reiterate now
on behalf of everybody within our organization, our thanks to the
broad market, to the public utility commission, to the agencies that
we work with, and a deep thanks to all of the employees inside of our organization
for the work that went into the realtime ization plus battery implementation.
this is the most significant change to our real-time market
since we converted from a zonal market to a nodal market back in 2010.
very significant complex change, intense coordination required across
the entire market participant list, and it went extremely
well. So a huge thanks to everybody involved in that.
I also want to call out those that helped to lead the core values work
at ercot. It took weeks and weeks of work to do the surveys
and to host the listening sessions and to gather the input and to synthesize
and to adjust it and continue to iterate on it to get to those final values
that we developed. And so a big thanks to the team that led that. And then similarly,
we had an internal team that really helped to lead a successful employee summit for ercot.
we do a once a year all employees gathering. We did it on october 14th this
year. We had over 600 ercot employees participate, where we got together
to talk about our core strategies, talk about why our vision and
our mission and our values needed to change, and the opportunities and the
challenges that laid ahead of us. So an excellent production and very well done and think
a very high value use of time. So with that, I'll pause
chair flores, if there's any questions from, uh, the board or from anyone else, I welcome
the feedback or questions public. Can we ask those, uh, ercot team members to stand
up that you just recognized the, for all three of these,
uh, categories, correct? Yeah, if, uh, any of you are named on
any of these three categories, if you're in the room, please, please stand up. I already, I know there's
many of you in here, so please stand. There'll be some somewhere for record. Don't
be shy. I was gonna give them applause, but there's nobody to applause. Well,
, I think we've got some
high people. Great work. Any questions for pablo?
well, great report and, uh, keep up the great work. We look forward to, uh, the excitement
that we have in 2026. Thank you. With that, we're
gonna move into committee reports and we'll start with peggy higg, who serve as the chair
of the human resources and governance committee. Uh, she will present agenda
item 12.1, which is, uh, the committee's report. It has two associated
voting items. Peggy, thank
you, chair forez. The human resources and governance committee had a robust
agenda yesterday with, uh, ms. Billman to two voting items coming outta general
session and two voting items in executive session. The first
item, which is voting item, was, uh, a, a discussion with pablo
about the, uh, recommendation regarding the ercot vision, mission,
and core values that he just referenced. And there's a, there's a, a memo
in the, uh, materials, uh, for the board. This is
the second time that the human resources and governance committee heard from pablo on this. And
I think we were all very impressed with the process and the thoughtfulness
that went into the creation of the new vision and mission
core values. Uh, second, we reviewed
the ercot government documents, and there are, were no suggested
changes at this time. Third, we, uh, reviewed
the periodicity of the, uh, ercot board meetings with
the comparison to other isos. There'll be no changes proposed
to the ercot periodicity at this time. And this review will be filed
with the commission as required by the regulations.
uh, the fourth item, which is a voting item, is that the committee voted
to, uh, recommended that the board approve the 2027 board
meeting schedule and annual meeting of the members. Uh,
the, uh, proposed meeting dates are february 8th and ninth, april 12th,
13th, june 21 in 22, september, 2020,
2021, december 6th and seventh with the annual meeting,
uh, on december 6th, 2027.
fifth, we looked at the, uh, annual review of the board committee
membership. We had just, uh, gotten our new compliment
of board members, which we're very excited about, and we had reviewed that
at the last board meeting. So no changes are recommended at this time,
but the committee will continue to review a committee membership as needed.
we also looked at the, uh, annual committee
self-evaluation surveys, results of the human resources
and governance committee, the technology security committee,
and the finance and audit committee. And, uh, some materials were
filed in, in the board book, but the committees are all
functioning well. We also heard from gilbert hughes
and mark minor presented their annual communications overview.
and we heard from morris back on the, uh, human resources
report for 2025, as well as initiatives in 2026.
with that, we've got two voting items coming out of the general session, and,
uh, if, if it's okay with you chair, I'll
go ahead and make those motions. I move that the board accept the
ercot vision, mission, and core values is recommended by the human resources
and governance committee. Is there a second? Okay, chris, thank you.
all in favor? Aye. Aye. Any opposed? Any abstentions?
okay. The new mission, vision, and core values are approved.
the second motion is I move that the board accept the 2027 ercot board
meeting schedules in 2027, annual meeting of the members as
recommended by the human resources and governance committee. Is there a second?
okay, kathleen, thank you. All in favor? Aye. Aye. Any
opposed? Any abstentions? Okay. The meetings are set for next year or for 2027.
uh, next. Thank you. Thank you. Any more to your report? No, that concludes it. Okay. Thank you.
uh, now we're gonna transition to the finance and audit committee report where I temporarily
served as chair. Uh, we have one associated voting item.
uh, let me walk through the report first, then we'll have the voting item.
uh, the committee went through its normal reports, uh, debt compliance
investments, and went through the, uh, projected outlook for the
full year 2025 financial performance of the organization.
all the performances were nominal and as were expected. Uh,
now in terms of, uh, we also, the committee also reviewed the, uh, soc
audit report. And it had a standard, uh, this is
a standard annual requirement. Uh, the, uh, organization
received an unmodified or clean opinion. The independent auditor also
provided information about the enhancement to the control environment as the, uh,
treasury management system has continued to be automated over the last couple of years.
and so, on behalf of the finance and audit committee, I move that the board accept the 2025
organization system, organization and control audit report is presented yesterday
by weaver. Do I have a second? Second. Thank you, chris. All in favor?
a aye. Any opposed? That motion is carried.
uh, there is no other, uh, reporting. Uh, that concludes by
report for the finance and audit committee. We'll now transition to john
swenson, who will present a agenda. Item 12.3, the technology and security committee
report. John? Thank you mr. Chair. Um, technology and
security committee met yesterday morning in both regular and executive
session. In regular session, we had a guest speaker,
dr. Lee shay, who's a harvard professor and member of the board of
pjm, who presented a roadmap for integrating a agentic
ai into power systems. A very interesting discussion and continues,
uh, with our ongoing ai theme. Um, agen ai enables
large language models to interact with real world workflows, offering human
ai collaboration rather than replacement. It can streamline things like
interconnect studies, optimizing dispatch enhancing reliability through tools
like reinforcement learning and probabilistic scenario planning. Um,
ercot is well positioned to lead in the space and use this technology
with opportunities to reduce engineering overhead and accelerate the grid transformation,
uh, with an emphasis on secure ethical human in the loop ai
uh, development. Following his presentation,
uh, we went into our annual committee self valuation.
and as you've heard there, that was all fine. We had a good discussion. Uh, would mention
that ai is something that we are explicitly incorporating into
our charter so that we will pay more attention to that in the future.
and we'll be working with jp and his team on prioritizing
some of the ai investments for the company. Um,
we had a brief technical overview of rtc uh, plus
b mainly because we, we heard from matt and others in the full board.
um, and we talked about some of the lessons learned and, and some of
the problems that we discovered along the way, which as, as, uh,
jp has told us we're, we're gonna be in another six months of sort of bedding
down that technology and getting it stabilized. So we'll be, uh, we'll
be continuing to follow that up. Um, but, uh, it, it has obviously
gone extremely well. Um, we had our usual overview
of the 18 grid transformation initiatives, uh, was a request from the
board that, uh, there'll be a little more prioritization on the things that
are really, really important and more imminent versus the things that are still
in the planning stages. Um, and then we, as we
always do, we talked about future agenda items and you know, what
topics that we wanted to bring back in front of the, the committee, including things
perhaps related to battery and also nuclear. Um,
and uh, as I mentioned, we wanted to make sure we prioritize the,
uh, initiatives of the technology team. That concludes my report. Okay.
thank you john. And, uh, you made a comment about the committee's self valuation. So I need to amend
the f and a committee report that the f and a committee did, uh, review
the committee's self-evaluations and found that the committee was operating effectively
and appropriate with this charter. Uh, with that we'll move to agenda item
13.1. Well, let me, before I go anywhere, were there any questions from board members on
any of the committee reports? Okay, thank you.
uh, we'll move to agenda item 13.1, which is an adjunct membership approval of
agen infrastructure llc membership for membership
year 2026. Samuel branton with infrastructure
llc is with us via webex. If the board has any questions for agtech,
uh, chad sealey will present this item. Chad. Alright, thank you chairman.
up on the screen as a short decision template that explains the
background and rationale for agtech infrastructure.
being an adjunct member for 2026, uh, consistent
with the bylaws, adjunct membership requires board approval. Adjunct
membership does not have any other voting rights except for
participating at the protocol revision subcommittee in which they can vote. Uh, gentech
infrastructure is going to align itself with the independent generator segment
for 2026. And so we need board approval to approve their application.
does anyone wish to make a motion in this regard? So moved. Thank you bill.
second. So from chris, thank you. All in favor? Aye.
aye. Any opposed? Any abstentions? Okay. Gentech membership is
approved for 2026. Next is agenda item 13.2,
which is a non opt-in entity load. Jo load zone change.
uh, this is a request of lamar electric cooperative, uh, brian story,
the ceo with lamar electric co cooperative along with ramsey crisp
of se energy, which is part of snyder engineering. Are with us
in person today. If the board has any questions for lamar electric cooperative, kim
rainwater present this item. Kim?
nope. Okay. Good morning. Uh, kim rainwater
for ercot legal. Uh, we have a request from lamar electric
co-op, as you can see, to move about 60 megawatts of peak
load from the rayburn electric co-op load zone
to the competitive north load zone. Uh, lamar is present,
uh, with schneider engineering for any questions about the reason for
the change, but, uh, the protocols do require board approval.
so for our part, ercot does recommend approval,
um, mainly for three reasons. You can see there on the
cover slide that the lead time is 48 months. So
these changes wouldn't go into effect until january 1st, 2030,
which built into the process is sufficient time to
make ready the market, um, including regarding congestion,
revenue rights, auctions. And, um, we did
a little bit of research. Uh, we've, we've identified two prior
occasions at least when the board approved similar requests. Um,
one from guadalupe valley electric cooperative cooperative move from
lcra to a competitive load zone in 2014.
and then we had one more recently in 2023 when, um,
the hamilton load moved from competitive to lcra and that was
after the brazos uh, bankruptcy. So,
um, for, uh, from our review, ercot smes
have reviewed and identified no reason not to approve
lamar's request. Um, with that we would request the
board's approval. If you have any questions for
brian or, uh, ramsey,
are there any questions for brian or ramsey the principals
or for kim who's presenting this?
I don't hear any, no comments. So for that, I'll entertain a motion to
approve this change. I'll moved. Okay. Thank you. Julie, do I have a second?
second. Uh, kathleen. Peggy? Uh, all in favor?
aye. Aye. Any opposed? Okay, the motion is carried.
uh, the next thank you kim. Uh, the next is, um,
this is a mouthful. Here we've got a request from bher, power
resources and agenda item 13.3, uh, with an application
for permanent site specific exemption from compliance with paragraphs
five and six, a protocol section 10.3, 0.2
0.3, which is generation netting for ercot poll settlement
meters. Uh, neil connor with bher power
resources is with us via webex. If the board had any questions for bher
and brent del will present this item. Brent, thank you chair. You want
us say this in a simple format? I'm brent riddell, deputy general counsel
for ercot. Um, I'm here to discuss a-b-h-e-r
power resources exemption request, which was previewed yesterday by tac chair kaitlyn
smith during her report. The decision at hand
before the board is whether to approve a permanent exemption for bher power
resources from an ercot protocol provision. Our rule state that
facilities must connect to the grid only through designated metering points.
there is an exception that exists for auxiliary loads up to 500 kilowatts.
the bher facility located in big spring has been operating for 35
years. It exceeds that 500 kilowatt auxiliary load
limit, um, and reconfiguration to meet the
cap is not practical. In october,
ercot received bhe r's exemption request. At the november tech meeting,
encore supported the request and tac voted to approve it.
uh, tag noted that the facilities configuration predates the current rule.
so the recommendation before you today from our staff is that the board approve
the permanent exemption. And as the chair mentioned, neil connor, general manager
of bhe renewables is presumably joining us from big spring via
webex. If you have any questions, any
questions for brand or for the company representative, with
that, I will entertain this motion, which would be that the board accept the
application for permanent site specific exemption from compliance with paragraphs five
and six of protocol section 10.33 generation
netting for ercot poll settlement meters, which is a request from bher
power resources. Do I have that motion? So moved. Okay,
peggy. Thank you a second, julie. All in favor? A aye.
any opposed? Any abstentions? Okay, that is approved. Thank
you. Alright, the next is, uh, agenda item is
14. There are sub items under this one, uh,
regional planning group projects, which includes three voting items that christie hops
can pres present. The first one that she will present is the agenda item
14.1, which is 25 rpg 0 2 5
a ep, texas cps energy, encore, and cmp texas 7 65
kv step eastern backbone project. We know that
two no votes and two abstentions were cast attack, but tax still has
recommended the project for approval. Christie, please walk us through the project
and then we'll have an opportunity for any further comments. All right. Good morning board
members and bill, I'm glad you had to read that name of that project instead of I
, not me. What a, a great year
it's been to be a part of system planning and watch how we really have
involved here in the ercot market from the landmark decisions
that our regulators made at the puc earlier this spring,
uh, that led forth for reliability plan into the permian
basin and then building off of the work that we started last year.
the board has before you quite an opportunity to
consider a project, um, that I believe will be a big reliability benefit
for continuing to power the state of texas
both reliably and efficiently. So
if you'll indulge me, we've added a few extra slides. Just knowing
the magnitude of this project would like to give some of our newer board
members some history on how we got here. Um, the study
process that we went through and how we came to our decisions and
our recommendations that we have before you today
in 2024, as we were not only looking at the permian
basin reliability plan and how to most efficiently
and reliably serve the needs in the permian basin area,
we also started to observe in our planning forecast the
need out in the future for more transmission to reliably serve the
growing state. And what we saw in that 2030
forecast was a growing demand to near 150 gigawatts
compared to the previous years when we had studied in about the 120 gigawatt
range. So at that time we realized we could not keep planning
the system the way we always had, meaning 3 45 voltage
being the highest level to serve the customers.
at that time, our team embarked
on a process to look not only at planning the system the way we always had, but we
also looked at using 7 65 voltage
in fact building what I would call a super highway. You think about building the interstate system,
connecting your generation in your large load centers. And
we looked at how that might work with our current network.
and we provided two plans throughout 2024 and
filed some comparison documents of the commission that looked at the pros and cons of using
vote. That was back in january.
in april. As I mentioned, the commission made the decision for the permian basin
to use the import path capability at the 7 65 level.
this would allow ercot to start using that in our planning process. As
we looked at the reliability needs for the rest of the state
in the summer, we had a joint project that was submitted through our
normal regional planning group process from encore,
a ep center point and cps that would
have us continue to study the eastern backbone of the 7 65
network. So throughout the summer and this fall, ercot
completed additional sensitivity studies, economic analysis
as well as stability, uh, analysis in coordination
with the stakeholders, reviewing stakeholder comment and input.
and we delivered our final recommendation to the regional
planning group and tac considered in november of this year.
thus it's before you for board endorsement today.
so again, just a little bit of the detail as we went back and looked,
what was the best option to be able to serve the needs of the state?
there are several reliability benefits that I wanna highlight that really
led to our recommendation that's before you today.
the first is if you think about these 7 65 lines, while yes,
7 65 is new to texas, it's not new technology, it's
been in use since the 1960s in the us so it's tried and
true by using this higher voltage
greenfield new right of ways, new build
out of the system that allows us the flexibility we need
to continue taking maintenance outages on the current system. We have,
as we've continued to grow, it becomes more and more difficult each day for utilities
to be able to take the outages they need to maintain lines
to cut in new lines for additions of generation or additions
of loads to the system. So this gave us more flexibility from that
perspective. You'll see in the comparison chart
through the economic analysis, by utilizing the 7 65
network, there are reduced congestion cost on the system.
so yes, while that's an economic benefit, it also provides an underlying
reliability benefit. So if you think about if you
have a system where, uh, power can flow freely without
congestion where it has to be rerouted, that gives us more flexibility
not only where generation is sided, but once it's sided there, being able to get it
to where the consumers need it. The most
impact to customers. I know when you say 7 65,
you think 3 45 it must be twice as big. While, while it
can carry much more power across those lines, it takes a lot less
right of way to move the same amount of power. A 7 65
right of way is needed about 200 feet compared to five
and half, 3 45 ride aways to carry the same amount of power.
so just 1 7 65 line could be built instead of five
and a half, 3 45 lines less impact to the
consumers of texas as bride aways are needed to be built.
and then last but not least as we did our research, uh, in talking with
others systems that utilize higher voltage,
they seem to find that they have fewer forced outage rates on those
higher voltage lines because of the setup in their configurations.
so jumping in, uh, to the particular project in front of you, as I studied,
uh, the utilities brought this to us this summer. We
utilized, uh, during our normal processes, uh, the opportunity
to build off of the work that we had done in 2024 is
our base case to do additional analysis and sensitivity studies.
one of the things that we focused on, and we get a lot of questions is the concern
this plan was developed for load increases in the state, substantial
load increases. What if those loads don't materialize?
so we ran sensitivity studies to take a step back and look
what if those large loads don't materialize. So we ran the
reliability need based off of lower levels of load
and we still still saw the need demonstrated for this 7 65
system.
so over basically a two year process timeline,
we continue to review, do additional analysis, take in stakeholder
feedback and comments. Our project summary,
uh, this is a list of the recommendations that would be needed for new
additions to the system to build out that plan.
and so I stand before you now to, uh, bring you ercot recommendation
to move forward and request your endorsement of moving forward with
this project as well. I'll pause there 'cause I know
you probably have some questions. Okay, any
questions for christie for this incredibly important project? So
christie, what you're saying, even in our, our low load case, this is still
required for reliability. So throughout all three scenarios, low base,
high load, this is required for reliability and the best alternative.
yes, I that is correct. Um, one thing that I failed to also
point out is a part of that two year study process. Not only did we study it looking
out to 2030 during our 2024 review cycle, but
we've been undergoing with, you know, additional new loads
that have come in as we're studying 2025 looking out to 2031.
and as we've gone through this year's annual regional transmission planning process,
we also see the need for this infrastructure to be able to reliably
serve the future demand on the system. So
low, medium, high as well as we've seen that now two
years in a row in our studies that it is needed. And what's
the approximate time to construct? So what the utilities
have told us, and I know they're here if they want to jump in and correct, um,
it would be in the 2030, probably 2031 timeframe.
okay. It's all contingent upon, I know they, they've been moving
forward, um, as they have been with the permian working,
uh, to get the equipment they need. Um, but also, uh, what
would be next steps if the board endorses this, then the utilities, then it moves over
to, to the commission process or the utilities would
do, um, customer notifications for potential right
of way decisions. Um, and that would take, you know, probably
most of next year to work through that process at the commission before they can actually start
building. Okay. Thank you. Christie, when did, when did
you sort of freeze the load analysis? Uh, did you, is it,
is it sort of july timeframe that you were using data from
or, or more recently than that? So this particular
review on this case was done, um, they submitted
it based off of the need that we saw in our 2024 analysis.
mm-hmm . So that load was froze, um,
in late probably april, may of
last year. And that was that study process. Now
fast forward we're, we're doing a similar study where we also see the need
during 2025 and that load, uh, wasn't finalized. If you
recall, we went through, uh, a forecast, um, discussion with the commission
and that was locked in in june. So, so june timeframe and
since then there's been more load added to the queue, right? That's correct.
kristy, uh, can you comment on our confidence level around
the cost of the project? So the costs,
uh, that are in this were based off of estimates that
were provi or generic type estimates that were provided based on the information
from last year. Um, I would probably defer
to the tsb counterparts, um, that have been doing negotiations with,
um, vendors for securing supply chain. Um,
one thing I would note, um, I know there was debate in the
past, um, from some previous larger transmission projects about
how the cost went up in time. And what we found is we implemented a new
practice this time around. So when we estimated the mileage that would
be needed for these, we added a 20% adder to the mileage
because we recognize when you go in and try to cite
where that line is actually gonna be placed, it's probably not gonna be a straight
line from point a to point b. And so, uh, we do add increased
mileage to account for that. Um, because every
turn on the, on the build of the system does add, you know, additional equipment that
needs to be accounted for. Thank you.
okay. Benjamin, do you have a comment? Uh, just a couple of questions. Why 20% for
the cost out from, we went back,
um, historically when we were doing it just a straight line
approach, what we saw on the average it was about 18% when
they would actually then come back to the commission. And so that's why we chose 20%.
it was based off of historical, uh, information.
so it didn't factor anything into like the geography of the area of this going through.
no. Uh, so this is about the same size as the permian
basin plan, which had a monitor. Is there any consideration for having a monitor or some sort of
cost reporting requirement for this plan? For this? So my recollection, um, how
the permian basin monitor was established was during the commission
deliberation process where they added that into their final
order for the permian plan to keep, um, overview
of schedule and cost, um, because of the importance of the timely
build out for the consumers in the permian. And that is actually being
run by and overseen by the commission. So I would defer
to, to commissioners, uh, whether that's something they would want
to entertain or a consideration of, of some version of that for
this project. Yeah, I'm happy to weigh on, on, in on that ben.
so I've talked to pc executive staff, um, about
this. I think at minimum we will take the construction reports
that will be filed by the tsps and compare those to the cost
estimates that, um, are in this approval if it gets approved so
that we have a benchmark that we can compare against. I'll continue to talk to
connie and barksdale about, you know, the portal that we've set up and if we have money
to expand the data that we put into that. Um,
but I think at minimum we will take the construction reports and do a comparison
and we can post that information online. 'cause I too, you know, uh, cor was
one of the first projects I was, I was involved with when I came to the commission
and so I'm, I'm very aware of, uh, the public's desire to know
cost overruns if schedule slips. And so I think it's important
given the, the magnitude of this and the cost that we are transparent about
any cost overruns and slips in schedules. So we will, we will do everything we can at the commission
to, uh, to make sure that that information's public so that everyone from the governor to the
legislature to, uh, the public at large knows, knows what's going on with this
project. I I appreciate that. Thank you
christie. My question has to do with the, uh, execution of the project.
can it be phased in and let's say
to match load expectations because that is
the load forecast seems to be so dynamic at this point. What, what was
deliberated about in terms of basing
the project? So I, I like to think about what's before you, if you
think about it. It's, it's a loop. So there were three set points
that were decided they're already established by the commission as a
part of the permian basin plan and then this completed the loop.
um, if you think about what we're recommending here, again, it's the super highway
and what it's giving us the opportunity, the points that we chose when we were preparing
this were strategically chosen, whether they're already large load centers
or they're generation pockets where we see a lot of generation on the system
today. So those are knowns and that helps us more efficiently move
power around. But as that load materializes over time,
we know it's important to know where they're gonna be located so that you can build transmission
to them. I would foresee this as being your interstate
as we, and it's needed based off our sensitivity, whether that
large load materializes it or not. But what this provides
you is when those new large loads or new generation comes to the system, where
do you build the exit ramps? And we have the flexibility to be able to do that
with a lower voltage.
this is a little bit off of normal protocol, but given the scope
and size of this project, if, uh, representatives from a ep encore
or cps or uh, uh, cnp would like
to comment, we're willing to listen.
okay. I don't see anybody jumping up. Alright,
carpenter. Okay. Okay. We do have a commenter. Okay.
uh, yes, this is mark carpenter, senior vice president with encore electric delivery.
um, the cost estimates we have in this we think are prudent costs
given the information we have at the time, things like tariffs and
right away costs. And some of those things are variables that, uh, uh, we've
taken our best guess and, but we're very comfortable with the, with the
cost estimates and I believe the other two tsps would say the same thing.
okay. Thank you. That's helpful. Anybody else?
christie, any closing comments? No, I, I would,
uh, thank you for your consideration. As I said, it's been, uh,
a very long process to get to here, um, a lot of
review and and consultation. Um, so I'm excited to see what your
decision is. Okay. With that, I'll entertain a motion
to approve the 25 rpg 0 2 5
a ep texas cps energy encore and cnp texas
7 65 kv step eastern backbone project. So
moved. Okay. Thank that was bill. Yeah. Okay. Uh, second?
yes. Second. Okay. Got two of me, linda and kathleen. All in favor?
aye. Aye. Any opposed? Any abstentions?
okay. That project is approved. Christie, would you proceed with
the next agenda item? Sorry. And lemme go ahead and read it. It's agenda item 14.225
rpg 0 2 2 encore, and a psc drill hole to sand lake
to solstice 7 65 kv line project.
all right, so we've, we've talked about from the 7 65 perspective,
when we looked at the strategic transmission expansion plan to
reliably meet the needs of consumers into the future, we had the permian
portions, we have had the eastern portions you just considered. If you think about
out in far west texas and the permian basin area, there
are three import lines that were approved by the commission.
they all end there and this project was brought forward at the same time
based off of the, the same analysis we discussed, uh, on the other project
to close in those three endpoints so that we would have a fully
networked 7 65 backbone on the system. 'em,
we went through that same review process in, in considering, um, looking
at what we had analyzed in 2024, what we had analyzed in our
2025 planning process working with the regional planning group.
and we still saw, um, the reliability need. And I think from this
perspective, I look at it not only as reliability but resiliency.
it'll give us more flexibility in the future as we're looking at outages
that may need be needed for, for maintenance to be able to have that system fully
networked. So the request before you, um,
is to endorse the need for this project based
on our reliability planning criteria. And
would you replete the estimated cost again? Sure, it is,
um, I believe it's $742 million.
okay. This is just for line cost. Uh, the substation costs were
already a part of the permian plan approval. Okay.
any questions for christie on this? No
questions, no comments. Uh, hearing none I will entertain
a motion to, um, approve the 25
rpg 0 2 2 encore and a psc drill hole to sand
hole to sand lake. So to solstice, excuse me, drill hole
to sand lake to solstice. 7 65 kv line project.
so moved. Thank you. Chris. Do I hear a second? Second,
peggy? All in favor? Aye. Any opposed?
any abstentions? Okay, that project is unanimously
approved. Bill, before we go on to the next one, I'd like to just take an opportunity to
send a thank you to our teams that are probably watching. Um,
they've spent a lot of time and analysis not only in the planning
department, uh, coordination, working with dan's folks, the the markets folks
to look at some of the economic analysis. So it was a, a large effort
by a lot of folks at ercot to bring this forward. Um, I think woody
likes to joke, if you were a planning engineer in another iso, you
may get to work on one u line in your career. And, um,
the planning engineers on our team have had quite the past two years.
so, uh, thank you chris.
with that, we're gonna proceed to the third voting item, which is agenda item 14.324
rrg, r pg 0 2 0, encore connell
3 45 slash 1 38 kv switch and connell to
rockham 3 45 kv double circuit line project option
one. Christie, would you present that to us please? You bet. So this is
$110 million, uh, project that was brought forward by
encore. If you recall the last couple of board meetings, dan's been
providing information in the far west texas area. We know that's an
area that is growing. Um, while there are a lot of projects
that have already been endorsed that are being built in the area, as we continue
to see additional demands on the system in far west texas, you're gonna need
additional infrastructure to continue supporting them. And so this project was
brought forward by encore, went through our, uh, review process
and we saw reliability need in that far west as additional loads
would be continued to be added to, um, do
upgrades, um, to the system in the region to eliminate
or, um, thermal and voltage violations in that far west
texas area. This project was unanimously endorsed by
attack. Um, and so with that, I would
request the board's endorsement of this, uh, encore
project in the far west area, uh, which totaled about $110 million.
any questions for christie? One question is yes
for this project, christie, how, how fast can this be done and what, what
will the timeline look like? Um, lemme let me take a quick look at our report
here. Um, what the expected timeline? Um, I think I
know one disclaimer while I'm looking up that, that timeline, um,
it's, it's needed for in-service in 2026. So
this is looking at a project that would be next year. There is 13 miles
of right of way that are required. So they will have to go through, uh, the commission
ccn process to establish that need and
get approval for the siding of that new right of way. Um, and I know one disclaimer
that the utilities typically put in when they give us timelines on how quickly
they think they can build the project, um, is that it's
dependent upon, um, outages. So when we talked about approving
the 7 65 plan and how our system is utilizing
its full transmission capability today, it becomes harder and harder to take those
outages. So it's also dependent upon weather and being able to take those outages
needed to, to upgrade the systems. Thank
you. Sorry. If, if you don't mind, encore, representative
kin to speak to that. Yes, liz jones on behalf of encore.
um, I, I do have some updated information in response to your question.
because of the delay in processing this rpg submittal
and because of customer needs, encore went ahead and filed
the ccn proceeding with the puc and that
is nearing its end. And so there will be some time savings
as we move forward to build and operate the
facilities. So don't leave liz, any questions for liz while she's
up there? Okay. Alright, thank you.
that was helpful. Any other questions or comments?
I'm not hearing any, so I'll entertain a motion to approve the two four
rpg 0 2 0 encore con connell 3 45, 1 35, 1 38
kv switch and connell to rock hand. 3 45 kv double
circuit line project option one. Do I hear a motion?
so moved. Thank you julie. I have a second. Second. Okay. Who is that? Bill.
okay, thank you. All in favor? Aye. Any opposed?
any abstentions? Okay. Uh, ercot board has endorsed this project
for approval. Next, we'll move to agenda item 15, commercial
markets. The first agenda item is 15.1
market price correction, incorrect generation to be dispatched, values
used in scad gordon drake is gonna present this item. Gordon.
thank you chairman flores and members of the board. It's my pleasure to be here, uh,
to present this potential price correction for your consideration, uh,
to talk about the events that that led to the issue in our market systems
and request board approval to correct prices for operating day october 14th.
on october 14th, um, we had, uh, an input
into our generation to be dispatched value in our market systems.
that is a, a parameter in our market system that determines how much, uh, generation
do we need to, uh, instruct to, to generate in order to meet the, the
load. Um, and a key input into determining that generation two
b dispatched value is the, the load forecast that they, that the controller
is using and our market systems observe. And we had been,
uh, using our external short term load forecast as an input to our market
systems when we noticed an abnormal spike in the, um,
in, in that load forecast. And the control room has the ability
to switch to another load forecast that more accurately reflects the
expected load pattern. Uh, as they were executing that switch, uh,
because of the, uh, the observed spike, unfortunately, there was a,
a software bug that prevented that from, uh, appropriately executing.
and so that, that that price spike, so that load spike was reflected
in the calculations for the, the generation to be dispatched parameters
as a result that the, the generation to be dispatched parameter,
um, impacted prices between, uh, eight 10 and 9:15 pm
resulting in high system-wide prices, uh, in between, uh, eight 10
and 8:15 pm so all the prices were impacted within that window, but
we, we noticed, uh, particularly high prices in that eight 10
to 8:15 pm window. We identified this as
a software issue, uh, on october 23rd. Um, and
as thus could not meet the, the two business day timeline in the protocols
in order to correct prices before they went final. And that is why we are
here today requesting your approval. The, the cause of that software
bug that prevented the effective switch between the load forecast was identified and
affix was deployed near the end of october. We communicated the,
uh, event in our investigation to the market through two market notices, uh,
the first on october 24th, uh, providing the same details that
we are sharing here today. And on nover november 17th. Uh,
upon concluding our analysis, uh, and informing the market of our, uh, intention to,
uh, present it to the board of directors for approval at this meeting,
we determined that the impact of prices met the significance criteria
in our, in our, uh, nodal protocols, um, exceeding the thresholds
of, uh, an impact of 2% and also greater than $20,000
or 20%, and also greater than $2,000 to a single counterparty.
we had 18 counterparties that met the first criterion and three counterparties
that met the second criterion. And the absolute value
to counterparties, uh, to a single counterparty was a maximum
of $140,000. Um, which, and the maximum percentage
criteria of nearly 22% and nearly 150% for
the second criterion. Overall,
the impact to ercot settlements was just more than $800,000,
um, representing the shisha of 4% of the total market settlements for that
day. Um, in summation, we had, uh,
an issue in our software that led to, uh, an impact to an
inappropriate impact to prices for operating day october 14th, which met
the significance criteria in our protocols, and we are requesting
board approval to correct the prices, uh, for the real time market for operating
day october 14th. I'm happy to answer any questions. Okay, chris,
uh, just to comment, uh, gordon, I would say good job on describing
a tough and complex issue. Um,
I, I, I appreciate it. This isn't, it's not easy to describe and explain.
thank you. What has happened here, and I'm glad there's a fix.
any other questions for gordon or comments? And
you provided your assurance that that particular issue has been fixed, so yes,
sir. Shouldn't have a repeat occurrence. Okay, thank you. I don't hear any other
comments or questions, so recognizing that, uh, I'll entertain a motion
to approve the price correction as presented. So moved. Okay. Thank you, chris.
any second, sir? Okay, peggy, thank you. All in favor?
aye. Any opposed? Any abstentions? Okay. The price
correction has been approved. Next, we're gonna move to agenda item 15.2.
keith collins is gonna give us a commercial up, uh, markets update.
all right, good morning. This is an informational discussion
and we'll cover some of the key initiatives we're working on,
uh, over the last several months, but also moving forward as well.
and we'll cover, uh, our current credit situation in terms of,
uh, the, uh, we haven't seen any significant market credit or settlements
related items, and we'll cover that in a second. So, uh,
starting off, we've, we've discussed a couple of these, uh, a few times, but I think it's important to
highlight again that, uh, the first key initiative we're working
on is dispatchable reliability reserve service. We did cover this a bit more yesterday,
but just to give a few more highlights, we did have a study,
uh, from a more aurora energy research that showed the,
uh, the potential benefits of, of the, the various
permutations of, of drrs. We'll talk about that in a few minutes.
we did post the two nprs, uh, our drs an ancillary
service version under 1309 and drs ancillary service
plus under 1310. And we will be hosting
a stakeholder workshop here, uh, a week from, uh, a
week from tomorrow, uh, at the met center to with aurora
to discuss the report with stakeholders. Uh, secondly,
uh, our residential demand response program. We had a,
uh, we had a, uh, had good discussion with stakeholders
at the wms on november 5th. There was a lot of good feedback that
we received at that. Uh, during that discussion. We are taking that feedback,
uh, and, and the points raised during there and working on revising
the proposal based on some of the key points that we, we, we
learned during that discussion. We expect to have, uh, some, uh, a modified
npr, uh, early next year. And then the
final point is the energy attribute certificate program. This
was something that we discussed in june at the june board under npr
1264. We have been making significant, uh,
progress on that. Uh, I, I will note that we are have been working with stakeholders
on a sort of a lightweight option that had been discussed at the board.
and, uh, ultimately we have, uh, provided some updates to
the prs and the wms on a request for a quote for a
vendor. Uh, ultimately part of the next steps will be to select a vendor, but we have
at least have, uh, uh, a draft version of, of that request.
and we've made some draft comments to, uh, the stakeholders regarding
1264 to better define the processes, roles and responsibilities.
and sort of the final point that I wanna make as, as part of our key takeaway, obviously, rtc,
all of this has been going on while we've also simultaneously been working on rtc
plus b, but I do want to sort of note that there are some stabilization efforts
going on over the, over the course of the next few months. We mentioned some of those yesterday.
I, uh, thankfully that it, it, it has been, uh, a relatively smooth,
but, but again, there are some cleanup items that we want to just not ignore as we move forward.
and then talking about market credit update, there have been no significant issues,
uh, in either the settlement or credit related defaults. Uh,
when we, we view our total exposure, there's generally a seasonal pattern, and we saw
a summer peak, uh, 1.84 billion, and that's come down,
uh, to about 1.57 in october. Just a update
on npr 1277. This is something that we
discussed, uh, starting at the end of last year, beginning of of this year,
we did have an npr, uh, that went through the process to
help improve the collateralization requirements and the impacts of high
volatility that passed the commission in november.
and we do anticipate implementing that in early 2026.
the other item that I want to highlight is that we have been, uh, working
on a credit, uh, our credit staff is working on an
analysis that evaluates and measures market stress scenarios. And we do look
forward to bringing that through the stakeholder process, uh, in 2026.
uh, that concludes my update, and I'm happy to answer any questions that, uh,
the board may have. Any questions for keith?
okay. John, do you have a question? Yes. Keith, as you look out over time, um,
be beyond the immediate things that you're working on, are there any
things on, on your roadmap that would continue to send better price
signals to the marketplace about the need for dispatchable generation?
and if so, can you give us a bit of an idea of what kinds of things you're thinking about?
I, I think the, the most immediate thing that we're, we're looking at is our,
our dispatchable reliability reserve service. That's, that's really our focus. We think that
has the ability to do precisely what you're hitting on is you,
uh, incentivize dispatchable resources, uh, within
the market in, in order to address the, the reliability concerns,
the growing relian concerns we're seeing, is it enough
by itself? Uh, what, what we see, and we'll talk about this in just a
few minutes, is that, uh, the combination of, uh,
what we saw in senate bill six and the drs ansley
service plus version in combination should be enough
to, to address the majority, if not all the issues, uh, that, that we've
studied. Okay. Thank you.
okay. Thank you, john.
I'd like to, I mean, there's also the, uh, the reliability standard
study next year. That'll be a good indicator too.
okay. Any other questions for keith? Alright,
keith, I think you have the next agenda item, which is, uh, 15.3
dispatchable reliability reserve service, or as we call it, drrs.
drs. Yes. Thank you. Thank you, mr. Chairman. Uh, I'm here to present,
uh, on the study that was done by aurora. We have representatives from aurora here
as well, aurora energy research in the event that there may be some questions from
the board, uh, they're here with us today. Uh, I'm here to
not present the full report, but to give the highlights, uh, that we, and key
takeaways of, of that, of that report. Uh, this was presented
to the commission a few weeks ago, and we, we plan to
have, uh, some dialogue with stakeholders, as I said earlier, in a couple weeks, to, to go
through the, the specifics of the report.
and so, um, starting with the
conclusions, and I think this was, was, was kind of key, was that
there is no silver bullet, uh, market design solution, uh, either
on the load side, uh, with, with potential load curtailment or,
uh, on the generation side market design. However,
and this gets to the question that, that, uh, I just just responded to,
is that when you, when you do look at, uh, the impacts of these
different, uh, tools, they do have significant effects individually
on improving, uh, the resource adequacy and the potential for,
for outages in the future. And in particular, the,
the drs ancillary service plus case, as opposed to
some other analyses we looked at. And we compared different alternative scenarios. And
that included, um, the dispatchable reliability, reser
reserve service that was presented in 1309. We looked at that as
just an ancillary ser as a, as primarily as an ancillary service design. And
we did look at the ordc, um slash adcs as they
are now, uh, in, in the market. And we looked at modifications there and said, well, would those be
significant enough? And what we found was that the, the drs
ancillary service plus scenario adds more dispatchable
capacity at lower costs and provides greater resource adequacy
benefits under, uh, different load and, and extreme weather conditions.
and so it, it did provide the, the most benefits at, at the
lowest value, at the lowest cost. And so, uh, uh,
so the study did a good job of, of evaluating that, that universe. And,
and so when we look at the combination of that drs an
service plus in combination with the senate bill six programs
to, for large load and, and large load curtailment, you can end
up in a scenario where you'll cover a range of potential outcomes that
that could potentially exist.
all right? And so the, the first slide here is essentially an
evaluation of, of the status quo market design, uh, under,
um, under, under stress conditions, either a winter storm
or a summer heat wave. And the winter storm, uh, this is, is the equivalent
of winter storm elliot, not necessarily winter storm yuri,
winter storm. Elliot was, uh, uh, essentially a christmas
time, uh, winter storm in, in 2022. The summer
heat wave that we looked at was just, uh, the summer we experienced a few years ago in 2023.
so these are, are, uh, relatively recent events. And
if we apply the same conditions under the load conditions,
uh, and by load conditions, we looked at the ercot 2025
long-term load forecast and an aurora, uh, what
they call the aurora central case, which is, is a more moderate demand scenario.
uh, that what we find in both scenarios that we see, uh, the,
the duration, uh, the magnitude, which you see here
represented in the bars in terms of the outages, the duration, uh, in terms of hours,
uh, you see around that, uh, 15, 11 to 15 hour range. And
the total amount of, of load shed, you see are in the gray boxes under the chart
of, uh, in, in, of about 60 to over a hundred gigawatt
hours of, of load shed. And then the costs are represented in the
bottom chart in terms of how much cost at the, at
the value of lost load would we expect, uh, to
occur during those events. And you'll see that being, uh, ranging for about 2 billion to,
to just, just under $4 billion. So this is under the status
quo in 2030 in the event that we had, uh, an event,
uh, like, uh, like winter storm elliot, or like,
uh, uh, a summer event like 2023. So it is, it is a reasonable
to assume that those could potentially occur in the future, and this is the outcomes that we
would anticipate based on their analysis.
alright, so we asked, we asked the aurora staff to look
at, uh, the senate bill six. Uh, we knew that that had
the potential to improve the scenarios. And, and what
we see is, is essentially mixed, uh, that under some scenarios it has significant
benefits under other scenarios. It, it, uh, has some benefit, but, but limited
effects. And, and so we'll start with the charts on the, on the left,
which show under high load growth scenario, this, this being equivalent to
a significant amount of large load, uh, inter interconnection
by 2030. Uh, and what we see under those scenarios that, that
flexibility afforded to you under those scenarios under emergency
conditions. And that's, that's important that a lot of that, uh, the
access to that capability occurs, uh, not necessarily under market conditions, but potentially
under emergency conditions. You can, you can, uh, potentially
address the, both the summer and winter events and
that, that you see there by the elimination of those bars and elimination
of the costs on the right hand side. If you end up with a moderate
load growth scenario where you do have, uh, data centers coming, but
maybe perhaps not at that, that high level that is envisioned in a long-term
load forecast, then what we see is that there's a more
limited effect that those large loads can have on on outcomes
and that can lead to significant, still, still have significant outages
remain and significant costs as well. So, uh, again,
this is a scenario where the, the senate bill six large load, uh, uh,
curtailments under emergencies can have positive effects. But again, it's not a
silver bullet. All
right? And then concentrating on the drs
ancillary service plus scenario, we find that, again, it
has the potential to help alleviate both under the high and the
moderate load growth scenarios, but it doesn't eliminate the scenario.
uh, what we do also look at is, uh, uh, the storage
included and not included. And so that does add another wrinkle. The, the khaki
color that you see here is has the storage excluded the yellow color, has it
storage included. And what we find is that it's, it's mixed in some
scenarios, the storage can help in some scenarios. The storage doesn't
have the same benefits as, as excluding them. Uh,
and again, I think that's primarily related to duration. When you're, when you're
evaluate, we evaluated this with four hour storage and four hour storage,
uh, under, under summer conditions tends to be, uh, uh, more
effective under the longer winter term scenarios. It, it, it tends to be a little less effective
than dispatchable thermal capability. And so really
what we see is a reduction, uh, when we have ansi service, plus
we see a reduction in the magnitude, the reduction in frequency, the
reduction in the number of hours that we see impacted in a reduction in the costs. But again, it
is not a silver bullet and, and we're cognizant of that, but it does have a significant
impact on the outcomes that we see. And interestingly enough too, is that
where the, under the high growth scenario, the large loads
tend to to be more effective. We see under the moderate load growth scenario
that the, uh, drs ansley service plus, uh, tends to be,
um, a bit more effective in addressing concerns. And that, that, that shows they're a bit
complimentary, if you will.
okay. And then comparing the drs ansi service plus to alternatives,
we looked at the cost, we looked at the amount of, uh, dispatchable
generation that we see added, and that's sort of a proxy in their, in their report, they
show that ultimately the, the drs ancillary service plus
scenario does have a greater level of reliability benefits
as compared to the others. And so, um, but, but in this chart, we're covering
the costs and, and the quantities. And what we see on the far left chart
is this is the all in system costs under the different scenarios,
including the status quo. The chart in the middle,
uh, effectively does the, the comparison for you. It's comparing each
scenario, the ansi service scenario, the ansi service plus scenario,
and the ordc scenarios. And it's comparing it. And, and we
see in the middle chart that ultimately the cost associated with
drs ans answer service, ansley service case, uh, uh,
we see a net net cost of about 700 million in the
drs anser service. Plus case, we see a net cost of 400 million.
and we see on the rdc case a cost of about 2.2 billion.
and so very different cost profiles depending on which scenario
you take. But, um, what we see in the final chart is
how much dispatchable capacity relative to the status quo do we see,
uh, under the ancillary service scenario. Uh, we see 900 megawatts of incremental,
uh, capacity. Again, it's a very incremental program. Uh, it
is, it is designed as a, primarily an ancillary service. And so
it's, it's going to have incremental effects. Uh, whereas the ancillary
service plus case, we see five gigawatts of additional dispatchable generation,
and what we see is a reduction in the amount of solar, uh,
and the short term and, and even some of the four hour storage. And
then under the ordc, what we see is an increase of,
uh, 1.7 gigawatts of dispatchable thermal capacity. But
we also see solar. We also see one hour battery. We also see two hour battery,
uh, storage as well, uh, in addition. So, uh, in terms
of additional dispatchable thermal cap capacity, the
drs ancillary service plus is, uh, we see it's the lower net costs,
we see it's more dispatchable capacity. And when we translate that into reliability,
it has, uh, greater reliability benefits compared to the other scenarios as well.
so in terms of next steps, uh, the two nprs that we've been talking
about, the 1309 has the urgent status, and the
1310 will also be brought up in the stakeholder process. It's
important to note that what we're deeming the release factor, which
is a part of the ancillary service plus scenario, uh, that's what creates
the reli. The, the resource adequacy benefit is this release factor.
ultimately, uh, that is going to be in an off position until approved
by the, the commission to, to switch it into the on position.
and then ultimately, the energy storage under thir, uh, npr
1310 will also be in an off position until approved to turn on
by the puc. And then, and then finally, as I noted,
we will be having a stakeholder discussion on december 17th. So again, a week from
a week from tomorrow, we will be discussing with stakeholders all the various, uh,
addressing all their various questions. And we've been receiving several of them, uh, but,
but, uh, mostly pointing to pointing them to the discussion that we have, so we
can all hear it, and, and I'll have, uh, uh, a common set of understanding of what the findings
of the report were. So, uh, I'm happy to answer any questions. I also have, like I
said, the, the representatives from aurora to answer any questions that you may have. Uh, keith,
I'll start with the questions. Let's go back to, uh, slide six, if you would.
yes. Looking at the right hand column. So we saw a decrease in battery
and storage, right? Uh, so what we have in that, that right
hand chart, what you see in that middle scenario right, is a, a decline
in, and this is relative to this status quo case, correct? Right. So you're
not, you're not, you're not retiring those resources, you're just adding
less, you're not adding them. So the, my question is, are they not being added because
of a policy consideration or an economic consideration? It is
primarily because of the economics of the drrs ansi
service scenario. So the as plus, as plus scenario correct, uh, creates a
lower economic incentive for capital deployment for storage companies.
is that correct? For the, for storage and for the, um,
for the solar as well. And, and just to point out, this whole, all of the modeling
on this page is done with the batteries ineligible to participate,
correct? Correct. As the prior slides, that's right. We did see scenarios with eligibility
inclusive and non and non-inclusive. So this one,
all of these scenarios show without batteries being eligible. Correct. But that's why I was trying to dis grade
is how much of it's because batteries are ineligible versus economics that were causing that
capital and not be deployed. And, and, and there isn't. There
is a chart where, where pablo is, is noted. We have a comparable chart that
shows the battery's eligible, but those batteries eligible are the four
hour batteries, right? So what we'll see there in that chart is an increase.
um, so the increase in the dispatchable capacity will won't be as high. So
it's five gigawatts in this, it'll be a little bit less, and then you'll have
a, a value for the, um, the four hour storage, but
then you'll, you'll have reductions in the short hour, the short duration
storage, as well as the solar. Okay. Any other questions? There's
lots to digest. Okay, chairman, thank you, mr. Chairman. Uh, keith, I
think it would be probably beneficial for the board members to hear, uh,
to hear you respond to a question I asked at our last open meeting. Um, you
know, some of the, the critique I've heard of this has been around
a lot of these charts, and a lot of the discussion sounds similar to the discussion around the pcm.
so can you kind of compare and contrast this to the pcm
market design that we had, uh, so many discussions about previously?
absolutely. And, and if you just bear with me with a moment, I'll sort of start with
an analogy and then we'll get into the specifics of how it can differ from
the, the, the pcm. So I think there, what we've heard
from folks is, is potentially some, um, some
reactions that are, well, this looks like pcm or this is a capacity market.
and, and I think part of that is that when you're seeing something that you're,
that you, you've never seen before or is new to you, um, and we see this with
lots of innovations and things that you're, you're gonna describe it like something, you know,
and for example, if, if you're, you're going to the ocean for the
first time with, with, with a child and saying that you see a,
a, a big creature jump out of the water and, and the child says, hey, look at the big
fish. Well, um, a whale is not a fish. Um,
but you can forgive them for, for mistaking the difference between the two.
and so I, I sort of look at these reactions the same way, because
the, the primary difference between the drs ancillary service plus
case and the pcm is, uh,
we talk about, uh, our market as an energy only, but that's
not entirely true because we have ansley service markets.
we have a crr market, we have an ers process, so we have
things that compliment the energy only market, and one of them is ansley services,
which is, which is what drs, uh, is designed
to be an ansley service. And so what we have done in this release
factor process is to use that ancillary service mechanism
and to allow it to enhance resource adequacy.
and so it will be paid like an ancillary service. It'll be settled like an ancillary service.
and, and so it's using that mechanism. And so we don't
have a mechanism like that today. Um, and it's my understanding that no
market has a mechanism quite like that. And so it is
not a separate mechanism like you would see with the
capacity market, like you would see with the pcm that sits outside of
that existing structure. And so really, we're using
ansley services to promote resource adequacy. And I think that's
very different. And, and, and I think one of the things that I think of is
there, there are, there are different ways you can achieve resource adequacy. Um, just
like you have many creatures swimming in the sea, but not all of them are
capacity markets. And not all of them are pcm in this case. It is in fact an ancillary service,
um, um, to promote resource adequacy.
it's kind of a fishy analogy. Uh, anyway,
any other questions or comments on this particular subject? There's
a lot to digest here. Thanks for this analysis. And all
of us are still digesting the very thorough aurora report.
um, was any analysis done looking at like a
$0 price floor and $0,
um, any price floor at all? No. We,
we did not look at, uh, price floors as, as part of the analysis.
okay. Okay. Public, did you want to, I, I was just gonna add
on to chair thomas's, uh, chairman gleason's question. And
I, I think I, the important question that, that I also hear
often time and as we discussed this, is why does this question
keep coming up? Why, why are we continuously trying to find
something to address what is either a perceived
or real gap in the energy market? And
as you look back historically over the last 10 years, you see a
trend of resource additions onto the grid that has been fairly consistent
and steady defined by the market construct that we're operating today.
and its primary focus on economic signals being the,
um, what drives favorability and for success in the market.
what's, I think not fully considered in our current market design,
and, and I alluded a little this a bit to this in my comments last night at the annual meeting,
is that, you know, the market design was fundamentally put in place at a
time when all of the resources that were
operating with that, uh, construct were fairly homogenous. They
were thermal resources, long duration. There were coal, there were nuclear, they were in
actual gas. And so what the market design, which was intended to
drive efficiency did, is it drove, it was driving efficiency among
a resource set that had the same operating and reliability characteristics
or very similar ones. And it would replace less efficient thermal
resources with more efficient thermal resources, with the introduction
of a completely different set of resources that have
different operating characteristics and different reliability characteristics like
wind, solar, and short duration resources. The same market
construct, which is designed to bring efficiencies only
is now doing so with resources that have very different reliability
characteristics. And, and that's the reason why this issue exists, is
because the original intent, which was always assuming to deliver reliability,
because the reliability characteristics were the same in the, in the
construct and in the resources that they were going to, it was gonna be supporting. But
because those characteristics have changed so meaningfully, we now have, uh, over
70 gigawatts, 70 gigawatts of renew of, of
wind and solar installed on, on the ercot grid. We reach periods of
time where 75% of the energy delivered in the ercot
system is coming from just wind and solar. We have a completely different
resource mix. And so the economic incentives have remained fundamentally
the same. The operating characteristics are radically different than what
they were 25 years ago. So that's the reason this
question keeps coming up. We are trying to find a way to continue to sustain this market for the next 25
years, and now we're facing a large high growth environment ahead of
us. And so we're trying to figure out how do we keep up with that growth? How do we
make sure that we can be ahead of that growth so that the bedrock
of this organizational's mission, which is reliability, never falls
behind the needs and the expectations of texans on a business
or on a residential front. And so I think that's really the important question, is to acknowledge
that we've got this issue fundamentally, and that the underlying system has
changed. And so we have to find a way to continue to support those
original goals of this energy only market. Those original goals were
presumed reliability and improved efficiency with subsequent
investment in subsequent refreshments. Those original goals are not
being met in the same way today because of the very different characteristics
of that resource mix on the grill resource mix on the grill on the grid.
thank you. That's helpful. Any other comments or questions?
okay, so I'm sorry, real quick, sorry. Um,
pablo, you said one comment about building for the next 25 years. So do you think
drs if used correctly, can be what is solving
the problem for the next 20 to 25 years? I, I think it has the potential
to, because it's, it's, it's tied directly to
the, um, to the shortfall
of a balanced resource mix. Looking forward using that reliability
standard, the intention would be use the reliability standard analysis to
identify if in the future we're gonna lack the appropriate mix to meet reliability,
and then find the most cost effective way to get there, to get the, that
answer. And so if it's constantly providing real
time in injects into the market, looking ahead at a need to
anticipate the needs of the market a few years down the road, which that reliability standard
analysis will do, I think it has the potential to keep up with what is needed.
and this is based on, you know, a set of assumptions. It's looking at 2030, it's looking at the assumptions
we've put forth, which was the high load case, the assumptions that aurora put forth, which were the
moderate load case. And it says, okay, based on those assumptions, here's the numbers.
but as that changes, which changes every week, it'll be able to adapt
to those needs by constantly having that view of looking forward and trying to
fill in that gap. So I do think it has the potential to be a sustainable part
of that solution set. And, and frankly, I think it's a, it's a relatively low
risk way to put something into the toolbox that as
the commission and the stakeholders in the market look at that growth being
realized, we start to see is the economic growth actually materializing to
the degree and to the speed that, uh, that we anticipated? May we
now have a tool that we can, you know, put in place and, and see how that works.
okay. Any other questions? So keith, update us on one
last issue. So this is under consideration now, and what, what are the next steps? When
does the board see this again? So, so, um,
with regards to the drs ancillary service scenario
that you'll see in june. Okay, my understanding and discussions
with, with, uh, ta leadership is they're, they will
bring both, but if they can't do both at the same time,
1310 will go slower. 1309 would go faster. Okay. As we discussed
yesterday. As discussed yesterday. Okay. I just wanted the board to recognize
this is coming back. Any other questions, comments?
uh, do we need aurora to comment or we good at this stage?
okay. Looks like we're good. Thank you, keith. Thank you. Uh, the next is agenda item
16, system planning operations. There are two sub items. The first
is agenda item 16.1, system operations and winter
weather update presented by dan woodfin. Dan,
good morning. Got, uh, three items I wanna talk to you about this morning. Uh, the first
is kind of a preview of, um, winter, maybe
not moving. Okay.
okay. Um, so, um, our meteorologists are expecting
a cooler winter over average
across the entire winter this year than what we've seen say the last four
years, but that still would be above average
temperatures over the course of that winter. We've just seen such hot winters,
uh, the last, uh, four years that we could still be
cooler than those. And on average, high, hotter and all. They're
also expecting that we'd see, uh, from a precipitation perspective,
that we'd see drier than normal conditions over the course of the winter.
now, as, as we talk about every year, even in an above average
temperature, uh, period over the course of the whole winter, that
doesn't mean that we will not see significant coal spell during
or one or more significant coal spells during that winter.
and I think there, there may be more potential than that this year, since we've
already started to see some disruption of the polar
region. Uh, and it's caused really the northeast quadrant
of the us to see pretty cold weather already this, uh, so there's
always the potential for that. And that means we've, uh, collectively as an industry need
to be prepared for it. And, um, pablo talked
about this morning, some of the, the preparation work that we're, we're doing, uh,
through our weatherization program.
the next thing I wanted to talk about was we, we've talked about the last several meetings that
we're doing various studies related to ride through characteristics
of these new large electronic loads. And jeff talked about
yesterday that we're proposing, and the board has now made that a
priority revision, uh, to put in place, uh,
ride through standards for on a going forward
basis for these large electronic loads. But these studies
are really studying what's, what's already on the ground or what's already been approved to energize.
and so before we got too far into those studies, we wanted to give the opportunity
for the large electronic loads to provide updated
information so that we're not as having to assume kind of the most
conservative ride through characteristics, but if they have the
capability to do better than that, they can. They, we issued an rfi
that would allow them to provide better information to us. And
of course we had to ask for that through the tsps 'cause we don't have a
direct relationship with these large electronic loads. And we also put out a market notice.
and when we got back, uh, we got responses from nine of 24
rfis that we sent out. Um, only two of them showed that
they had better than the kind of the, what we call the iic
curve, the, um, um, that, that, that
kind of more, um, conservative, uh, assumption that we've been making
in these studies. So the studies going forward that we'll be bringing at forward to the stakeholder
groups, and probably here as well over the next couple of months
will be, um, uh, including the id curve for all, but those
that that show, um, that provided responses
that they can do better than that. Um, now there
is an ongoing opportunity for those guys to, uh, provide
better data, update their models, go through that process.
so there's, there's still that opening, uh, as, as we, uh, work
forward. So it, it highlights the need that,
that we may need a more direct relationship somehow
with these, uh, the large loads so that we can communicate with
them more directly and request information and then get information back from
them, is what we've, we've kind of the point of that.
and then finally, uh, we do a, a black start training every year. And of course,
we don't want to ever have a system black start type
event, but that doesn't mean we shouldn't plan for it. And so we have a plan in
place for restarting the grid if that were to ever happen. And, uh,
not only do we have a plan, but we train on it every year. This year we,
we did that through a six week cycle. So there's a different group of people
that go through the training on our simulator, including people
from ercot, my staff and ercot operations, but also people
from qsc and people from that own generation or that operate
generation and also transmission owners. And we go through a simulation
to say, what if it, what if we had to restart the grid? How would that work? And
so we had a really successful one this year, uh, but about 750
market participants that were involved in that. And I just wanted to highlight that because
it's not something you hear about every day, but it's, it's really a important
function, um, and involves a lot of people, obviously.
and that's it. I'm happy to answer any questions. So
is it appropriate, appropriate to, uh,
ask what the, uh, longest and shortest black
start scenarios look like? It's, uh, we
don't want to do it. And in fact, because it would take longer than anybody would be
comfortable with. Okay. And, you know, in fact, one of the things people always ask, well,
what could get us into that kind of situation? And I ha
always answer that, well, if we figure out something that might
get us in that situation, you'll see an nprr or some rule change
or some operating procedure change that will eliminate that risk
as quickly as possible. Yes, sir. That's, that's the appropriate response. Okay. Good.
any questions? Okay, jury, I
have a generic question. Um, now that we've implemented
rtc plus b, congratulations in our decks are the
typical operating metrics, are you projecting any
moderate changes in what the trend lines we're seeing as a result of rt c? I think that's
something we've been looking at very closely the last several days.
um, we've actually, I sent a note this morning, what about this?
and so we're, we're definitely looking at this. I think we, when we have more of a trend line
than having three points on it, we'll, we can come back and, and make kind
of more of a here's the, what we've seen both between me and keith, I think.
okay. Anything else for dan? Dan, do you have anything else? Okay,
peggy? Yeah. Hey, dan, I remember you presented to us after
the event over in europe mm-hmm . About, uh, looking at
lessons learned from that and ways to improve to get back
online quickly if we have an event. Are you guys still evaluating that?
and, uh, um, can you provide us an update?
um, we, we've done some things. One of the things that we're looking
at is, uh, the potential for, um, um,
temporary ac ties that we could use to, to make the island kind of the restoration
happen faster. I think that was one of the lessons learned that that could happen.
um, the, they were able to get that grid back. Blake started very quickly,
amazingly fast, in fact, uh, because of that, I actually hosted a group from
portugal recently, and, uh, that was one of the things that we talked about with
them. And so I think we're, we're looking at that. We've got a couple of different
kind of low level initiatives going on to look at that. Uh,
but that's, that's our intent to still learn from that. We don't have anything
ready to bring for you yet.
okay. Dan, I think that's it for you. I'm gonna say anybody else raise their hands.
so we're gonna pr uh, move to agenda item 16.2, system
planning and weatherization update. And, uh, christie's gonna be back at the podium for
this presentation.
all right, so we talked about the infrastructure needs from a transmission perspective.
and so I think as you look at some of the updates that we're seeing on the system, both
from the large load and the generation kind of completes that
picture. So I wanna share where we're at on those stats as well as work
that we're doing and the resource adequacy, the weatherization. Um,
and then finally some updates on where we are on reviewing
the information received from stakeholders from ger 2 45,
large load interconnection request. Um, a lot of press
being given to how this queue has, and
I should say queue because there is not a queue of a first in, first
out, but how this group of large load request has really
grown over time. As you can see on this slide, we
are tracking over 226 gigawatts of large load
requests as of november 18th. But
to show you how quickly things are changing, I asked the team on friday,
so what have we seen in the, in the next several days
as of this past friday, that number is now up to 233 gigawatts.
so we continue week after week to see more interest in
connecting to the ercot grid. Over 75 or
70% of those requests are data center request
across the system. And recognizing,
um, you know, we, we hear the developers loud and clear
the need for certainty, and we agree there's need for certainty, and we also
recognize there's need for improvements to the process. If you look at what's
happened just since the beginning of this year, so when we met
last year at this time, we were tracking about 83,000
megawatts worth of requests over the course of 2025.
that's grown. Now, as I just stated, we're up to 233
gigawatts. That's almost a 300% increase
in the amount of megawatts that are wanting to connect to the ercot system.
we have outgrown the process that was established for reviewing these large
loads. It was originally set up for,
we were thinking about 40 to 50 loads back in the
2022 timeframe. And as you can see now,
we're tracking, just this year we received 225
new requests. So this,
the amount of loads in how we study them, we can no longer be looking
at them individually because we have to look at their impact to each other as well.
um, again, on this one, these stats were pulled on november 18th,
as of last friday, we had had an additional five new requests come in in that short
period of time over the thanksgiving holiday and last week.
I guess one thing I would note, um, when you look at the request on
the large load slide and the amount of megawatts, you know, over 200 gigawatts
of request, we recognize the importance of working with
the commission to implement the sb six
statutes that were put forward to be able to get better information about
the certainty of which of those loads move forwards. Just like the large
generation interconnection queue that we'll see in a couple slides,
we don't expect that all of those will materialized. So again, it's very important to
get those low forecasting and standardization rules in
place so that we have better information as we're studying and making recommendations
on how to move forward.
here's the slide that I was looking for, 2000 generation requests,
and this was as of october. And again, those things are changing as well. I had the
team take a look at what we had as the end of november, and we've
actually gotten additional, uh, megawatts in from those requests as
well. Tracking over 432 gigawatts. That's now up to 435.
but what I would say is the most notable, you know, we've seen the trend
month after month that the majority well over, almost 80%
is coming from solar and battery energy storage request. We
are still, we're starting to see an uptick in the natural gas, uh,
request as well. When we were here in december of last year,
we were tracking 26 gigawatts of gas as of november 30th,
that number is now up to almost 53 gigawatts.
always like to keep you updated on how the texas energy fund projects are
moving through the process of those seven gigawatts or 18
projects that are moving forward. We actually had our first project
pen peaking, um, receive its part one approval to energize. So
it's actually connected to the system going through testing and enabled
to, um, to produce energy.
just another snapshot of looking at how the generation is materialized
in 20 24, 25 in 2025. Across
those years, we saw about 23 gigawatts of generation resources synchronized
to the grid. Um, but you can tell the majority of those are coming from
these blue lines, battery energy storage or the green lines, which
are solar. As we look ahead, those resources
that have already gone through our qualification process and are planning to energize,
uh, q1 of next year, we're looking at almost another 10 gigawatts coming
to the system. Again, those are mainly comprised of solar
and battery energy storage.
from a transmission planning perspective, um, the team has been really
busy. So not only looking at ways that we can improve the planning
processes, looking at, um, the potential, uh, implementation
of 7 65, but just the sheer volume of projects. In
fact, in 2025 alone, um, we've more than doubled the amount of
projects that the team has reviewed and brought forward to you. Um,
this year we got in study or have already brought forward
48 various projects last year. That number was 22.
I think that trend will continue, uh, as we start to look at receiving
projects from the utilities to implement both our 2024
rtp and 2025 rtp roadmaps
from a resource adequacy reporting perspective. Um, the graphic in the middle just
gives you a quick snapshot of our monthly outlook on resource adequacy
at the time we put these slides together. Both december and januarys were available
this past friday. We also published the february more and we see
a consistent trend, um, this year compared to last year,
lower chances of going into emergency operations or
even load shed given our probabilistic analysis.
and the main reasons for that is, you know, you think back to the previous slides, the amount
of generation that has been added to the system since then, um, is
playing a key factor. One other note,
uh, wanted to or two other notes from the resource adequacy reporting perspective,
each may in december, we come out with our capacity, demand and reserve
report. This is really, um, a log of all of the
generation that has met certain requirements for coming onto the system into
the future years, as well as our forecasted demand that we
received from input from the utilities. And that release is planned
for the third week of december. Per protocol requirements
did wanna highlight, we will be pushing out a market notice to make all participants
aware, but one thing we're doing differently this year is we're actually going
to have a draft version of the capacity, demand and reserve report
available to the supply analysis working group page.
so it, it will be available to anyone, um, that would like to review it as
a draft form. Um, as we found, um, getting input from the stakeholders
throughout the process has been beneficial and making sure that final report
that we put out, um, is meeting, um,
our requirements. We will have our protocol required
requirements, and then we've also added in some additional scenarios that look
at the impacts of our assumptions
based off of the senate bill six large load curtailment and the
texas energy fund assumptions. So for example, generation
that is in the texas energy fund hadn't met the protocol requirement for
being included in our ledger of generation that's available. Those are some
scenarios that we'll look at as a part of that report just to give people different perspectives,
um, on different scenarios that could play out. Pablo
also mentioned the reliability standard analysis. So we've
been working with commission staff, uh, as well as our
staff to prepare for next year's work that will be undertaken
as the first reliability standard assessment for puc rules.
uh, earlier this month, uh, we filed in in coordination
with the, from input from the tsps, um, information
as to the magnitude. So if you think about the reliability
standard has three legs, it's frequency, magnitude, and duration.
and the reason for the magnitude piece is we recognize
from lessons learned from winter storm uri, the utilities can only safely
rotate through a set amount of megawatts on their system
until they get to a point where they can no longer rotate through customers. So
we take input from the tsps on their capabilities, compile that
information, and we've provided that to the commission, which will be one of the
inputs going into next year's reliability assessment.
we're also working on what our assumptions will be for our model
that we'll run next year for the assessment. We'll be filing those with the
commission in mid-january. It will open up an opportunity for stakeholder
comment on the assumptions that will go in, and then
based off of commission decision, that'll be finalized. And
then we'll run throughout the summer, be running our model analysis and we'll keep you updated
on that as we move through next year.
weatherization perspective, you know, this group was
established in 2021
we have going into, um, this winter season.
and you can see the trend is we've been doing more and more resources
and more transmission facilities over time. That's
as we've added additional staff, but more importantly because there are
more resources and more transmission elements on the system. So in advance
of winter to help, uh, work with stakeholders, we really tried to make this,
uh, a collaborative program where we
are providing input, sharing best practices. So we've had workshops with,
uh, the utilities, with the resources. Um, we've held additional,
um, sessions for those new resources coming to the system to help
them prepare their documentation and answer their
questions about the, the rule and preparations. We started our weatherization
and inspections last week, um, and we've completed
13 transmission and 21 resource inspections. Uh, we've
got a target of doing at least 430, uh, throughout the
winter season. And we really use a risk-based approach on how we choose
which, uh, resources and utility, uh, equipment that we go
in and research. So for example, um, from a resource perspective,
we're looking, there's a rule requirement that we must see 'em at least once every three years.
so have we seen them yet in that three year period? Have we seen them in a weather,
um, season? Have they had previous issues and
we need to go back to make sure they have corrected, um, and cured those, those
problems. And then most importantly, newly commissioned resources,
making sure they understand the rules and are prepared
in the off seasons. Um, one thing I did want to highlight, one of the things that the weatherization
inspection team does, because they are um, across the state,
is we are able to utilize them to go out and inspect the,
the facilities, um, that have been awarded the firm fuel supply service
to make sure, um, they are prepared as well for going into the, the
winter season in case that service has to be called upon
noer 2 45. Um, so this is based on inverter
based resources and requirements that they meet, uh, voltage ride
through requirements. We continue going through the
analysis of the information that we received from the resources
back in september. We are looking at
their three categories of request. They can request
an extension so they believe they can meet the requirements,
but they need additional time maybe to work and make changes in the field.
there are entities that are requesting an exemption. They do not feel that they
can meet those and um, there's no changes. Maybe they're an
older type turbine, for example, and they can't make changes to their configurations
to be able to meet the ride through requirements. And then we have some
entities that have requested both because they're still maybe working with their vendors
and they don't know whether they can make it. They think maybe they can,
but then they might not be able to. So they've requested both to be on the safe side.
we're right now prioritizing our review of the extension request.
um, and updated stat, this says 130, but
out of as of um, earlier, uh,
this or late last week as of friday, we'd sent out
141 notices of missing information to resources.
so looking at those extension requests, we found that additional information
is needed or wasn't provided correctly
from an exemptions perspective. Um, a key part
of that is providing models to show
what their, their capabilities are so that we can review that.
um, there are 72 resources that were seeking an exemption that
still have not provided their models, which were to have already
been provided to us. So we continue to try to obtain those
from the resource entities to be able to run the reliability
assessment next year. It's important that we have good dynamic
model information, so when we run
to see whether or not we can grant an exemption, we need to know
what's currently on the system and how it's gonna interact and whether
we can take, um, except it's a minimal level of risk
for that particular entity that's asking for an exemption.
as of the time of pulling these slides, we had over 400 resources that
still had not provided their updated models to their capabilities.
and so this, once we receive those models, we have to go through a model quality
test. It requires, you know, additional review by ercot.
so it's very important that we get that information from the
resources to be able to then do the reliability
assessment next year. So, christie,
what's their obligation to provide it? I mean, is that a mandatory obligation or
voluntary obligation? It's a mandatory, um, obligation
via the nodal operating guide rules that were passed and approved by the
puc and what are the consequences that they don't by
a certain date. So if they don't, this would be something then we could turn
over to, um, our erm that would review
for, you know, non-compliance with the protocols and guides
and then turn that over to the commission for enforcement. That's a substantial
portion that you're still waiting for. Yes.
I just wanna follow up. Did you wanna say something? Go ahead. Okay. I just wanted
to follow up on that line of questioning. Christie. I know we've made a little bit
of progress in this area, but it is quite frustrating,
a lack of responsiveness, especially given how long it took us
to get this passed in the first place. And, uh,
when you come back and report on this the next time,
if we're not not making significant progress, I think we need to have a more
fulsome discussion about what our options are. And maybe the commission needs
to be thinking about that too, because it's a serious issue.
thank you. Well, can I add onto that, uh, what's
tax's role once they pass something to help encourage
compliance to a new role? Should we ask tax to also
address this matter?
I mean, tech leadership is listening. They can, um, I, I don't
think there's a lot of value on what tech can do. You're talking about individual companies now that have
a compliance obligation on the roles and that we've interacted with for quite
some time. So I think we have the ball as we're
managing to understand where we're going with the reliability assessments.
as christie indicated, there are mechanisms to move this over to the
enforcement side. And so we're kind of balancing out all that as we look at a tremendous
amount of data that still has quality issues associated it with
it, and a lack of models that have come in. So
we will continue to manage it with, as pablo has indicated, and christie's indicated at
some point, we will move forward and do the reliability assessments based upon the information we have.
and those outcomes will, will, we'll move forward with either granting
or not a, granting the exemptions or the extensions.
and, and then from there, it it is a compliance regulatory process that
falls within the commission to ultimately handle at the end of the day. And
I think what might be needed, chad, at some point, is a plain english
language communication to all the affected parties,
reminding them of their obligations and the consequences of not fulfilling
them. Those communications have happened
in plain english or in lawyers speak.
plain english. Okay. Not, not misunderstood.
yeah. Things that engineers can understand. This is what happens if
you don't do it. Uh, to go back to julie's, uh,
comment, I don't know that we wanna put tac in an enforcement position. That's not really their role.
well, and I think they'd be uncomfortable with that. Let me, let me give a little background. This
is a member organization, uh, wasn't asking so much
tax enforcement so much as what are they seeing
causing resistance and delays in the membership that agreed to do this?
yeah. Feedback. Yeah, I think would always welcome their feedback. Chair
gleason. Yeah. Mr. Chairman, since um, compliance and enforcement got brought up,
maybe I'd ask our deputy executive director barksdale english to speak to
staff's role in enforcing, uh, these provisions. Thanks,
chairman. Um, so as chad mentioned, the, um, the
erm process, uh, is, is gonna be ercot
staff's primary way for referring any outstanding
issues to the commission to seek enforcement over. Um, my staff
works very closely with the, the reliability monitor here. And,
um, we are constantly juggling the myriad issues that,
um, that face the stakeholders here and trying to prioritize
which, um, which efforts need to be, um, escalated
and move forward more quickly. Um, this is certainly a, an
important one. Um, and we also wanna recognize that
the exemption process that christie was talking about is, is novel,
uh, for this market. And so I think, uh, in my opinion, ercot
staff is doing a good job of trying to provide a little bit of grace to allow the member companies to
figure out how to get through that process. Um, but
I would agree with the members', uh, concerns here that at a
certain point we need to, you know, call time and, and start moving forward
with something more serious and in an enforcement investigation. Uh, and
just so the members are aware, uh, failure to comply with ercot
protocols, uh, could result in a daily fine of up to $25,000
per violation or potentially being kicked off
the, the grid. That could be a resulting action as well, sir?
yes. Okay. Uh, so those 416
noncompliant members need to get their information in 130 that have missing
information, need to get that in. So for those that are listing in kristy, keep going.
that completes my update. Any questions? Okay. Any questions?
all right, very good. Uh, if there are no other
questions for christie, uh, we'll move to agenda item 17,
other business. Is there any other business that any other board member would like to raise?
hearing none, the board will recess and convene an executive session. Follow the
executive session. We anticipate several voting items, so general session
will reconvene at the conclusion of the executive session. The general session
of ercot board of directors meeting is now recessed and the webcast will be suspended.
chair gleason. Thank you. Thank you mr. Chairman. This meeting,
the public utility commission of texas will stand in recess.
okay. Good afternoon. I'm bill flores ercot, board chair. I hereby reconvene this meeting
of ercot board of directors. I've confirmed that a quorum is present in person.
this meeting is being webcast live to the public on our cop's website.
uh, we have three voting items, uh, carried over from
executive session, uh, for, uh, this is agenda item
18. Uh, first I'm gonna entertain a motion for board approval of the two
personnel matters discussed during executive session. Under agenda items
es 2.4 and two point.
so moved. Uh, thank you, peggy. Is there a second? Second.
okay. Second for chris. Thank you. All in favor a. Aye.
any opposed? Any abstentions? The personnel matters are approved
as, uh, as presented. Next, I'll entertain
a motion for board approval of the contract matter discussed during executive session under
agenda item es 2.7 0.1.
john, thank you. Second, julie. All in favor? Aye. Aye.
aye. Any opposed? Any abstentions? The contract matter has been
approved. And then lastly, I'll entertain, I'll make the motion,
uh, to approve the selection of weaver and tidball lp as a 2026
independent system and organization control auditor
for the soc audit for 2025. 2026.
second. Thank you, peggy. All in favor?
aye. Any opposed? Any abstentions that has been approved? Thank you.
the meeting of the ercot board of directors is now adjourned and the webcast will be concluded.