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  • Item 0 - Chairman Gleeson calls meeting to order - 56954
    00:00:07
    This meeting of the Public Utility Commission of
  • 00:00:09
    Texas will come to order. To consider matters
  • 00:00:11
    that have been duly posted with the Secretary
  • 00:00:13
    of State for 02/13/2025. Good morning, Commissioners. Good
  • 00:00:18
    morning, everybody. So, before we get into anything,
  • 00:00:22
    I do want to congratulate our staff and
  • 00:00:26
    particularly Connie and Haley. We just got done
  • 00:00:29
    with the senate finance hearing that lasted all
  • 00:00:32
    of about five minutes, where for the first
  • 00:00:34
    time, I was trying to think that in
  • 00:00:37
    all the tens of hours I've testified, I
  • 00:00:40
    don't think I've ever been asked zero questions.
  • 00:00:44
    And so I think what I learned from
  • 00:00:46
    that was I've been messing this up by
  • 00:00:47
    participating more. And the the secret sauce there
  • 00:00:51
    was, was Haley and her staff putting that
  • 00:00:54
    LAR together and Connie being up there to
  • 00:00:56
    lay it out. So congratulations. That was probably
  • 00:00:59
    the best hearing I've ever been a part
  • 00:01:00
    of. Thank you, chairman, for laying the groundwork.
  • 00:01:07
    So, as for as far as kind of
  • 00:01:09
    run of show, we have Closed Session today,
  • 00:01:12
    and then Pablo's here to talk about the
  • 00:01:15
    CDR. So if it's okay with you all,
  • 00:01:18
    I think we'll do closed session first since
  • 00:01:20
    the AG is already here. When we come
  • 00:01:22
    back, we'll move to, to hear from Pablo
  • 00:01:25
    and the CDR. We also have a discussion
  • 00:01:27
    on magnitude in that, project number. I think
  • 00:01:31
    we'll take that up separately. So I'd say
  • 00:01:33
    we do Closed Session, and then we take
  • 00:01:36
    up Pablo and the CDR. Then we go
  • 00:01:37
    back to the top of the agenda with
  • 00:01:39
    the contested cases and go back down, if
  • Item 28 - Chairman Gleeson pauses Open Meeting, to hold Closed Session
    00:01:41
    that works for everybody. That work? Okay. So
  • 00:01:45
    having convened in a duly noticed open meeting,
  • 00:01:47
    the Commission will now, at 11:02AM on 02/13/2025,
  • 00:01:53
    hold a Closed Session pursuant to Chapter 551
  • 00:01:56
    of the Government Code. It will
  • 00:01:57
    consult with its attorneys pursuant to Section 551.071
  • 00:02:00
    of the
  • 00:02:01
    code, deliberate personnel matters pursuant to Section 551.074
  • 00:02:04
    of the
  • 00:02:06
    code, and deliberate security matters pursuant to Section
  • 00:02:09
    551.076 of
  • 00:02:11
    the code. We'll be right back. Alright. Let's
  • Item 28 - Chairman Gleeson concludes Closed Session, Public Meeting resumed
    00:02:21
    go back on the record. The Closed Session
  • 00:02:24
    is hereby concluded at 11:11AM on 02/13/2025, and
  • 00:02:29
    the Commission will resume its public meeting. No
  • 00:02:31
    action will be taken by the Commission regarding
  • 00:02:33
    matters discussed in closed session. Alright. Shelah, do
  • 00:02:37
    you wanna take us do you wanna take
  • 00:02:38
    us through the consent agenda? Yes. Good morning,
  • Item 0.1 - Commission Counsel Shelah Cisneros lays out Consent Agenda
    00:02:40
    Commissioners. By individual ballot, the Commissioners voted to
  • 00:02:44
    place: Items 4, 8, 10, 11, 12, 13,
  • 00:02:51
    and 15 on the consent agenda, and no
  • 00:02:54
    one signed up to speak on these items.
  • 00:02:56
    And further, no one signed up for a
  • 00:02:57
    public comment either. Thank you, Shelah. And Item
  • 00:03:00
    14 will not be taken up. Is that
  • Item 0.1 - Chairman Gleeson asks for motion to approve items on Consent Agenda
    00:03:03
    correct? Okay. Alright. I'll entertain a motion to,
  • 00:03:08
    approve the consent agenda as laid out by
  • 00:03:10
    Shelah. So moved. Second. I have a motion
  • 00:03:13
    and a second. All those in favor, say
  • 00:03:14
    aye. Aye. Opposed? Motion prevails. Alright. So like
  • 00:03:18
    we discussed, I guess oh, do we have
  • 00:03:21
    anyone signed up for public comment today? No
  • 00:03:23
    one has signed up for public comment for
  • 00:03:25
    any item. Thank you. So like we discussed,
  • 00:03:28
    let's go a little out of order, and
  • Item 6 - Project No. 55999 – Reports of the Electric Reliability Council of Texas
    00:03:30
    we'll take up, ERCOT first. So I'm gonna
  • 00:03:33
    call up Project No. 55999, reports of the
  • 00:03:37
    Electric Reliability Council of Texas, and ask ERCOT's
  • 00:03:40
    president and CEO, Pablo Vegas, to come give
  • 00:03:43
    us an update on the CDR report. Good
  • Item 6 - Pablo Vegas – ERCOT President & CEO - CDR Cycle - 55999
    00:03:45
    morning, Pablo. Good morning, Chairman. Good morning, Commissioners.
  • 00:03:49
    Good to be with you this morning. Wanted
  • 00:03:52
    to spend a little bit of time walking
  • 00:03:54
    through the CDR, this cycle because there's been
  • 00:03:57
    some pretty significant changes in the structure of
  • 00:03:59
    it. And so I wanted to kinda talk
  • 00:04:01
    through what some of those changes are. Wanted
  • 00:04:04
    to explain, a little bit about what the
  • 00:04:06
    trends are that we're seeing and and then
  • 00:04:08
    importantly also talk about some of the opportunities
  • 00:04:11
    that we see ahead in order to deal
  • 00:04:13
    with some of the trends that we're seeing
  • 00:04:14
    in the in the CDR. So as I've
  • 00:04:17
    got a presentation that I've we filed and
  • 00:04:19
    hopefully you all have access to up there.
  • 00:04:22
    You know, first off, the CDR is something
  • 00:04:24
    that we publish a couple times a year,
  • 00:04:25
    typically in May and December. This time, the
  • 00:04:27
    cycle was delayed, a couple months in order
  • 00:04:30
    to provide a little more time to review
  • 00:04:33
    all of the substantive changes that went into
  • 00:04:35
    the CDR report and make sure that all
  • 00:04:36
    of the analysis and the, and the and
  • 00:04:39
    the outcomes were, correctly accounted for. And so
  • 00:04:43
    if we go into the presentation, I think
  • 00:04:45
    starting on slide three, it would be helpful
  • 00:04:47
    to talk through a little bit what these
  • 00:04:48
    changes are. Overall, though, let me start off
  • 00:04:52
    by saying, you know, as we would expect
  • 00:04:55
    in a in a fast growing environment where,
  • 00:04:59
    you know, load is being able to grow
  • 00:05:01
    more quickly than supply is or than even
  • 00:05:04
    transmission and other infrastructure, we've seen a trend
  • 00:05:08
    of kind of downward pressure on planning reserves.
  • 00:05:10
    And so we see that trend continuing in
  • 00:05:12
    the CDR as well. Some of the changes
  • 00:05:15
    that we've made have, has have accelerated or
  • 00:05:17
    changed the view of those, planning reserve margin
  • 00:05:21
    shrinks, shrinking. But I wanna start off by
  • 00:05:24
    saying the overall circumstance, you know, from May
  • 00:05:27
    to December hasn't fundamentally changed. Just a lot
  • 00:05:30
    of the accounting for how we look in
  • 00:05:32
    some of the supply resources and how we
  • 00:05:34
    are now counting for some of the loads
  • 00:05:36
    due to, some of the legislation from the
  • 00:05:38
    last session. That's what has changed. But the
  • 00:05:41
    overall trend of a rapidly growing economy, rapidly
  • 00:05:44
    growing demand as a result of that, and,
  • 00:05:47
    and and really the, the the energy economy,
  • 00:05:50
    you know, working to keep up with that,
  • 00:05:52
    that trend remains similar today as it was
  • 00:05:54
    back in May and during the last public,
  • 00:05:56
    publication of the CDR. So beginning on slide
  • 00:06:00
    three, you know, the CDR changes, I'd say
  • 00:06:02
    some of the most impactful changes that we're,
  • 00:06:05
    looking at now is, first off, we are,
  • 00:06:07
    of course, using the the load that is
  • 00:06:10
    the full load that was submitted for, transmission
  • 00:06:13
    planning, the load that was changed based on
  • 00:06:16
    the hospital 5066. So that larger load forecast
  • 00:06:19
    now is incorporated looking out for the next
  • 00:06:21
    five years. Additionally, the, report now uses, effective
  • 00:06:27
    load carrying capabilities for measuring the the reliability
  • 00:06:31
    contributions of wind and solar. That is a
  • 00:06:35
    change that, ERCOT made working through with stakeholders
  • 00:06:39
    during the NPRR process around the restructuring of
  • 00:06:41
    this report. It is, something that we are
  • 00:06:45
    seeing, utilized more frequently across ISOs throughout The
  • 00:06:50
    United States. Effective load carrying capabilities are being
  • 00:06:54
    used by other large ISOs and RTOs. PJM
  • 00:06:57
    is using it. MISO uses it. New York
  • 00:07:00
    ISO uses it. So, SPP just voted to
  • 00:07:03
    begin using ELCC for their capacity accreditation beginning
  • 00:07:08
    this summer, actually, in 2025. So many of
  • 00:07:10
    the largest RTOs and ISOs in the in
  • 00:07:13
    The US are using ELCCs. That's a commonly
  • 00:07:15
    used metric that more accurately reflects the reliability
  • 00:07:19
    contributions of, variable resources like, like wind and
  • 00:07:24
    solar. In addition, for the first time, the
  • 00:07:26
    CDR also includes battery storage contributions. In the
  • 00:07:30
    past, we didn't have really a a a
  • 00:07:32
    track record, that was long enough to really
  • 00:07:35
    show the impact, but now we do. We've
  • 00:07:38
    seen the performance of batteries over the last
  • 00:07:40
    several years, and so we can now forecast
  • 00:07:42
    based on the growth that's ahead of us
  • 00:07:43
    the contributions that we can expect them to
  • 00:07:45
    make during peak peak times, and that's been
  • 00:07:47
    a very positive aspect to the, to the
  • 00:07:50
    reserve margins in the future. And then a
  • 00:07:52
    couple of smaller changes that had less of
  • 00:07:54
    an impact. We're we're we're reporting also peak
  • 00:07:57
    net loads in addition to peak loads. We
  • 00:07:58
    just only just show peak load periods in
  • 00:08:00
    the winter and the summer. Now we're showing
  • 00:08:01
    peak net loads. That's important, especially in the
  • 00:08:04
    summer because the, risky periods in the summer
  • 00:08:06
    have changed and moved to the net peak
  • 00:08:09
    period, which is typically when the sun sets.
  • 00:08:11
    In the in the winter, that has less
  • 00:08:12
    of an effect because the peak and the
  • 00:08:14
    net peaks tend to be closer to each
  • 00:08:16
    other in the winter. So less of an
  • 00:08:18
    impact in the in the margins during those,
  • 00:08:20
    those periods of the Winter. And then there's
  • 00:08:22
    been some updates to the criteria for how
  • 00:08:24
    planned resources are included, how changes from developer
  • 00:08:28
    schedules are included, and then also the inclusion
  • 00:08:31
    of publicly announced planned retirements even in advance
  • 00:08:34
    of, some of these, being officially noticed with
  • 00:08:37
    an NSO to ERCOT. And so we do
  • 00:08:39
    capture those, you know, announcements and reflect those
  • 00:08:42
    in future years today. So so those are
  • 00:08:46
    some of the more substantive changes in the
  • 00:08:48
    actual report construct. Because the load forecast is
  • 00:08:52
    such a, you know, significant part of it,
  • 00:08:53
    I wanted to just spend a minute talking
  • 00:08:56
    about how kind of that load forecast comes
  • 00:08:58
    together. If you look at slide four, there's
  • 00:08:59
    an illustration there that explains the components that
  • 00:09:03
    go into the load forecast we use. So
  • 00:09:05
    starting first, you know, we've got our existing
  • 00:09:07
    load that's on the system that's, you know,
  • 00:09:09
    part of the baseline. And then the transmission
  • 00:09:12
    service providers, they will provide us details on
  • 00:09:15
    executed customer agreement load that they expect to
  • 00:09:17
    come on the system, if they're utilizing any
  • 00:09:20
    credible third party forecast like the S&P
  • 00:09:22
    Global Oil and Gas forecast that's been
  • 00:09:24
    used historically to help forecast changes in the
  • 00:09:27
    in the Permian. And then, one of the
  • 00:09:29
    changed elements from HB5066 is
  • 00:09:32
    the inclusion of the TSP officer tested letters
  • 00:09:34
    and the load that's included in those. Then
  • 00:09:37
    ERCOT has components that we bring into that
  • 00:09:39
    forecast. We bring in the base economic growth
  • 00:09:41
    forecast that we've historically done. And then we
  • 00:09:44
    also include electric vehicles, plus whatever existing crypto
  • 00:09:48
    site load growth we have. So that's existing
  • 00:09:50
    cryptos, not growth of brand new ones, but
  • 00:09:52
    where we have existing sites and expansions at
  • 00:09:54
    them, we include that minus the impact of
  • 00:09:57
    rooftop, photovoltaics. So the impact that that, distributed
  • 00:10:01
    rooftop solar has. So that's the way that
  • 00:10:05
    the the load forecast gets built today. So
  • 00:10:10
    then as you kind of look at the
  • 00:10:13
    actual CDR results and the and the takeaways
  • 00:10:16
    on slide slide five, some of the key,
  • 00:10:19
    you know, changes that we're seeing here is
  • 00:10:21
    that now we're we're including a range of
  • 00:10:23
    scenarios, in all of the peak and net
  • 00:10:26
    peak scenarios to show potential variability, in the
  • 00:10:31
    outcomes. There is a lot of uncertainty, of
  • 00:10:33
    course, in the specific timing of when specific
  • 00:10:37
    supply resources and load resources could come online.
  • 00:10:40
    That uncertainty could certainly move around the numbers
  • 00:10:43
    in any given year. There are also different
  • 00:10:45
    things that are being considered legislatively right now
  • 00:10:49
    around flexibility requirements for certain large loads. That
  • 00:10:52
    could have an impact on, the way large
  • 00:10:56
    loads are modeled today. Today, typically, large loads
  • 00:10:59
    other than crypto mining facilities are modeled as
  • 00:11:02
    firm loads. And if there were requirements that
  • 00:11:05
    large loads had to have some elements of
  • 00:11:07
    flexibility, then those could be modeled differently, and
  • 00:11:09
    that would show up differently in the planning
  • 00:11:11
    reserves in the future. And so what we
  • 00:11:14
    wanted to do was to show some realistic
  • 00:11:16
    and probable adjustments that could be made to
  • 00:11:19
    the report definition that would give different scenario
  • 00:11:22
    outcomes based on how things could proceed in
  • 00:11:24
    the future. So timing of load, the variability
  • 00:11:26
    and flexibility of load, very significant factors. Also,
  • 00:11:30
    the inclusion of supply, like the Texas Energy
  • 00:11:32
    Fund generation resources. Based on the criteria of
  • 00:11:36
    the report today, they wouldn't be most of
  • 00:11:38
    it would not be included just based on
  • 00:11:40
    where they are on the development cycle. However,
  • 00:11:42
    we think there's a high likelihood that a
  • 00:11:44
    good amount of that, generation will get built.
  • 00:11:46
    So we showed scenarios where they're built in
  • 00:11:48
    order to show what the impact would be
  • 00:11:50
    on these, on these planning reserves in the
  • 00:11:52
    future. So we wanted to do is to
  • 00:11:54
    really try to explain, you know, that while
  • 00:11:56
    there's a, you know, rigid and new definition
  • 00:11:58
    for this report that does show a declining,
  • 00:12:01
    reserve margin, there are very impactful potential changes
  • 00:12:06
    that could give different scenario outcomes to the
  • 00:12:08
    CDR. And we'll continue to report showing this
  • 00:12:11
    kind of variability in the future because I
  • 00:12:13
    think it better reflects the, the uncertainties that
  • 00:12:16
    are inherent in a dynamic market and the
  • 00:12:19
    uncertainties that can manifest based on changes to
  • 00:12:22
    either market rules and or, the progress of
  • 00:12:25
    the of load growth in the in the
  • 00:12:26
    state. So I think that's, that's an important
  • 00:12:29
    important point to to make here. But all
  • 00:12:32
    that being said, you know, the the trends
  • 00:12:35
    do show that, you know, we do have
  • 00:12:37
    you know, there's pressure on these, on these
  • 00:12:39
    planning reserves, and so I think it's important
  • 00:12:42
    to think about what actions we should be
  • 00:12:44
    taking today to continue to try to move
  • 00:12:46
    the trends, upwards and to continue to support
  • 00:12:49
    reliability, going forward. And so I included a
  • 00:12:53
    couple of the actual charts from the report
  • 00:12:55
    to try to illustrate what some of these
  • 00:12:56
    scenarios look like. Maybe we'll just stop on
  • 00:12:58
    slide six for a second, and and this
  • 00:13:00
    is an example of the summer peak load
  • 00:13:02
    hour. What you see here is, you know,
  • 00:13:05
    at the very bottom, you see a light
  • 00:13:07
    blue line that represents the protocol protocol prescribed
  • 00:13:11
    planning reserve. And and what's included in this
  • 00:13:15
    report is really important, but what's not included
  • 00:13:17
    in this report is also very important. So
  • 00:13:20
    let me start by saying by modeling or
  • 00:13:22
    by, reporting what a potential planning margin is
  • 00:13:25
    in the future, what it doesn't reflect is
  • 00:13:29
    the operational realities of the way the market
  • 00:13:31
    would respond to the circumstances that are described.
  • 00:13:35
    It doesn't model what the market typically would
  • 00:13:37
    do if you were to get into periods
  • 00:13:39
    of time of scarcity. Meaning, you know, if
  • 00:13:42
    you had extended periods of scarcity where you
  • 00:13:44
    had pricing going up like this planning reserve
  • 00:13:46
    would indicate, you would likely see the market
  • 00:13:49
    respond in some way. You would see potential
  • 00:13:51
    acceleration in supply. You would see potential slowdowns
  • 00:13:54
    in load. You would see a dynamic market
  • 00:13:57
    operate the way it operates today in a
  • 00:13:59
    future environment with this kind of a trend
  • 00:14:01
    occurring. This report doesn't model that. This report
  • 00:14:04
    just takes snapshot in times in the future
  • 00:14:06
    of potential amounts of supply, potential amounts of
  • 00:14:09
    load, does arithmetic, and shows what the planning
  • 00:14:12
    reserve margins would be. So this is not
  • 00:14:14
    a good representation of an operational forecast or
  • 00:14:17
    what we would expect to happen in real
  • 00:14:19
    time operations in the future. It's just showing
  • 00:14:22
    a trend of where the supply and demand
  • 00:14:25
    is going. And as a result of that,
  • 00:14:27
    you know, trying to inform, the market so
  • 00:14:31
    that we can consider what are the best
  • 00:14:33
    policies and what are the best actions to
  • 00:14:34
    take in order to deal with what those
  • 00:14:36
    trends are showing. So I think that's a
  • 00:14:37
    really important point. This is not a forecast
  • 00:14:39
    of expected operational reserves, nor does it try
  • 00:14:43
    to model the, the the changes and the
  • 00:14:46
    actions of the ERCOT market, how it would
  • 00:14:49
    behave in a dynamic environment. So on this
  • 00:14:52
    slide, you see the prescribed kind of structure
  • 00:14:55
    on the light blue line that, goes negative
  • 00:14:57
    down in the twenty seventh through twenty ninth
  • 00:14:59
    period. At the very top, you see kind
  • 00:15:01
    of a bookended scenario, and that bookended scenario
  • 00:15:04
    excludes the TSP officer letter loads and includes
  • 00:15:07
    the inclusion of TEF projects. And then there's
  • 00:15:10
    a couple of lines in the middle. The
  • 00:15:12
    green one shows if you had half of
  • 00:15:14
    that officer letter load, during each of these
  • 00:15:17
    periods and the TEF projects, what that would
  • 00:15:19
    do. And then the gray line below it
  • 00:15:21
    shows what it would look like with half
  • 00:15:22
    of the officer letter loads and without the
  • 00:15:24
    TEF projects. So more than likely, reality is
  • 00:15:28
    somewhere in between these bounds. And, you know,
  • 00:15:31
    what we, you know, should do as a
  • 00:15:32
    result, let us think about then what what
  • 00:15:34
    are the best actions we can be considering
  • 00:15:35
    in the, in the short and midterm to
  • 00:15:38
    try to address declining planning reserve margins. So
  • 00:15:42
    I'll, I'll jump to that because I think
  • 00:15:45
    the the next charts illustrate, the same general
  • 00:15:48
    trend. We could pause on on slide eight
  • 00:15:51
    for just a second, and this shows the
  • 00:15:54
    impact of some of the report structure changes.
  • 00:15:57
    So it shows how much of an impact
  • 00:15:59
    the change to ELCC had on planning reserve
  • 00:16:02
    margins, how much the inclusion of officer letter
  • 00:16:04
    loads had, the addition for the the inclusion
  • 00:16:07
    of batteries, storage. And so you can see
  • 00:16:11
    in a waterfall format from the May CDR
  • 00:16:13
    to the December or February as we're gonna
  • 00:16:15
    publish it now, what the impact was for
  • 00:16:18
    the summer of twenty twenty five. And, you
  • 00:16:21
    know, this kind of a waterfall is available
  • 00:16:23
    in the report to show in future years
  • 00:16:25
    as well, kind of the degree of impact
  • 00:16:28
    that each of these changes had on those
  • 00:16:29
    margins. So I think very importantly, it's it's
  • 00:16:34
    important to conclude with what are some of
  • 00:16:36
    the opportunities ahead. And, you know, really, if
  • 00:16:38
    you think about, you know, in the long
  • 00:16:40
    term, obviously, supply and infrastructure investments are gonna
  • 00:16:43
    be very helpful as new load comes on
  • 00:16:45
    on the system, and we expect the market
  • 00:16:47
    to respond and be able to support that
  • 00:16:49
    continued growth in infrastructure. In the short and
  • 00:16:52
    midterm though, some of the fastest things that
  • 00:16:54
    we can do have to deal with, the
  • 00:16:56
    demand and demand response. And so specifically on
  • 00:17:00
    large loads, we think that having some type
  • 00:17:02
    of policy and and associated requirements for being
  • 00:17:06
    able to require flexibility where large loads can
  • 00:17:09
    provide flexibility is a critical outcome that could
  • 00:17:12
    immediately provide reliability benefits and would immediately have
  • 00:17:15
    an impact on the, planning margins that we
  • 00:17:18
    see in the future. Would also have an
  • 00:17:19
    immediate impact on potential operate operating margins as
  • 00:17:23
    well, and so there's a a real short
  • 00:17:24
    term benefit to that. We'd love to see
  • 00:17:27
    the more of a focus on residential demand
  • 00:17:30
    response as well. We're gonna be working this
  • 00:17:32
    year, to bring forward some ideas on how
  • 00:17:34
    to develop a residential demand response program that
  • 00:17:37
    ERCOT would have financial support for in order
  • 00:17:40
    to help grow the size of the existing
  • 00:17:43
    residential demand response programs that exist in the
  • 00:17:45
    state today. I think that's a tremendous opportunity
  • 00:17:47
    and could be done more in a short
  • 00:17:49
    to midterm time frame as well. We wanna
  • 00:17:51
    continue to, look at other options that we
  • 00:17:54
    could consider broadening the scope of the firm
  • 00:17:56
    fuel supply could potentially provide more incentive to
  • 00:17:59
    have the development of, backup storage facilities for
  • 00:18:04
    gas, gas operators, and that could include you
  • 00:18:06
    know, that could help make sure that the
  • 00:18:08
    capacity that's on the system is able to
  • 00:18:10
    perform during extreme periods, you know, throughout the
  • 00:18:13
    year. And then, of course, continue to support
  • 00:18:15
    the Texas Energy Fund. Longer term, you know,
  • 00:18:18
    some of the things we've noted here, continuing
  • 00:18:20
    to enhance battery optimization efforts. Batteries continue to
  • 00:18:23
    play a very critical role in the reliability
  • 00:18:25
    and performance of the market today. We think
  • 00:18:27
    they'll continue to do so in a growing
  • 00:18:28
    fashion in the future. The the new ancillary
  • 00:18:31
    service, dispatchable reliability reserve service is gonna be
  • 00:18:34
    designed and developed following the completion of the
  • 00:18:36
    real time co optimization project that has the
  • 00:18:39
    potential to be utilized in ways that could
  • 00:18:41
    support resource adequacy down the road. And then,
  • 00:18:44
    of course, you know, implementing the reliability standard
  • 00:18:47
    and leveraging that to assess the different impacts
  • 00:18:49
    and changes of scenarios in the future will
  • 00:18:51
    always be helpful to inform, the potential impacts
  • 00:18:54
    of some of these these potential, improvements. So
  • 00:18:58
    we'll continue to use that and and see
  • 00:19:00
    that as an opportunity to provide clearer information
  • 00:19:02
    going forward. So I wanted to cover this,
  • 00:19:05
    you know, with with each of you. If
  • 00:19:07
    you had any questions, we'd be happy to
  • 00:19:08
    answer questions about it today and, and certainly
  • 00:19:11
    going forward, as as they emerge. Thank you
  • 00:19:15
    for that layout, Pablo. I think just first
  • 00:19:17
    off, I wanna say thank you for the
  • 00:19:19
    time you spent with my office going over
  • 00:19:22
    this, and and the change to include different
  • 00:19:26
    scenarios, you know, we hear often everything else
  • 00:19:29
    being equal. This is what it'll be. But
  • 00:19:31
    we know a lot of those variables will
  • 00:19:33
    change. So I think it's important that you
  • 00:19:34
    all went back and made some changes to
  • 00:19:37
    look at how different variables being changed would
  • 00:19:39
    actually affect, a possible reality that we'd see
  • 00:19:42
    in the future. So I think that was
  • 00:19:43
    definitely a good change. Commissioners, questions for Pablo?
  • Item 6 - Commissioner Hjaltman's questions for Pablo Vegas - 55999
    00:19:48
    Just a few. Thank you, Pablo. In general,
  • 00:19:52
    I the first kinda, you know, line of
  • 00:19:54
    the study obviously says eroding resource adequacy in
  • 00:19:57
    the absence of major mitigating factors. And then
  • 00:20:00
    it mentions federal policy as something. What what
  • 00:20:04
    are some of those federal policies that we
  • 00:20:05
    could go forth and ask about that would
  • 00:20:08
    maybe be a mitigating factor? So federal poll
  • 00:20:12
    when you start to think about things that
  • 00:20:14
    are being contemplated at the federal policy level,
  • 00:20:16
    so clearly, EPA rules as they apply to
  • 00:20:19
    the, coal and gas fleet here in Texas
  • 00:20:22
    is important federal policy to continue to keep
  • 00:20:25
    an eye on. There are, you know, today
  • 00:20:27
    there are past provisions, by the EPA that
  • 00:20:30
    would restrict the ability for the coal fleet
  • 00:20:33
    in Texas to continue to operate, much past
  • 00:20:36
    2030. And, similarly, very, significant restrictions on the
  • 00:20:40
    ability to build new types of gas resources,
  • 00:20:45
    that wouldn't that don't have, mitigating factors like,
  • 00:20:49
    carbon capture and sequestration, which could make it
  • 00:20:51
    very difficult to build CCGT type of, gas
  • 00:20:54
    plants, anywhere in the country going forward. That's
  • 00:20:57
    some of the federal policy that's out there.
  • 00:20:59
    But then also if there were tariffs, so
  • 00:21:01
    there's been a lot of discussion on tariffs
  • 00:21:02
    and what the impact is of tariffs, not
  • 00:21:05
    only on, supply chains, but actually on electric,
  • 00:21:08
    you know, electric power exchanges that are moving
  • 00:21:11
    between countries. So from Canada to The US,
  • 00:21:14
    from Mexico to The US, the question of
  • 00:21:16
    whether tariffs would be applied, and then certainly,
  • 00:21:19
    of course, on the supply chain of the
  • 00:21:20
    components that go into the electric infrastructure. As
  • 00:21:23
    you know, a lot of the infrastructure that
  • 00:21:26
    is used to build, traditional thermal generation as
  • 00:21:30
    well as, the renewable generation that we're seeing
  • 00:21:33
    coming Oncor the grid comes from outside of
  • 00:21:35
    The United States. And so tariff policies that,
  • 00:21:39
    could that that could be considered could slow
  • 00:21:42
    down or make it more expensive to develop
  • 00:21:44
    those types of resources. And so that would
  • 00:21:46
    have an implication on, some of the reserves
  • 00:21:49
    in the future if we started to see
  • 00:21:50
    a slowdown in development because of that. So
  • 00:21:52
    those are the things those are the federal
  • 00:21:53
    policy issues that I think we have to
  • 00:21:54
    keep a really close eye on and continue
  • 00:21:56
    to advocate for as a state because of
  • 00:21:58
    the impact that they have to us. Yeah.
  • 00:22:01
    That's helpful. And then I you talk about
  • 00:22:03
    the different types of load, firm and, more
  • 00:22:07
    flexible. Is there any discussion of adding other
  • 00:22:12
    levels of types of load and creating different
  • 00:22:15
    scenarios with that? Yeah. And we there is.
  • 00:22:18
    And we would very much like to be
  • 00:22:20
    able to have varying types of loads for
  • 00:22:23
    modeling purposes that better reflect what their performance
  • 00:22:26
    is gonna be in real time. And, you
  • 00:22:29
    know, the thing that, you know, there are
  • 00:22:32
    programs today that offer, you know, voluntary curtailment
  • 00:22:35
    capabilities and things along those lines. We don't
  • 00:22:38
    typically model things that are voluntary today because
  • 00:22:41
    we don't really have assurance that they necessarily
  • 00:22:44
    will respond, during periods of time. But things
  • 00:22:48
    that have kind of more of an obligation
  • 00:22:50
    or a structure around how they will operate
  • 00:22:53
    or participate in a program with a definition.
  • 00:22:55
    So if they're participating in an ancillary service
  • 00:22:58
    where there's an obligation to respond, those are
  • 00:23:01
    the types of things we do model in
  • 00:23:02
    all of our, forecast, and so we reflect
  • 00:23:05
    the participation based on the size and the
  • 00:23:08
    resources that that participate in those, in those
  • 00:23:10
    services. So we'd very much like to define
  • 00:23:12
    new load classes that have operating parameters that
  • 00:23:16
    demonstrate flexibility because then I think it will,
  • 00:23:19
    one, it'll provide a real reliability benefit to
  • 00:23:22
    the grid in doing so and will allow
  • 00:23:24
    us to model it better and and show
  • 00:23:26
    better forecast for what we can expect in
  • 00:23:28
    in future years with that type of a
  • 00:23:30
    load class. And is that legislatively needed? I
  • 00:23:34
    don't I don't think it's necessarily needed. No.
    EditCreate clip
  • Item 6 - Commissioner Jackson's questions for Pablo Vegas - 55999
    00:23:36
    Okay. Okay. I know you you said many
  • 00:23:40
    times that, you know, people look at ERCOT
  • 00:23:43
    and, they see it from an operational standpoint.
  • 00:23:45
    Some some sort of air traffic controller, but,
  • 00:23:49
    you've you've you've kind of stated that the
  • 00:23:51
    real product, you know, that ERCOT provides is
  • 00:23:53
    data. That's right. And so, you know, good
  • 00:23:57
    job particularly since, we know that change is
  • 00:24:01
    inevitable, but, you know, having good processes in
  • 00:24:04
    place help us to manage change. And, you
  • 00:24:07
    know, echoing, I think, what was said earlier
  • 00:24:09
    about, you know, having the various scenarios so
  • 00:24:11
    that we can look at various opportunities within,
  • 00:24:18
    you know, what we see coming in the
  • 00:24:19
    future so that, again, we we can evaluate
  • 00:24:23
    those and then we don't plan to plan,
  • 00:24:26
    we plan to build, we plan to act.
  • 00:24:28
    That's right. And so, just just maybe just
  • 00:24:32
    one question and more, you know, kind of
  • 00:24:35
    your your thoughts going forward. Of course, we
  • 00:24:38
    have real time co optimization that is, you
  • 00:24:41
    know, is looming and is and we're very
  • 00:24:43
    excited to see that implemented. And, you know,
  • 00:24:46
    the other thing that makes Texas unique is
  • 00:24:48
    that we're growing. Right? And so, oftentimes, we're
  • 00:24:51
    compared with other parts of the country or
  • 00:24:54
    other parts of the world, but we're unique
  • 00:24:56
    in that standpoint. So, you know, just from,
  • 00:24:59
    you know, what we're seeing here, which is
  • 00:25:00
    kind of a forecast, and knowing that, you
  • 00:25:02
    know, we are unique in the growth that's
  • 00:25:04
    coming, and also we have this opportunity for
  • 00:25:07
    efficiency, you know, how do you see both
  • 00:25:10
    of those things kind of impacting, you know,
  • 00:25:12
    what we'll be looking at and what we'll
  • 00:25:13
    be doing and the kind of opportunities that
  • 00:25:16
    you think are, you know, the the ones
  • 00:25:18
    that we really ought to be focusing in
  • 00:25:20
    on? Talking about are you and is that
  • 00:25:22
    specific to the the kind of how real
  • 00:25:24
    time co optimization fits into that? Is that
  • 00:25:26
    was that part of the question? Right. Exactly.
  • 00:25:29
    Yeah. So, you know, as we think about
  • 00:25:31
    that project, you know, a lot of the
  • 00:25:32
    things that, you know, we do has very
  • 00:25:35
    kind of, discreet purpose in what it's trying
  • 00:25:37
    to affect in terms of the operations. And
  • 00:25:39
    real time co optimization is trying to affect
  • 00:25:42
    an efficiency in the way that we dispatch
  • 00:25:45
    resources in real time to support the needs,
  • 00:25:48
    that we have for ancillary services to carry
  • 00:25:50
    reserves and to support the energy needs in
  • 00:25:53
    in the market in real time. So real
  • 00:25:55
    time carbonization is going to step us forward
  • 00:25:58
    significantly in the efficiency of that dispatch, which
  • 00:26:01
    when you have an efficient dispatch, you lower
  • 00:26:03
    wholesale cost overall. There's a benefit to that
  • 00:26:06
    because you're able to move the lowest cost
  • 00:26:09
    resource into the energy delivery source and carry
  • 00:26:12
    higher cost resources in reserve so that you
  • 00:26:15
    give the market the lowest cost at at
  • 00:26:17
    all times. In addition, we're also gonna be
  • 00:26:19
    including for the first time batteries in that
  • 00:26:22
    co optimization so that we can better optimize
  • 00:26:25
    the in the utilization of batteries in that
  • 00:26:27
    real time model. And so that's a real
  • 00:26:29
    benefit, I think, for the market too that'll
  • 00:26:31
    drive efficiencies. So what it's what it's not
  • 00:26:35
    really driving towards necessarily is a significant change
  • 00:26:38
    in in any kind of a reliability posture.
  • 00:26:40
    Mhmm. What it's really doing is it's efficiently
  • 00:26:42
    operating and dispatching the the resources in the
  • 00:26:44
    market. And so what we look to then
  • 00:26:48
    for, you know, impacts to the longer term
  • 00:26:51
    reliability and the planning reserve margins is are
  • 00:26:53
    more issues around the way load can actually
  • 00:26:56
    be responsive to, you know, demand signals, the
  • 00:27:00
    way that the overall market sees the opportunity
  • 00:27:04
    for, investment based on the the the revenues
  • 00:27:09
    that are gonna be coming into the market
  • 00:27:10
    consistently to meet the growth signals that are
  • 00:27:12
    that are being sent. And so there's I
  • 00:27:15
    think about them a little bit separately in
  • 00:27:17
    the sense that you wanna always operate as
  • 00:27:19
    efficiently as you can. That's a good thing
  • 00:27:22
    for the the market itself. But then once
  • 00:27:25
    you kinda get to that level of efficiency,
  • 00:27:27
    you can't ever lose sight of what the,
  • 00:27:29
    you know, the big picture is, which is
  • 00:27:31
    making sure you're operating a grid for reliability
  • 00:27:33
    today and into the future. And so you
  • 00:27:36
    we still then we go right back to
  • 00:27:38
    what will be the those signals in the
  • 00:27:40
    market that will help to incentivize a balanced
  • 00:27:43
    portfolio of growth, and what will be the
  • 00:27:46
    opportunities we have to leverage some of the
  • 00:27:48
    advancements on the load side, both residential as
  • 00:27:51
    well as large loads, in order to improve
  • 00:27:55
    and and bring flexibility into the dispatch so
  • 00:27:57
    that we can get short term reliability benefits
  • 00:27:59
    from it. And and that's really how I
  • 00:28:01
    think about the opportunities. I kinda think of
  • 00:28:03
    one over here, the RTC+B and the benefits
  • 00:28:05
    it'll make in our efficiencies, But then we
  • 00:28:07
    have to kinda get right back on and
  • 00:28:09
    focus on how do we ensure that long
  • 00:28:10
    term reliability. And we're doing both? Yeah. We
  • Item 6 - Chairman Gleeson's questions for Pablo Vegas - 55999
    00:28:14
    need to do both. Thanks. Exactly. Pablo, on
  • 00:28:18
    slide four of your presentation, on the right
  • 00:28:23
    hand side, you know, h b fifty sixty
  • 00:28:25
    six load forecasting process. Your second bullet on
  • 00:28:28
    key takeaways is ERCOT has limited data to
  • 00:28:31
    be able to verify loads provided by TSP
  • 00:28:33
    officer tested load letters. Can you talk to
  • 00:28:38
    you know, right now there am I right?
  • 00:28:40
    There is not a standardized process for TSPs
  • 00:28:44
    to gather that information and then for for
  • 00:28:47
    it to be reported to you. So there
  • 00:28:48
    could be, some issues around, you know, one
  • 00:28:52
    TSP is is counting some amount of load
  • 00:28:55
    than another one isn't. There's no standard for
  • 00:28:58
    that. And then, one, I think that's true.
  • 00:29:01
    And then, two, that limited limitation on data,
  • 00:29:05
    what kind of problems does does that pose
  • 00:29:07
    for you all? Yeah. It's a it's a
  • 00:29:09
    really good question because, so much of the
  • 00:29:12
    foundation of the all of the reports that
  • 00:29:15
    get, you know, created and market analysis that
  • 00:29:18
    gets created is founded on kind of a
  • 00:29:20
    very core number here, which is what that
  • 00:29:22
    load is going to be in the future.
  • 00:29:24
    And so, today, you're you're correct. Each of
  • 00:29:28
    the TOs have, come up with a set
  • 00:29:31
    of criteria that they use for, determining whether
  • 00:29:35
    a customer load should be included in their
  • 00:29:37
    officer attestations that they provide to us. It
  • 00:29:40
    would be helpful for there to be more
  • 00:29:43
    consistency across that community and, transparency. And I
  • 00:29:49
    in terms of what that criteria is, because
  • 00:29:50
    I think there's a lot of questions as
  • 00:29:53
    to the, veracity of the size of that
  • 00:29:56
    load and kind of what makes it up
  • 00:29:59
    so that there could be some sort of
  • 00:30:01
    a gut check to know whether it's, you
  • 00:30:03
    know, well grounded based on expected trends. If
  • 00:30:06
    there's risk of duplication, but, you know, within
  • 00:30:08
    Texas or even outside of Texas, that's a
  • 00:30:10
    question that's, you know, come up. Could is
  • 00:30:12
    it possible? And then a very important question
  • 00:30:14
    around the timing of it. In a lot
  • 00:30:16
    of cases, you know, there's a strong belief
  • 00:30:18
    that the volume or the the magnitude of
  • 00:30:21
    the load is coming. But a big question
  • 00:30:23
    is to is it gonna be by 2030?
  • 00:30:25
    Or is it gonna be staged in over
  • 00:30:27
    time? I think when you look at the
  • 00:30:30
    way a load forecast like this gets used,
  • 00:30:33
    it's very effective for the purpose of transmission
  • 00:30:35
    planning. Because when you think about how you
  • 00:30:38
    do transmission development, you effectively have to build
  • 00:30:41
    the transmission capacity for what the peak utilization
  • 00:30:44
    is gonna be at a customer site when
  • 00:30:45
    you build that transmission infrastructure. You typically don't
  • 00:30:48
    stage in, you know, level sets of transformers
  • 00:30:51
    and breakers and such that can step its
  • 00:30:53
    way up to a a large load's full
  • 00:30:55
    capacity as it gets developed. You build for
  • 00:30:58
    that peak. And so whether it's within
  • 00:31:00
    a year or two or even three of
  • 00:31:03
    the forecasted time period is less consequential because
  • 00:31:05
    you're building infrastructure that's gonna be used and,
  • 00:31:09
    depreciated over 50+ years likely. And so
  • 00:31:12
    that it it's well suited for transmission planning.
  • 00:31:15
    But for reliability modeling, it's really important, specifically,
  • 00:31:20
    what year the load actually activates and turns
  • 00:31:23
    on. It makes a huge difference if we're
  • 00:31:26
    talking gigawatts of load that may be modeled
  • 00:31:29
    in 2030, but actually will be staged in
  • 00:31:32
    over the next two to three years and
  • 00:31:34
    could come on or eventually get to that
  • 00:31:37
    peak, but over a period of time. That
  • 00:31:39
    would have a material impact on the planning
  • 00:31:42
    reserves in each of those years that the
  • 00:31:44
    staging process happens. So the the staging we
  • 00:31:46
    hear a lot about with, you know, data
  • 00:31:48
    centers. So then would you argue that we
  • 00:31:52
    should have two separate processes for for load
  • 00:31:55
    forecasting, one for kind of our long range
  • 00:31:58
    transmission plan, one for kind of our reliability
  • 00:32:00
    metrics? I I do. I think it would
  • 00:32:02
    be very helpful to take the load forecast
  • 00:32:04
    that we get and to bisect it into
  • 00:32:06
    two views. One, that has kind of the
  • 00:32:09
    total capacity that's gonna be required for the
  • 00:32:11
    load that's coming. That'll help and inform the
  • 00:32:13
    transmission planning and help us stay ahead of
  • 00:32:15
    it. That's, I think, the big benefit we
  • 00:32:17
    got out of the legislation, in 2023 is
  • 00:32:20
    that now we can actually plan the infrastructure,
  • 00:32:23
    ahead of time to be able to support
  • 00:32:25
    the growth that's coming and not have it
  • 00:32:27
    become a bottleneck for it. So that's, I
  • 00:32:29
    think, a really significant benefit. But we've lost
  • 00:32:31
    some of the fidelity. We don't I don't
  • 00:32:33
    know if we've lost it. We don't have
  • 00:32:34
    the fidelity around when exactly the staging of
  • 00:32:38
    that load growth happens on a year by
  • 00:32:39
    year basis, and that's critically important for reliability
  • 00:32:43
    and operational modeling. And that's something that I
  • 00:32:46
    think we could think about ways to improve
  • 00:32:48
    that. It could be with better data submission
  • 00:32:51
    or more clear data submission from customer through
  • 00:32:53
    TOs to us. That could be part of
  • 00:32:55
    the story. We could just come up with
  • 00:32:57
    some ways to, you know, make some assumptions
  • 00:33:00
    and, you know, kind of divvy up a
  • 00:33:02
    full load level into a period of time
  • 00:33:04
    to reflect what we often see happen when
  • 00:33:06
    loads get built, that they come online in
  • 00:33:08
    stages, it can take multiple years, eventually get
  • 00:33:11
    to the full capacity. But those individual years
  • 00:33:14
    where we're doing operational, you know, type of
  • 00:33:16
    forecasting and and reliability modeling, very significant impacts
  • 00:33:20
    if they they stage out over time versus
  • 00:33:22
    all coming at once. Yeah. I mean, that
  • 00:33:26
    that's something I hadn't thought about, but, you
  • 00:33:28
    know, this has come up in multiple legislative
  • 00:33:31
    hearings now about the load forecast and and
  • 00:33:33
    how we're using it. So I you know,
  • 00:33:35
    as I sit here and I'd wanna think
  • 00:33:37
    about it more, but something like that seems
  • 00:33:39
    to make sense to see if if the
  • 00:33:41
    the one process, the one number makes sense
  • 00:33:44
    to use for everything we're trying to use
  • 00:33:47
    it for. And so I I think that's
  • 00:33:48
    that's a that's a good point. On on
  • 00:33:52
    slide eight, you have your let's see. You
  • 00:34:00
    have what I think you called your waterfall.
  • 00:34:02
    Yes. The changes. To the changes to the
  • 00:34:05
    CDR. Is it fair to say that those
  • 00:34:09
    changes are were done, primarily because of changes
  • 00:34:14
    in protocol and changes in law rule? Is
  • 00:34:16
    that why those are done? It is. And
  • 00:34:18
    so the the utilization of the LCCs, which
  • 00:34:21
    you see really two pretty significant changes here
  • 00:34:23
    in the center. The the 15.8 gigawatt, reduction,
  • 00:34:28
    on wind and solar contributions, and then the
  • 00:34:30
    addition of 11.6 gigawatts of storage contributions. That's
  • 00:34:34
    the LCC change biggest swings right there. And
  • 00:34:37
    then the, the other ones, grow as you
  • 00:34:40
    as we look further in time, you'll see
  • 00:34:42
    the inclusion of the TSB officer letter loads
  • 00:34:44
    become a pretty a much larger portion of
  • 00:34:46
    the waterfall when you look at a 2030,
  • 00:34:48
    version of this for, you know, from May
  • 00:34:51
    to to to December. So and these were
  • 00:34:53
    all changes that were worked through in that
  • 00:34:56
    protocol change for the report. So it's fair
  • 00:34:58
    to say the the inputs into what gets
  • 00:35:01
    reported in this are are governed by protocols
  • 00:35:03
    and laws. That's exactly right. Okay. And I
  • 00:35:06
    guess the last thing, not really a question,
  • 00:35:08
    more of a point. So right now, you're
  • 00:35:10
    going through the kind of load submission process.
  • 00:35:14
    Is it would it be accurate to say,
  • 00:35:17
    I know you don't typically publish that till
  • 00:35:19
    March, April time frame somewhere in there, that
  • 00:35:21
    we can expect to see a lot more
  • 00:35:23
    load being reported? Yeah. We're we're just starting
  • 00:35:27
    to get the, initial submissions from the transmission
  • 00:35:30
    operators, and there are definitely changes. There's some,
  • 00:35:34
    inputs and outputs, some some decreases and some
  • 00:35:36
    increases. But overall, it does look like the
  • 00:35:39
    general trend is, is a a fairly significant
  • 00:35:41
    increase in the load forecast even from what
  • 00:35:44
    this last one, which which showed a pretty
  • 00:35:46
    significant increase, in 2024. We expect another one
  • 00:35:50
    that shows a fairly significant increase. All the
  • 00:35:53
    more reason why it's gonna become very important,
  • 00:35:55
    I think, to have a better understanding of
  • 00:35:57
    the criteria that goes into that for the
  • 00:36:00
    parts that are not, structured with, you know,
  • 00:36:02
    the with the signed interconnection agreement. And I
  • 00:36:05
    think also very important to have a conversation
  • 00:36:07
    that that you just noted, which is what's
  • 00:36:09
    the best way to really reflect this load
  • 00:36:12
    from a reliability modeling and reliability reporting in
  • 00:36:16
    contrast to the utilization for transmission planning? Yeah.
  • 00:36:20
    I think I think that's right. I think
  • 00:36:21
    it's also you know, I'm sure some folks
  • 00:36:24
    who are are seeing the CDR this morning
  • 00:36:27
    are are seeing some of these numbers and
  • 00:36:28
    are probably struck by them. But if we're
  • 00:36:30
    gonna if we anticipate seeing even larger load
  • 00:36:33
    numbers in the next report, the the trend
  • 00:36:35
    we see here will probably be reflected, even
  • 00:36:38
    more so in the next CDR. That's right.
  • 00:36:40
    And that's why the timing is such a
  • 00:36:41
    critical element such a critical element because that's
  • 00:36:44
    really what this is based off of point
  • 00:36:46
    in times, assumptions, straight math. And if we're
  • 00:36:50
    if we're able to better reflect a more
  • 00:36:52
    accurate kind of pacing based on what we
  • 00:36:54
    think will actually happen, I think we'll see
  • 00:36:56
    a real benefit in the quality of the
  • 00:36:58
    of these reports and analyses. Okay. Alright. One
  • 00:37:01
    more question. Sorry. On 11 on your chart
  • 00:37:05
    Yeah. When we're looking at 2025, '2026
  • 00:37:07
    why are we not starting at the
  • 00:37:11
    same point? They're all they're 29.8, 26.7.
  • 00:37:15
    I mean, if we're starting from
  • 00:37:19
    the point of today, why are we not
  • 00:37:21
    all at the same dot? Does that make
  • 00:37:22
    sense? Yeah. I think it's it's what it's
  • 00:37:26
    doing is it's it's factoring in some of
  • 00:37:29
    these changes actually, what we would expect throughout
  • 00:37:33
    this year's cycle. So '25, '26. So we're looking
  • 00:37:36
    at right here the upcoming winter that that
  • 00:37:38
    we're gonna be in. This is where it
  • 00:37:39
    starts. It doesn't it's not in the winter
  • 00:37:41
    we're in now, January 25 or February 25.
  • 00:37:44
    It's winter December 25 into, January, February '20
  • 00:37:49
    '6. And so it's it's pushing forward some
  • 00:37:51
    of these assumptions to to that time. To
  • 00:37:53
    a little bit of it. Okay. Yeah. That
  • 00:37:54
    makes sense. That's why it's starting from a
  • 00:37:55
    different place. Thank you. Pablo, thanks again for
  • 00:37:59
    being here and taking the time to to
  • 00:38:01
    lay this out. I'm sure we'll have many
  • 00:38:04
    more discussions and and a lot more questions
  • 00:38:06
    in the future as you do this. But,
  • 00:38:08
    but, you know, I'm I'm happy with the
  • 00:38:10
    changes you all made, to show the different
  • 00:38:12
    scenarios. I think that's a that's a good
  • 00:38:14
    change, and appreciate all the work on this
  • 00:38:15
    from you and your team. Alright. Thanks so
  • 00:38:17
    much. Appreciate your questions, and look forward to
  • 00:38:19
    talking about this further. So like I said,
  • 00:38:22
    thou said, I know we have another item
  • 00:38:24
    in here on magnitude for the reliability standard,
  • 00:38:26
    but, and and Matt's here for that. But
  • 00:38:29
    I think it's probably we have TNMP here
  • 00:38:31
    to talk about, their resiliency plan. So, I
  • 00:38:35
    think we'll go back up to the top
  • 00:38:36
    of the agenda and start at item number
  • 00:38:39
    two under contested cases. Shelah, will you lay
  • Item 2 - Docket No. 56954; SOAH Docket No. 473-24-25125 – Application of Texas-New Mexico Power Company for Approval of a System Resiliency Plan
    00:38:42
    out Item No. 2, please? Item No. 2
  • 00:38:47
    is Docket No. 56954,
  • 00:38:50
    the application of Texas New Mexico Power Company
  • 00:38:53
    for approval of a system resiliency plan. Before
  • 00:38:56
    you is a second corrected proposed order that
  • 00:38:59
    addresses an unopposed agreement in this docket, and
  • 00:39:02
    the Chairman filed the memo. Thank you, Shelah.
  • 00:39:05
    Yeah. So the memo in this similar to
  • 00:39:07
    the the previous two resiliency plans just to
  • 00:39:09
    give notice to the utility to to be
  • 00:39:12
    prepared to make a presentation. I think it's
  • 00:39:14
    appropriate as we've done in the previous two,
  • 00:39:18
    let TNMP make their presentation, have us ask
  • 00:39:20
    questions, and then take a little time to,
  • 00:39:23
    to get more briefing and and think through
  • 00:39:25
    the responses to those questions as we decide
  • 00:39:28
    whether or not to approve, deny, or modify
  • 00:39:31
    their, resiliency plan, if that's okay with you
  • 00:39:33
    all. Okay. Good morning. Good morning. Good morning.
  • Item 2 - Stacy Whitehurst – VP of Regulatory Affairs - overview of System Resiliency Plan - 56954
    00:39:40
    Thank you. For the record, Stacy Whitehurst, the
  • 00:39:43
    vice president of regulatory affairs for TNMP. Once
  • 00:39:45
    again, congratulations on your quick, meeting and or
  • 00:39:48
    Senate Finance. Good morning, Commissioners. For the record,
  • 00:39:52
    my name is Stacy Whitehurst, Vice President of
  • 00:39:55
    Regulatory Affairs for TNMP. Joining me today are
  • 00:39:58
    Chris Gerety, TNMP's Vice President of
  • 00:40:01
    System Reliability and Technical Services. Keith Nix,
  • 00:40:04
    TNMP's Vice President of Operations. And Stephanie
  • 00:40:07
    Sparks, Outside Counsel with Vedder Price. Before we
  • 00:40:10
    begin, I would like to express our sincere
  • 00:40:12
    appreciation to the parties involved in this proceeding
  • 00:40:15
    for their collaboration, which has enabled us to
  • 00:40:18
    present an uncontested settlement to the Commission for
  • 00:40:20
    approval. We also extend our gratitude Commission Staff
  • 00:40:24
    for their diligent work and analysis, particularly given
  • 00:40:27
    the expedited timeline for the system resiliency filings.
  • 00:40:31
    TNMP serves as the map shows, TNMP serves
  • 00:40:34
    a diverse geographic area across Texas with each
  • 00:40:37
    region facing unique resiliency challenges. Our West Texas
  • 00:40:42
    service territory encompassing the Permian Basin is susceptible
  • 00:40:45
    to severe thunderstorms, lightning, and wildfires. North Texas,
  • 00:40:50
    including the suburbs north of the GFW Metroplex
  • 00:40:53
    and communities along the Red River, are is
  • 00:40:55
    vulnerable to thunderstorms, lightning, tornadoes, and ice storms.
  • 00:41:00
    Central Texas, which is kind of Northwest Of
  • 00:41:02
    Waco, also experiences thunderstorms, lightning, tornadoes, and wildfires.
  • 00:41:07
    Finally, our Gulf Coast service territory, South of
  • 00:41:10
    Houston is subject to hurricanes. TNMP is pleased
  • 00:41:15
    to present a system resiliency plan for our
  • 00:41:18
    customers tailored to the specific needs of each
  • 00:41:21
    of our service area and the distinct resilient
  • 00:41:24
    event it faces. In developing the hardening, modernization,
  • 00:41:28
    vegetation management, and operational technology enhancements, and flood
  • 00:41:31
    mitigation components of our SRP, TNMP engaged 1898
  • 00:41:35
    and company. They're now also Oncor
  • 00:41:38
    major event data spanning a hundred and seventy
  • 00:41:40
    years for tropical cyclones and twenty five years
  • 00:41:42
    for other extreme weather events. A member of
  • 00:41:45
    eighteen ninety eight and company team is present
  • 00:41:48
    today should you have any specific questions regarding
  • 00:41:52
    I'm so sorry. I didn't mean to interrupt.
  • 00:41:54
    I was gonna I wanted to pause for
  • 00:41:55
    just a moment because Connie asked a really
  • 00:41:57
    good question, which is, is this is this
  • 00:41:59
    demonstrative best here or if we should put
  • 00:42:01
    it behind the commissioners where you can see
  • 00:42:03
    it? Oh, no. It's it's fine. It's fine.
  • 00:42:05
    It's fine where it is? I got handouts
  • 00:42:06
    that you see if you all need. Perfect.
  • 00:42:08
    Thank you. Okay. Their analysis incorporates major events
  • 00:42:13
    data spanning a 70 for tropical cyclones and
  • 00:42:16
    twenty five years for other extreme weather events.
  • 00:42:19
    A member of eighteen ninety eight and company
  • 00:42:21
    team is present today. Should you have a
  • 00:42:23
    specific questions regarding their analysis? TNMP's SRP is
  • 00:42:28
    structured around eight key resiliency measures, distribution system
  • 00:42:32
    resiliency, distribution system protection modernization, vegetation management, wildfire
  • 00:42:38
    mitigation, flood mitigation, enhanced operation system technology, cybersecurity,
  • 00:42:44
    and physical security. I'll now turn over the
  • 00:42:47
    presentation to Chris and Keith who will provide
  • 00:42:49
    provide a overview of these eight measures. Hi.
  • Item 2 - Chris Gerety – VP of Technical Services & System Reliability - Distribution System Resiliency Measure - 56954
    00:42:56
    Good morning. I'm Chris Garrity, TNMP's vice president
  • 00:42:59
    of technical services and system reliability. I think
  • 00:43:01
    the mic's working. It is. So, measure number
  • 00:43:06
    one in our SRP is the distribution system
  • 00:43:09
    resiliency measure. We have four programs within this
  • 00:43:12
    measure. One aimed at hardening full circuits or
  • 00:43:15
    protection zones, to ensure we kinda maximize the
  • 00:43:19
    benefit to those whole protection zones versus kinda
  • 00:43:21
    piecemealing at a time. And that's backed by
  • 00:43:24
    a benefit cost analysis, that justifies those investments.
  • 00:43:29
    And then our circuit overhead inspections and hardening
  • 00:43:31
    program, those are really geared towards, hole protection
  • 00:43:35
    zones that do not meet those BCR thresholds
  • 00:43:37
    and finding the most, critical elements within those
  • 00:43:39
    circuits and replacing those, one at a time.
  • 00:43:43
    And then, we do not have a significant,
  • 00:43:46
    portion of our system underground at this time.
  • 00:43:49
    And so we felt like we lacked some
  • 00:43:51
    of the kind of, data we needed to
  • 00:43:54
    propose significant or widespread undergrounding. So we have
  • 00:43:57
    two pilot programs, a pilot strategic undergrounding program
  • 00:44:01
    for us to gather those those costs and
  • 00:44:03
    make a more informed decision in future SRP
  • 00:44:06
    filings. And then we do, have a strategic
  • 00:44:08
    undergrounding for freeways, and that's aimed at eliminating
  • 00:44:12
    overhead crossings for ingress and egress routes during
  • 00:44:15
    resiliency events. Turning to slide four, our next
  • 00:44:20
    measure is our distribution system protection and modernization.
  • 00:44:24
    Two programs in this measure, the mainline automated
  • 00:44:27
    reclosing deployment, replaces and installs additional modern reclosers,
  • 00:44:32
    to allow for advanced and remote switching of
  • 00:44:34
    our system during resiliency events. And then a
  • 00:44:37
    lateral recloser deployment, which installs reclosing fuse devices,
  • 00:44:43
    at key points within our system to, minimize,
  • 00:44:47
    momentary outages to our to our customers. We
  • 00:44:49
    don't have to roll a truck and those
  • 00:44:50
    customers come back online much more quicker quickly.
  • 00:44:55
    Keith, I'll turn it over to you for
  • Item 2 - Keith Nix – VP of Operations - Vegetation Management - 56954
    00:44:56
    vegetation management. Thank you. Good morning, Commissioners. My
  • 00:44:59
    name is Keith Nix, Vice President of Operations
  • 00:45:02
    for TNMP. And I'm here to discuss our
  • 00:45:04
    vegetation management measure, four programs within the measure.
  • 00:45:08
    Program number one is proactive vegetation management. So
  • 00:45:12
    TNMP will be transitioning from a
  • 00:45:14
    reactive or reliability based approach to a cycle
  • 00:45:17
    based approach. We've split that into two different
  • 00:45:20
    cycles to put it upon our operating areas.
  • 00:45:22
    The Gulf Coast area is on a faster
  • 00:45:24
    cycle. It's on a five year cycle, based
  • 00:45:27
    upon tree growth and data that that we
  • 00:45:29
    obtained from lessons learned from hurricane barrel for
  • 00:45:31
    sure and six years everywhere else. An enhancement
  • 00:45:35
    of that program is that we will be
  • 00:45:36
    revisiting and looking at multiphase circuits halfway through
  • 00:45:40
    each of those measures as well each of
  • 00:45:42
    those, inspections as well. Really focusing on our
  • 00:45:49
    prime areas of area hurricane and HRAs initially
  • 00:45:54
    for high risk areas for wildfire for vegetation
  • 00:45:56
    management, obviously. Second second program is our enhanced
  • 00:46:00
    tree risk assessment program. So we'll be moving
  • 00:46:03
    from a level one, mostly visual tree risk
  • 00:46:06
    program to a more enhanced level two where
  • 00:46:08
    we'll be actually visiting and assessing tree health.
  • 00:46:12
    That's really key. Lesson another lesson learned from
  • 00:46:14
    Hurricane Beryl is we'll be focusing on trees
  • 00:46:17
    that were outside of the right of way
  • 00:46:19
    that impacted us during hurricane Beryl. Also lessons
  • 00:46:22
    learned from windstorms and various events in North
  • 00:46:25
    Texas as well. Third, we'll be having a
  • 00:46:28
    remote sensing program, which derives the data needed
  • 00:46:30
    to perform the inspections in one and two.
  • 00:46:34
    That will also be using newer technologies such
  • 00:46:37
    as LIDAR, aerial enhancements to to develop the
  • 00:46:39
    data needed to help develop the programs going
  • 00:46:42
    forward and focus those those resources. And finally,
  • 00:46:46
    risk based system for inspection wildfire mitigation measure,
  • 00:46:59
    we have three programs, asset mitigation, So under
  • 00:47:01
    the wildfire mitigation measure, we have three programs.
  • 00:47:04
    Asset protection is the first program that we
  • 00:47:06
    that we're that we're including. That'll include fire
  • 00:47:10
    hardening of facilities in the high risk assessment
  • 00:47:12
    areas. As we've we've shared with you before,
  • 00:47:15
    we've developed a wildfire mitigation program where we
  • 00:47:18
    identified all of our high risk areas. So
  • 00:47:21
    under the fire hardening, we'll be doing thing
  • 00:47:23
    items such as changing out wooden cross arms
  • 00:47:25
    to fiberglass cross arms, retrofitting poles with fire
  • 00:47:29
    retardant wraps, a pole hardening, and and basically
  • 00:47:33
    infrastructure hardening within those HRAs. Second piece of
  • 00:47:37
    that program will be fuels management along transmission
  • 00:47:39
    right away. So clearing defensible space underneath transmission
  • 00:47:43
    right away will be the focus in the
  • 00:47:45
    HRAs as well. Program number two will be
  • 00:47:48
    situational awareness. We're looking at gathering real time
  • 00:47:52
    data inside of our HRAs based off of
  • 00:47:55
    weather stations, also cameras that that help with
  • 00:47:59
    smoke smoke detection that will notify us if
  • 00:48:02
    we TNMP resources, if we see,
  • 00:48:06
    any sort of fire ignition, in in the
  • 00:48:08
    HRAs. Info get we will be sharing that
  • 00:48:12
    information and gathering that information, sharing that with
  • 00:48:14
    first responders in the local area to help,
  • 00:48:16
    with, response. Also, we'll be sharing we will
  • 00:48:20
    use that data and develop a fire potential
  • 00:48:22
    index based off of real time data during
  • 00:48:24
    the day. Finally, ignition mitigation. So one of
  • 00:48:28
    the other larger issues that we you have
  • 00:48:31
    inside of the HRAs is how can you
  • 00:48:33
    eliminate sparks that come from equipment. So and
  • 00:48:36
    under ignition mitigation, excuse me, we'll be replacing
  • 00:48:40
    equipment such as fuses that emits sparks, capacitor
  • 00:48:43
    banks. We'll be installing fast tripping reclosing so
  • 00:48:47
    that way we can limit sparks when you
  • 00:48:49
    do have a contact event covering jumpers and
  • 00:48:52
    installing more wildlife guards. Okay. And then turning
  • 00:48:58
    to slide seven, flood mitigation. Very straightforward but
  • 00:49:01
    very important measure. We took an inventory of
  • 00:49:05
    the flooding probability of substations across our entire
  • 00:49:08
    system. And this measure will enhance two substations
  • 00:49:11
    and raise the either the substation or equipment,
  • 00:49:14
    so that it does not, it's not subject
  • 00:49:16
    to flooding and wouldn't take an extended recovery
  • 00:49:19
    or, response time. Enhanced operations systems technology, I
  • 00:49:25
    think as you heard in key statements, we're
  • 00:49:28
    proposing to deploy technology that's new to us
  • 00:49:31
    and maybe new in the industry. And so
  • 00:49:33
    this measure gives us a strategy road map
  • 00:49:35
    and governance framework to ensure the decisions we're
  • 00:49:38
    making on procuring technology, are fully vetted long
  • 00:49:42
    term plans that will be fully utilized. A
  • 00:49:45
    fully enabled OMS, I think another lesson learned
  • 00:49:47
    from Beryl is the importance of an OMS
  • 00:49:49
    system that's fully functioning and reporting into an
  • 00:49:51
    outage map. Our goal is to enhance our
  • 00:49:54
    existing OMS capability and and build on what
  • 00:49:57
    we have, to have a fully functioning system.
  • 00:50:00
    A resilient high capacity field area network. We
  • 00:50:03
    talked about deploying mainline reclosers throughout our system.
  • 00:50:07
    One of the important things is those be
  • 00:50:08
    remotely controlled by our operation centers. And so
  • 00:50:11
    this will deploy a, high capacity field area
  • 00:50:15
    network to get signals from our reclosers back
  • 00:50:17
    to our system operation center. And then project
  • 00:50:20
    and portfolio management reporting, again, we, you know,
  • 00:50:24
    recognize, the responsibility to wisely execute a plan
  • 00:50:28
    like this. And so we've included, time and
  • 00:50:32
    cost to ensure we have the project portfolio
  • 00:50:35
    management reporting skills and and and capabilities, to
  • 00:50:39
    to execute. Turning to slide nine, cybersecurity. So
  • 00:50:47
    this is about sort of there's there's four
  • 00:50:49
    programs in here, but generally speaking on those
  • 00:50:51
    four program or those, five programs rather, it's
  • 00:50:55
    it's having protections in place and being able
  • 00:50:58
    to monitor those protections and centralizing that net
  • 00:51:00
    monitoring capability. And then the last one, physical
  • 00:51:05
    security. I I don't know that we've mentioned
  • 00:51:07
    much before this, but the vast majority of
  • 00:51:10
    our our resiliency plan is is, distribution system
  • 00:51:13
    based. This is a a slight exception to
  • 00:51:15
    that. It's partially distribution, but there's some transmission
  • 00:51:17
    substations. And so we have two programs here,
  • 00:51:21
    hardening fencing around, the most vulnerable or sensitive
  • 00:51:24
    sites, as well as deploying, technology to those
  • 00:51:28
    substations for, surveillance and early threat detection. So
  • 00:51:44
    I, we're available for any questions or any,
  • 00:51:47
    follow-up or any more details that you'd like.
  • 00:51:50
    Sure. Yeah. Thank you for being here and
  • 00:51:52
    and for laying out that that high level
  • Item 2 - Commissioner Hjaltman's questions for TNMP - 56954
    00:51:54
    overview. Commissioner's questions of TNMP? I have a
  • 00:51:58
    few. Just to start with, on the pilot
  • 00:52:01
    project for undergrounding, I guess, y'all have not
  • 00:52:07
    done any undergrounding so far with any of
  • 00:52:09
    your electric, or why is it pilot? What
  • 00:52:11
    are you hoping to learn from that? Yeah.
  • 00:52:13
    So we we have, some portions of our
  • 00:52:16
    system undergrounded. Most specifically, those are serving subdivisions,
  • 00:52:21
    where the developers essentially paid us to underground
  • 00:52:24
    those those lines throughout their development. Okay. We
  • 00:52:27
    don't have a lot of mainline, three phase
  • 00:52:30
    mainline underground, a significant amount of that. I
  • 00:52:33
    think that as you execute on undergrounding projects,
  • 00:52:37
    there there can be significant challenges that can
  • 00:52:40
    drive time and cost up. And as you
  • 00:52:42
    look at how to justify those through sort
  • 00:52:45
    of that framework of benefit to cost analysis,
  • 00:52:47
    those are the cost part is a big
  • 00:52:49
    driver. And if you get that wrong and
  • 00:52:51
    you justify projects that actually may might not
  • 00:52:53
    have been justifiable, then we'll we we would
  • 00:52:56
    have to answer for those, for those issues.
  • 00:52:58
    So I think that's the main piece is
  • 00:53:00
    that we wanna build some experience with with
  • 00:53:04
    undergrounding mainline extensively, or other laterals extensively before
  • 00:53:09
    we commit to, sort of a a rigid
  • 00:53:12
    framework of this is when you justify underground
  • 00:53:14
    and this is when you don't justify underground.
  • 00:53:16
    So as far as coming back to the
  • 00:53:18
    commission with what you learned from that, what
  • 00:53:20
    will we be expecting as far as data
  • 00:53:23
    points, I guess? I I think we'll have
  • 00:53:25
    a better understanding of the costs or difficulties
  • 00:53:27
    of doing it. Yeah. And and I think
  • 00:53:29
    we'll have a more robust understanding of how
  • 00:53:31
    to frame that in a benefit to cost
  • 00:53:33
    analysis. So I think you'll see that. Okay.
  • 00:53:36
    And then I'm gonna jump to vegetation. Sorry.
  • 00:53:40
    I I think we probably all like to
  • 00:53:42
    see you be more proactive, less reactive. That's
  • 00:53:44
    always, key. The amount you've asked for from
  • 00:53:50
    what '19, 1898 suggested was a twenty year
  • 00:53:54
    out cost, and you asked for a third
  • 00:53:56
    of what they said. But you're doing it
  • 00:53:58
    in a shorter time period. So do you
  • 00:54:00
    think can you can you walk through how
  • 00:54:02
    that's going to be used? Yes. So, basically,
  • 00:54:04
    this is a three year plan. And so,
  • 00:54:06
    basically, this is the amount that we've included
  • 00:54:09
    for recovery or a part of this plan
  • 00:54:11
    is the three years. So as Chris or
  • 00:54:13
    as Keith discussed that, you know, it's gonna
  • 00:54:15
    be a five year in The Gulf Coast
  • 00:54:17
    and a six year throughout rest of our
  • 00:54:19
    service territory. Basically, in three or two and
  • 00:54:22
    a half years, we'll be making another filing
  • 00:54:24
    for our second SRP, which will include the
  • 00:54:27
    additional money to, get us to finish year
  • 00:54:30
    four and year five in The Gulf Coast
  • 00:54:32
    and then, four, five, and six in the
  • 00:54:35
    rest of the service territory. What they laid
  • 00:54:36
    out was a twenty year coast cost for
  • 00:54:38
    this. So you're gonna somehow be able to
  • 00:54:40
    do it in three years? Could you could
  • 00:54:52
    you repeat that for me? So in in
  • 00:54:54
    1898 suggest a twenty year cost. They laid
  • 00:54:57
    it out at at 308,000,000. And you're only
  • 00:54:59
    going for a third of that amount, which
  • 00:55:02
    is fine. But how you're going to get
  • 00:55:04
    a twenty year cost done in that short
  • 00:55:06
    amount of time, you'll be able to get
  • 00:55:08
    the vegetation management people to be able to
  • 00:55:10
    do it that quickly. Jason's coming up. I'm
  • 00:55:12
    sorry. I'm pulling. Yeah. Jason De Stigter with 1898
  • 00:55:15
    is gonna help us answer that
  • 00:55:16
    from his. Thank you. From his work. Yeah.
  • Item 2 - Jason De Stigter - 1898 - Benefit cost analysis - 56954
    00:55:21
    Jason De Stigter with 1898. So
  • 00:55:24
    when we laid out the benefit cost analysis,
  • 00:55:27
    we wanted to look at a twenty year
  • 00:55:29
    time horizon. And so with vegetation man with
  • 00:55:33
    the overhead hardening sort of projects, you can
  • 00:55:36
    invest today and get benefits for forty years.
  • 00:55:38
    And so it's just one investment now and
  • 00:55:41
    then benefits for forty years. With vegetation management,
  • 00:55:44
    you have to continue to stay on top
  • 00:55:46
    of it. So what we laid out in
  • 00:55:48
    that benefit cost analysis is doing veg management
  • 00:55:51
    per the cycles for twenty years Okay. And
  • 00:55:53
    then getting benefits for those twenty years. So
  • 00:55:55
    when you look at, the cost numbers within
  • 00:55:58
    our report, you have to understand that it's
  • 00:56:00
    more assuming that continued o and m tail,
  • 00:56:03
    for the old time horizon because we wanted
  • 00:56:04
    to justify the program as a whole. Is
  • 00:56:07
    it worth is it worth the investment to
  • 00:56:09
    do that? Okay. Perfect. Thank you. That's all
  • Item 2 - Commissioner Hjaltman's questions on vegetation for TNMP
    00:56:11
    cool. And then for, again, the vegetation, is
  • 00:56:15
    this people you will have to go out
  • 00:56:17
    and hire? Do you have those people on
  • 00:56:18
    staff currently? Are you going outsourcing for those?
  • 00:56:23
    I think it's a combination of both. So
  • 00:56:25
    we'll be have to we'll definitely be outsourcing
  • 00:56:27
    the labor piece of that. And then we'll
  • 00:56:29
    be hiring some experts, internal experts for for
  • 00:56:32
    assessment. And we'll also be working with a
  • 00:56:34
    third party for systems development. Okay. And then
  • 00:56:40
    on some of the, metrics, obviously, I think
  • 00:56:44
    the importance of the metrics are so that
  • 00:56:46
    we can get the data points, and we
  • 00:56:48
    put them in the rule for a reason.
  • 00:56:50
    I do have concern on the wildfire mitigation
  • 00:56:52
    measures. Can you speak through you know, you're
  • 00:56:55
    only capturing the wildfires that originate from your
  • 00:56:58
    facilities. You're not making the area as the
  • 00:57:02
    whole. Can you speak to that a little
  • 00:57:03
    more? Sure. I I can handle that one.
  • 00:57:07
    So part of the data management will be
  • 00:57:09
    looking at ignitions from outside of TNMP's area
  • 00:57:12
    too. And and the data management and the
  • 00:57:14
    data analysis will be helping to see how
  • 00:57:17
    fires develop from even outside of the TNMP
  • 00:57:20
    area to how they would be potentially impacting
  • 00:57:23
    TNMP facilities. Okay. So we'll be monitoring. We'll
  • 00:57:27
    we'll have staff on board that'll actually be
  • 00:57:29
    monitoring external ignitions. We'll be able to hopefully
  • 00:57:32
    model those as data becomes available to see
  • 00:57:35
    how they they progress towards T and P
  • 00:57:37
    facilities. Okay. And then, this was brought up,
  • 00:57:41
    and I I have to say I kind
  • 00:57:42
    of agree and would like to look at
  • 00:57:43
    maybe making this change in the safety. You've
  • 00:57:46
    noted your geographic region is very, you know,
  • 00:57:48
    diverse across the state, and it's segmented. Having
  • 00:57:52
    some more direct correlation to those and separating
  • 00:57:55
    out your safety and safety so we can
  • 00:57:57
    go back and track what you're doing, I
  • 00:57:58
    think, is a beneficial idea, something to follow,
  • 00:58:01
    so that we can have some direct data
  • 00:58:03
    and the consumers can see directly what is
  • 00:58:05
    affecting them and not. You're saying regionally, essentially?
  • 00:58:08
    Yes. Yeah. Okay. Yes. Gulf, Central, Northwest. Yeah.
  • 00:58:11
    Yes. Okay. Yes. Exactly. And then a little
  • 00:58:14
    clarification on the metrics that are and aren't
  • 00:58:17
    in the report. It was a little confusing
  • 00:58:19
    of what ended up actually finally being included.
  • 00:58:22
    So if that's something that could be clarified,
  • 00:58:24
    I think staff could speak to it too
  • 00:58:25
    if need to be. It it it was
  • 00:58:28
    not clear what finally became part of the
  • 00:58:30
    report or not. Yeah. So I think I
  • 00:58:32
    think, the metrics that are in our report
  • 00:58:36
    are the metrics, save two modifications to two
  • 00:58:39
    metrics that are in the settlement agreement. It
  • 00:58:41
    just wasn't clear for everyone what that was.
  • 00:58:43
    So Okay. There might need to be clarification
  • 00:58:45
    again. So say that again. So there were
  • 00:58:49
    two metrics that were put in the report
  • 00:58:52
    that are not included in the settlement agreement?
  • 00:58:54
    No. I'm sorry. There are two revised metrics
  • 00:58:57
    in the settlement agreement that modified the table
  • 00:59:00
    of metrics within our report. Okay. I think
  • Item 2 - Commissioner Jackson's questions for TNMP - 56954
    00:59:04
    it just wasn't clear totally. Just a follow-up
  • 00:59:10
    question, because they asked previously about the, the
  • 00:59:15
    wildfire mitigation metrics and the fact that we're
  • 00:59:18
    not necessarily it it looked to me including
  • 00:59:22
    those, wildfires that were not, sourced from the
  • 00:59:26
    TNMP facilities.
  • 00:59:30
    You mentioned that you were gonna be monitoring
  • 00:59:32
    them, but are you actually planning on including
  • 00:59:34
    those in the metrics? So I think our
  • 00:59:39
    thought process at the time was that, the
  • 00:59:41
    fires that we directly, you know, responsible for
  • 00:59:44
    starting through, and measuring our, asset protection and
  • 00:59:49
    ignition mitigation programs was the intent of those
  • 00:59:52
    of that metric. And, I mean, you're hardening
  • 00:59:54
    your facilities. It seems like they should be
  • 00:59:55
    hardening against regardless of where the source of
  • 00:59:58
    the ignition source was. So is so how
  • 01:00:03
    would you address that Well, I think I
  • 01:00:06
    think when whenever you do have an outside
  • 01:00:08
    ignition source, you know, after the fact, you're
  • 01:00:10
    gonna go do analysis on if it impacts
  • 01:00:12
    TNMP facilities, then you'll track
  • 01:00:15
    and and see what that impact is. And
  • 01:00:18
    then we'll we'll we'll have a metric around
  • 01:00:20
    if we had x amount of exposure of
  • 01:00:23
    line that was hardened, what was or wasn't
  • 01:00:26
    the impact on that? How how do we
  • 01:00:28
    we need to measure how we're gonna be
  • 01:00:29
    successful. So, like, for example, your pole wrapping.
  • 01:00:33
    So I would expect that we would go
  • 01:00:35
    do post fire analysis from a ignition source
  • 01:00:37
    outside if it rolled through TNMP
  • 01:00:39
    facilities and then go look and see if
  • 01:00:41
    the success of the pole wraps. Did the
  • 01:00:43
    pole wraps hold up? Did the poles fall?
  • 01:00:45
    And those kinds of things. Mhmm. So we'd
  • 01:00:47
    be tracking that as part of our program.
  • 01:00:49
    Tracking as part of your program, but still
  • 01:00:50
    not including it in your metrics? I think
  • 01:00:53
    that's a detail we can add later on
  • 01:00:55
    for sure. But, you know, we're we're we're
  • 01:00:57
    gonna have to get experience. Unfortunately, we don't
  • 01:01:00
    have a whole lot of it. I mean,
  • 01:01:01
    fortunately, we don't have a whole lot of
  • 01:01:02
    experience with wildfire in those areas. So I
  • 01:01:05
    think that's gonna be something that that will
  • 01:01:07
    be event driven, unfortunately. Yeah. And I I
  • 01:01:09
    think the other part of it is I'm
  • 01:01:10
    I'm looking at the the the metric table,
  • 01:01:13
    is that, you know, as a wildfire might
  • 01:01:15
    burn across our service territory, we might not
  • 01:01:17
    know about it. Right? So I don't know
  • 01:01:18
    that we could commit to reporting on all
  • 01:01:21
    wildfires that that burn in our service territory
  • 01:01:23
    or across our facilities. They might not cause
  • 01:01:25
    an outage. We might not know about them,
  • 01:01:27
    I think, is the other difficulty. So, you
  • 01:01:32
    know, just kinda taking a look at, you
  • 01:01:34
    know, what the I guess, the game plan
  • 01:01:37
    would be moving forward and, maybe doing a
  • 01:01:40
    variance analysis between what was initially proposed and
  • 01:01:43
    what is in the settlement. There were three
  • 01:01:46
    areas, I guess, that had, significant change. One
  • 01:01:49
    being the flood mitigation, the other being, wildfire
  • 01:01:54
    mitigation, and then also something within vegetation management.
  • 01:01:58
    But just specifically with the wildfire, mitigation, there
  • 01:02:02
    was, I I think, a big impact on
  • 01:02:05
    situational awareness, which, I mean, that's the remote
  • 01:02:08
    sensing technology. That's the cameras that theoretically would
  • 01:02:12
    know whether a fire was coming through Right.
  • 01:02:14
    Your area. Also, preventative and, also something that,
  • 01:02:20
    you you know, in my mind helps you
  • 01:02:22
    to kind of, you know, do your risk
  • 01:02:24
    assessment. So, I mean, in your opinion, is
  • 01:02:28
    that something that quite frankly might be worth
  • 01:02:31
    keeping? Yeah. I I would just say I
  • 01:02:35
    think the reduction in the cost, the the
  • 01:02:37
    O&M cost of the situational awareness
  • 01:02:39
    program within the wildfire mitigation measure. I mean,
  • 01:02:42
    the reason we were, agreeable to deferring that
  • 01:02:45
    that expense was we don't think it necessarily
  • 01:02:48
    diminished the capabilities by shifting priorities within that
  • 01:02:50
    measure or that program. So initially, you you
  • 01:02:54
    started out and you had, I think it
  • 01:02:56
    was a hundred a hundred cameras. So and
  • 01:02:59
    you you actually specified what the facilities would
  • 01:03:01
    be. So what what would that, you know,
  • 01:03:06
    what what would you end up with? I
  • 01:03:08
    think we'll end up with a very similar
  • 01:03:09
    system, just in a a less turnkey, offering
  • 01:03:13
    from maybe an alternate supplier. Okay. So the
  • 01:03:18
    answer is you're gonna do it anyway? I
  • 01:03:20
    think we're gonna do some of it. Yes.
  • 01:03:22
    That gives us the same capabilities over time.
  • 01:03:26
    So, I mean, it's a significant reduction, you
  • 01:03:31
    know, 25,000,000 to 8,000,000. Yeah. I think in
  • 01:03:34
    the in the original filing, we can talk
  • 01:03:37
    to a specific, provider of that service. And
  • 01:03:41
    through the settlement negotiations, we looked at alternate
  • 01:03:44
    suppliers and providers, and we found that we
  • 01:03:45
    could do it at a at a cheaper
  • 01:03:47
    cost. That's good news. Okay. Alrighty. Because I
  • 01:03:51
    I do think that's an important part of
  • 01:03:53
    the wildfire mitigation, and I was just, again,
  • 01:03:56
    a little disheartened when I looked at it
  • 01:03:58
    initially not knowing this, if that was something
  • 01:04:00
    that you were potentially, you know, not gonna
  • 01:04:03
    keep. I guess, in terms of and I
  • 01:04:07
    know we talked a little bit about, metrics.
  • 01:04:11
    And, you know, one of the things that,
  • 01:04:13
    we've done in other with other resiliency plans
  • 01:04:17
    and we've kinda thought about is, you know,
  • 01:04:19
    a metric that would be common across, you
  • 01:04:21
    know, everyone who's participating across the state. Specifically,
  • 01:04:26
    you know, customer minutes interrupted as well as,
  • 01:04:30
    avoided system, restoration cost. So, I mean, what
  • 01:04:35
    what would your thoughts be on those in
  • 01:04:36
    terms of potentially adding those metrics? I think
  • 01:04:42
    our metrics are tailored to what our plan
  • 01:04:44
    does and the capabilities we've included in terms
  • 01:04:46
    of cost within our in our in our
  • 01:04:48
    plan. I think that's why we were hesitant
  • 01:04:50
    at the time to just, in a settlement
  • 01:04:52
    negotiation, change those metrics without changing the cost
  • 01:04:56
    or having to think through the the ability
  • 01:04:58
    to change the cost or capabilities within the
  • 01:05:00
    plan. I think our our metrics are tailored
  • 01:05:02
    to our plan, and those cost to provide
  • 01:05:04
    those metrics are built into the into the
  • 01:05:06
    plan and the cost of the plan. So
  • 01:05:09
    is that would that be a significant change
  • 01:05:11
    to add both of these from a cost
  • 01:05:12
    standpoint or from a Can you say the
  • 01:05:14
    two the two measures you were Customer minutes
  • 01:05:17
    interrupted. Right. And then avoided system restoration cost.
  • 01:05:23
    So I think the avoided system restoration cost
  • 01:05:26
    might be the trickier one of the two
  • 01:05:27
    of those without kind of some detailed system
  • 01:05:31
    modeling to understand what the potential impact or
  • 01:05:33
    not would be to your system, which I
  • 01:05:35
    don't I know we do not have built
  • 01:05:36
    into our plan, The the type of system
  • 01:05:39
    modeling for that. But no estimate in terms
  • 01:05:43
    of what potentially the financial impact might be?
  • 01:05:47
    The financial financial impact of building that model.
  • 01:05:50
    Right. We have not gone and done oop.
  • 01:05:52
    I'm sorry. We have not gone and done
  • 01:05:54
    the research for that. Again, just just an
  • 01:05:58
    idea that it would always be good to
  • 01:06:00
    have something that is common to systems, you
  • 01:06:02
    know, across Texas in terms of evaluating resilience.
  • 01:06:05
    Completely understand that. Just turning a minute to,
  • 01:06:13
    impact to residential rate payers, and understand that
  • 01:06:16
    you have a fairly large service area and,
  • 01:06:19
    you know, to be spread again across, you
  • 01:06:23
    know, relatively few customers in comparison to some
  • 01:06:26
    of the other, just some of the other
  • 01:06:29
    groups. But, so your application as proposed would
  • 01:06:35
    have a reg residential, ratepayer impact of $13.51.
  • 01:06:41
    So do you know what that impact would
  • 01:06:43
    be under the agreement? This is Stacy Whitehurst
  • 01:06:47
    with TNMP. Yeah. It's roughly, about $10, and,
  • 01:06:51
    that's assuming as is today. So we would
  • 01:06:54
    not the first year, we would not include
  • 01:06:57
    anything into a DCRF. And so our first
  • 01:07:00
    DCRF that would probably be hit would be
  • 01:07:02
    I believe it's gonna be roughly September of
  • 01:07:04
    2026 that would have a year's
  • 01:07:07
    worth. As you know that, the Commission has
  • 01:07:10
    a a requirement for regular rate cases, and
  • 01:07:14
    so we would expect that before that one,
  • 01:07:17
    we would be in for another rate case.
  • 01:07:19
    And so it's kinda hard to tell how
  • 01:07:22
    any rate, allocation would have occurred between what
  • 01:07:26
    we currently have in rates and what would
  • 01:07:28
    become the alpha rate case. Stacy, you said
  • 01:07:31
    what what amount? 10? Roughly about $10. Okay.
  • 01:07:35
    I was told $11.84, so I definitely wanna
  • 01:07:37
    get a check on that math on which
  • 01:07:40
    one will be in the I can follow-up
  • 01:07:44
    on that one. Okay. And then kind of
  • 01:07:45
    follow-up question to that. Again, associated with, the
  • 01:07:50
    impact to the residential rate payer is that,
  • 01:07:54
    you know, some of the state testimony mentioned
  • 01:07:56
    that the o and m and specifically the
  • 01:07:58
    vegetation o and m, is the main driver
  • 01:08:01
    for the residential rate, payer impact in this
  • 01:08:04
    proceeding. And I guess I'd like to understand
  • 01:08:07
    why is that. Basically, the allocation that came
  • 01:08:11
    out of our last rate case has the
  • 01:08:13
    allocation higher at the residential rate for those
  • 01:08:17
    cost. So it's, you know, if if you
  • 01:08:21
    look at it, you've got, you know, initially,
  • 01:08:24
    like, a $750,000,000 ask of which, you know,
  • 01:08:28
    a hundred million is vegetation management. But if
  • 01:08:31
    you look into what was actually the impact,
  • 01:08:34
    to the residential rate case to vegetation management,
  • 01:08:37
    it's a much higher percentage than that. Correct.
  • 01:08:42
    Because we would be allocating those costs associated
  • 01:08:46
    to the residential class based on the allocated
  • 01:08:49
    percentages in our DCRF. And so since our
  • 01:08:52
    DCRF allocation percentages haven't been updated since our
  • 01:08:55
    last rate case in 2018, we've seen significant
  • 01:08:58
    growth on our system. And so we would
  • 01:09:00
    expect, so based on our last rate case,
  • 01:09:03
    I believe our system peak was roughly 2,000,
  • 01:09:06
    megawatts. And so our I think our new
  • 01:09:08
    peak is around 2,800 megawatts. So we're seeing
  • 01:09:12
    a lot of growth, but the growth isn't
  • 01:09:14
    in the res the significant growth isn't residential
  • 01:09:17
    driving that. And so what we'd see is
  • 01:09:19
    a shift in allocation between those customer classes.
  • 01:09:24
    So more of an impact to the residential
  • 01:09:26
    customer? No. We would I I would expect
  • 01:09:28
    in our next rate case, we would see
  • 01:09:30
    allocation or, the allocation going away from some
  • 01:09:34
    of the residential to the other, commercial and
  • 01:09:37
    primary classes. So so potentially the the reason
  • 01:09:40
    for the difference between Commissioner Hjaltman's 11.84
  • 01:09:43
    eight four and your estimate of 10 is
  • 01:09:45
    the fact that more cost will be allocated
  • 01:09:47
    to other customer classes than residential. In the
  • 01:09:50
    next break case. In the next break case.
  • 01:09:52
    Okay. Which we wouldn't have seen in this.
  • 01:09:55
    Okay. Okay. I think those are all my
  • Item 2 - Chairman Gleeson's questions for TNMP - 56954
    01:09:59
    questions. So I think I just have a
  • 01:10:03
    couple. So the settlement where everyone settled on
  • 01:10:08
    a benefit cost ratio of .9. TIEC
  • 01:10:10
    argued for 1.2. Can you speak to why
  • 01:10:15
    you you're supportive of the point nine, why
  • 01:10:17
    that makes sense instead of a a higher
  • 01:10:19
    standard for the for the program benefit cost
  • 01:10:21
    ratio to be included? You are you asking
  • 01:10:24
    1.2 versus point nine? Yes. Yeah. So I
  • 01:10:27
    mean, I I think I think we and
  • 01:10:28
    I can have Jason come up and walk
  • 01:10:30
    through the actual calculation. But I think in
  • 01:10:33
    general, you know, I think we showed that,
  • 01:10:38
    sort of the the the qualitative benefits, could
  • 01:10:43
    be a significant adder and that's that wasn't
  • 01:10:46
    included in our number. And so if you
  • 01:10:48
    take it if you take account of those
  • 01:10:50
    qualitative benefits, that's why we landed on point
  • 01:10:53
    eight originally and then settled at .9.
  • 01:10:55
    Okay. Am I right that there were some
  • 01:11:00
    programs that had that have obviously of cost
  • 01:11:03
    that don't have associated performance metrics with them?
  • 01:11:08
    Are there programs that are not that that
  • 01:11:10
    do not have a metric? That don't have
  • 01:11:12
    a metric. And then are there and are
  • 01:11:15
    there programs that also didn't have a cost
  • 01:11:17
    benefit a benefit cost analysis done? There are
  • 01:11:20
    programs that did not have a cost benefit
  • 01:11:22
    analysis done. Why was that? I I I
  • 01:11:25
    think, sort of those low frequency but high
  • 01:11:30
    impact events, are I think more difficult in
  • 01:11:34
    that cost benefit analysis framework. Specifically, you know,
  • 01:11:38
    and Jason may you may wanna talk a
  • 01:11:40
    little bit about qualitative benefits and, you wanna
  • 01:11:49
    hop up? Yeah. So, thank you for the
  • 01:11:54
    question. Following up on the the point nine
  • 01:11:58
    threshold and, in the within the evaluation. So
  • 01:12:03
    as we look at that benefit cost analysis,
  • 01:12:06
    we we did our level best to make
  • 01:12:08
    sure the cost side of the house we
  • 01:12:10
    captured 100% of the cost side of the
  • 01:12:13
    house. When you do a benefit, benefits analysis,
  • 01:12:16
    it's not always easy to capture all the
  • 01:12:18
    potential benefits, that an investment might have. And
  • 01:12:21
    so the evaluation as we've laid out, you
  • 01:12:23
    know, did a, looked at the avoided customer
  • 01:12:27
    outages and the avoided ERCOT restoration costs, and
  • 01:12:30
    those are two quantified benefit streams. But what
  • 01:12:33
    you also have, especially with storm based investments
  • 01:12:39
    is there is a massive safety, component. Right?
  • 01:12:42
    Having crews out in the middle of the
  • 01:12:45
    night working on infrastructure, in in all the
  • 01:12:48
    various types of weather, there's a safety element
  • 01:12:50
    to that. Also, infrastructure falling, public safety element
  • 01:12:54
    as well. And quantification of that, can be
  • 01:12:57
    extremely challenging, to do. Additionally, how do you
  • 01:13:00
    quantify, you know, near misses, right, on that
  • 01:13:05
    front. And so because of that challenge on
  • 01:13:07
    that safety aspect, 1898's position is,
  • 01:13:12
    hey. Anything with a benefit cost ratio of
  • 01:13:14
    point nine or greater should be viewed as
  • 01:13:17
    this is a prudent investment to make, and
  • 01:13:19
    in the interest of the public. And so
  • 01:13:22
    as we look to develop those projects, say,
  • 01:13:24
    hey. We're gonna come to this circuit. What
  • 01:13:26
    sort of investment we ought to do? There's
  • 01:13:28
    significant efficiencies with tackling everything at once. Mhmm.
  • 01:13:31
    We wanna come to this circuit, do everything
  • 01:13:32
    that needs to be done so we don't
  • 01:13:34
    have to think about this for the next
  • 01:13:35
    decade plus. And so that's where that point
  • 01:13:38
    nine threshold came in. Anything on this circuit
  • 01:13:41
    that was a point nine or greater for
  • 01:13:43
    execution efficiencies, we're gonna do it all, at
  • 01:13:46
    once. And so that was the the methodology
  • 01:13:49
    in picking, that sort of threshold. But because
  • 01:13:53
    of the qualitative nature of some of the
  • 01:13:55
    benefits, you actually think that point eight is,
  • 01:13:59
    is reasonable, but it's settled on point nine.
  • 01:14:02
    We we settled yeah. So, a a point
  • 01:14:04
    nine would be for what we would call
  • 01:14:06
    maybe just general safety risk. You could argue
  • 01:14:09
    for a lower threshold if there is an
  • 01:14:12
    acute specific issue. For instance, maybe I've got
  • 01:14:16
    some infrastructure close to a school. Like, hey,
  • 01:14:20
    we're willing to drop our quantified threshold lower,
  • 01:14:24
    in those sorts of, situations. So we we
  • 01:14:27
    kinda balance between general safety and then specific
  • 01:14:30
    safety risk in potentially justifying a lower quantified
  • 01:14:34
    benefit cost ratio. Okay. Commissioners, any other questions?
  • 01:14:42
    Alright. Thank you for being here today. Like
  • 01:14:44
    like we typically do, we'll take take a
  • 01:14:46
    little more time with this, but but appreciate
  • 01:14:49
    the the effort in this. I know a
  • 01:14:50
    lot of work goes into these resiliency plans.
  • 01:14:53
    I'm definitely one of the most striking things
  • 01:14:55
    on that chart is seeing how unique your
  • 01:14:58
    in contiguous service territory is compared to, you
  • 01:15:01
    know, other TDUs that we that we regulate.
  • 01:15:04
    So, understand kind of the unique nature of
  • 01:15:07
    a resiliency plan for your service territory and,
  • 01:15:10
    and appreciate all the work. Thank you for
  • 01:15:12
    being here. Thank you very much. Alright. That'll
  • 01:15:19
    conclude the contested case portion of our agenda.
  • 01:15:24
    We'll go back now to Item No. 6.
  • 01:15:29
    That is project number 55999, reports of the
  • 01:15:33
    Electric Reliability Council of Texas. There was a
  • 01:15:35
    filing made by ERCOT on, the magnitude metric,
  • 01:15:39
    and then staff also had had a filing.
  • 01:15:42
    So ERCOT and staff would like to come
  • Item 6 - Matthew Arth - ERCOT - ERCOT's report on proposed magnitude methodology - 55999
    01:15:45
    up. Good afternoon, Matt. Good afternoon Chairman and
  • 01:15:52
    Commissioners. Matthew Arth for ERCOT. I'm here today
  • 01:15:55
    to speak about, ERCOT's report that we filed
  • 01:15:58
    on the proposed magnitude methodology. As you all
  • 01:16:02
    know, the reliability standard rule 25.508, which was
  • 01:16:06
    adopted in August and became effective shortly thereafter,
  • 01:16:10
    includes, three criteria for evaluating the reliability of
  • 01:16:16
    the ERCOT region, frequency, duration, and magnitude. And,
  • 01:16:20
    frequency and duration are established by the rule.
  • 01:16:23
    Magnitude, again, as you all know, was, not,
  • 01:16:28
    hardcoded into the rule, so to speak. ERCOT
  • 01:16:30
    is to determine that, value in consultation with
  • 01:16:34
    the transmission operators and with the commission staff,
  • 01:16:37
    out of recognition, I think, for the fact
  • 01:16:38
    that that load growth, that load is growing
  • 01:16:41
    in the ERCOT region, and that number will
  • 01:16:43
    will continue to evolve over time. So following
  • 01:16:46
    the, adoption of that rule, ERCOT immediately began
  • 01:16:50
    consulting with commission that that number might appropriately
  • 01:16:59
    be. Ultimately, ERCOT issued two sets of RFIs,
  • 01:17:04
    one in September and one in November, to
  • 01:17:06
    essentially understand, the amount of megawatts of load
  • 01:17:11
    that TOs could include in a load shed
  • 01:17:13
    rotation program, and of that amount, how much
  • 01:17:16
    could be shed at any one time to
  • 01:17:18
    facilitate rotation. So, with the the benefit of
  • 01:17:23
    the of the context and the background of
  • 01:17:25
    of those RFI responses, ERCOT is proposing a
  • 01:17:28
    methodology, for the magnitude of 20% of the
  • 01:17:33
    forecasted, winter load for the upcoming winter season,
  • 01:17:37
    using the seventy fifth percentile of that, winter
  • 01:17:41
    load forecast. So in the RFIs that we
  • 01:17:45
    issued for, the winter twenty four, twenty five,
  • 01:17:48
    which we're in currently, that, seventy fifth percentile
  • 01:17:52
    would, have been, 80,000 megawatts for a system
  • 01:17:56
    a system level. And so, applying the 20%
  • 01:18:02
    calculation methodology to that would result in a
  • 01:18:06
    16,000 megawatts magnitude. And so, we we really
  • 01:18:12
    appreciate all of the consultation efforts that the
  • 01:18:16
    transmission operators and Commission Staff, assisted us with
  • 01:18:20
    in developing this methodology. If the, I can
  • 01:18:25
    go into further kind of some of our
  • 01:18:27
    thinking on on how that was developed. But
  • 01:18:29
    if the commission agrees with that methodology, then
  • 01:18:33
    we would propose to move forward with, utilizing
  • 01:18:36
    that, for the annual December 1 filings that
  • 01:18:40
    ERCOT would be making, going forward. So implicit
  • 01:18:45
    in that number, there are a couple of
  • 01:18:46
    different ways that you could think about, how
  • 01:18:49
    that 20% was was reached. But, based on
  • 01:18:53
    the, RFI responses, which are attached for transparency
  • 01:18:57
    purposes, that would include, all of the, or
  • 01:19:03
    rather that would implicitly exclude from, from load
  • 01:19:07
    shed rotation the nonresidential critical categories of load,
  • 01:19:11
    which are, critical public safety, critical industrial, and
  • 01:19:15
    critical natural gas facilities, as well as maintaining
  • 01:19:19
    the 25%, under frequency load shed requirement, which
  • 01:19:23
    is a an an ERCOT and a NERC
  • 01:19:25
    requirement. And so, we felt that it was
  • 01:19:28
    appropriate to exclude those categories or rather to
  • 01:19:32
    implicitly exclude them and and come into the
  • 01:19:34
    calculation because, all of those categories could have,
  • 01:19:39
    an impact on the public at large, either
  • 01:19:42
    from a reliability perspective or from a, public
  • 01:19:45
    health and safety perspective. This would, also implicitly
  • 01:19:51
    include in the amount that would be, shedtable
  • 01:19:55
    the, transmission connected customers that are, not otherwise
  • 01:19:59
    registered as critical. And, while we understand that,
  • 01:20:04
    those customers are less likely for technical reasons,
  • 01:20:07
    to be shed, we did feel that if
  • 01:20:10
    they had not otherwise registered as critical, then
  • 01:20:12
    there was no, larger impact on the system
  • 01:20:15
    or to the or to the public health
  • 01:20:17
    of that area. And so I think it's
  • 01:20:18
    important, with, with that explanation to to emphasize
  • 01:20:23
    that, it is ERCOT understanding that the rule
  • 01:20:25
    is not a, a load shed compliance standard
  • 01:20:29
    for, transmission operators to, to achieve. And and
  • 01:20:33
    it doesn't if if this methodology is adopted,
  • 01:20:37
    it would not, seek to direct transmission operators
  • 01:20:40
    as to how to structure their load shed
  • 01:20:42
    programs, which which load to include or exclude.
  • 01:20:46
    It's just, helpful, for thinking about the evaluation
  • 01:20:52
    of the general reliability of the ERCOT region
  • 01:20:55
    as a whole, to think about being able
  • 01:21:00
    to, rotate load shed while, implicitly maintaining these
  • 01:21:05
    categories that would have, public reliability and health,
  • 01:21:09
    impacts. So happy to answer any questions and
  • 01:21:12
    go into that further, but, that's ERCOT recommendation
  • 01:21:15
    in this report. Werner, do you have any
  • Item 6 - Werner Roth - Commission Staff - Staff's recommendation on ERCOT's report for proposed magnitude methodology - 55999
    01:21:17
    comments? Yeah. Werner Roth, Commission Staff. Oh, Matt
  • 01:21:20
    actually did a really good job of summarizing
  • 01:21:23
    that just now, so I don't really have
  • 01:21:24
    too much of that. I just at the
  • 01:21:26
    end of the, memo staff did recommend that,
  • 01:21:30
    as required in the rule that we do
  • 01:21:31
    continue the consultation with ERCOT and the transmission
  • 01:21:34
    operators on this. While we do have a
  • 01:21:35
    methodology, we wanna make sure that we're continuing
  • 01:21:37
    conversations in case the system changes to where
  • 01:21:40
    this may not be an appropriate methodology to
  • 01:21:42
    use going forward. But by setting this based
  • 01:21:44
    off the low forecast that's included in the
  • 01:21:45
    CDR, this at least gives a little bit
  • 01:21:47
    more certainty about what to expect for this
  • 01:21:49
    value for the upcoming year. That makes sense
  • 01:21:54
    to me. Commissioners, questions for Matt or Werner?
  • Item 6 - Commissioner Jackson's questions to ERCOT - 55999
    01:21:58
    Well, just to underscore what you said that
  • 01:21:59
    the the idea here is that this is
  • 01:22:01
    for planning purposes and is no way intended
  • 01:22:04
    to be for operational purposes. And Yes, Commissioner.
  • 01:22:09
    And then, you know, the point that I
  • 01:22:11
    guess you made is that, you know, we
  • 01:22:13
    need to revisit this in in consultation between
  • 01:22:16
    staff and ERCOT. And so you would anticipate
  • 01:22:19
    that happening by December 1 every year? Yes.
  • 01:22:24
    That would be the plan where we would
  • 01:22:25
    have a discussion prior to December 1, discuss
  • 01:22:28
    whether the method like, if there's been any
  • 01:22:29
    significant change that would require revisiting the methodology,
  • 01:22:32
    but if not, just move forward based off
  • 01:22:33
    the, 20% of the low forecast in the
  • 01:22:36
    CDR. Okay. Thank you. And that is or
  • 01:22:39
    ERCOT intent to, probably well in advance, I'd
  • 01:22:42
    imagine, at least a month or two of
  • 01:22:43
    the of the filing to, consult with the
  • 01:22:46
    Commission Staff and the transmission operators. And we
  • 01:22:49
    can evaluate at that time, you know, whether
  • 01:22:51
    there have been advancements in, segmentation or rotation
  • 01:22:55
    method, technologies that might merit, different approaches going
  • 01:23:00
    forward. But, at least with this kind of,
  • 01:23:03
    consistent, thinking about a a a magnitude methodology,
  • 01:23:07
    then that does give some some relative amount
  • 01:23:10
    of certainty for folks to to plan on
  • 01:23:12
    and think about going into it. Would reducing
  • 01:23:18
    the the magnitude amount, would this be the
  • 01:23:22
    limiting factors we're looking at reliability? So my
  • 01:23:26
    understanding right now that with the number dropping
  • 01:23:28
    the 16,000, this the magnitude would not be
  • 01:23:31
    the binding component. It would still be the
  • 01:23:33
    frequency, the one and ten component of the
  • 01:23:35
    of reliability standard. Okay. Mhmm. Alright. Well, I
  • 01:23:38
    think this is reasonable I'm comfortable with this.
  • 01:23:41
    I am as well. Okay. Alright. Thank you,
  • 01:23:45
    Matt, for being here. Thank you, Werner. Thank
  • 01:23:46
    you. Alright. I think we only have one
  • Item 9 - Project No. 53911 – Aggregate Distributed Energy Resource (ADER
    01:23:49
    more item on the agenda. ERCOT Pilot Project) So, we'll move
  • 01:23:53
    to Item No. 9. That is Project No.
  • 01:23:55
    53911, aggregate distributed energy resource, ADER ERCOT pilot
  • 01:24:01
    project. Good afternoon, Ramya. It's afternoon. Just barely.
  • 01:24:09
    Thank you for that. I actually did not
  • Item 9 - Ramya Ramaswamy - Commission Staff - Moving ADER Pilot Project to ERCOT - 53911
    01:24:11
    know that. Ramya Ramaswamy, commission staff. Good afternoon,
  • 01:24:16
    Commissioners. Good afternoon Chairman. The aggregate distributed energy
  • 01:24:20
    resource pilot project was a first of its
  • 01:24:23
    kind where discrete individual households and commercial customers
  • 01:24:27
    were able to participate in ERCOT and real
  • 01:24:30
    time ERCOT real time and AS market. Many
  • 01:24:34
    were skeptical at the start, but committed pilot
  • 01:24:37
    stakeholders and ERCOT folks pushed through to seek,
  • 01:24:41
    innovative solutions at every step of the way.
  • 01:24:43
    Last session, we also cleared the way for,
  • 01:24:46
    regulatory and policy issues, making the pilot more
  • 01:24:49
    successful. Today, I'm here to recommend that it
  • 01:24:52
    is time to move the pilot to ERCOT,
  • 01:24:54
    to help continue its growth further. The pilot
  • 01:24:57
    can only benefit from larger from the larger
  • 01:25:00
    stakeholder group at ERCOT, and that will facilitate
  • 01:25:03
    its coordinated growth along with other projects within
  • 01:25:07
    the ERCOT market system. Staff will continue to
  • 01:25:11
    market this pro sorry. Staff will con continue
  • 01:25:14
    to monitor this project in a manner similar
  • 01:25:17
    to how other projects at ERCOT function. Further,
  • 01:25:21
    I also recommend that ERCOT report directly to
  • 01:25:24
    the commission all the progress, in this project
  • 01:25:27
    every six months. Happy to answer any questions.
  • 01:25:30
    Thank you, Ramya. You know, I'm I'm comfortable
  • 01:25:34
    with this moving to ERCOT now that we're
  • 01:25:36
    looking at at kind of more technical aspects.
  • 01:25:39
    I spoke to leadership of the task force,
  • 01:25:42
    and they believe that this is the right
  • 01:25:44
    way to go as well. So, I I
  • 01:25:47
    think this is how we should proceed. And
  • 01:25:49
    and I there's no one at the agency
  • 01:25:51
    I trust more than Ramya to make sure
  • 01:25:52
    that we are informed and the public stays
  • 01:25:54
    informed about what's going on. I'm in agreement,
  • 01:25:58
    especially with the trusting of Ramya. Yes. I'm
  • 01:26:02
    glad you concur, Commissioner. Yes. I'm as well.
  • 01:26:05
    And, you know, I would characterize it as,
  • 01:26:08
    you know, there were objectives that we needed
  • 01:26:10
    early on to be met, you know, at
  • 01:26:12
    the Commission to get this started, and I
  • 01:26:14
    feel like those were. And so to implement
  • 01:26:16
    it, the next the, you know, the logical
  • 01:26:19
    next step is to send it to ERCOT.
  • 01:26:21
    And so with your watchful eye, we'll be
  • 01:26:24
    watching the progress and, you know, hopefully, a
  • 01:26:28
    successful implementation. Thank you, Ramya. Thank you. Shelah,
  • 01:26:36
    I think that concludes everything on our agenda
  • Item 28 - Chairman Gleeson adjourns meeting
    01:26:38
    today. Alright. Commissioners, anything else? No? Alright With
  • 01:26:42
    there being no further business before us, this
  • 01:26:44
    meeting, the Public Utility Commission of Texas is
  • 01:26:45
    hereby adjourned.
Chairman Gleeson calls meeting to order - 56954
Starts at 00:00:07
28 - Chairman Gleeson pauses Open Meeting, to hold Closed Session
Starts at 00:01:41
28 - Chairman Gleeson concludes Closed Session, Public Meeting resumed
Starts at 00:02:21
Commission Counsel Shelah Cisneros lays out Consent Agenda
Starts at 00:02:40
Chairman Gleeson asks for motion to approve items on Consent Agenda
Starts at 00:03:03
6 - Project No. 55999 – Reports of the Electric Reliability Council of Texas
Starts at 00:03:30
6 - Pablo Vegas – ERCOT President & CEO - CDR Cycle - 55999
Starts at 00:03:45
6 - Commissioner Hjaltman's questions for Pablo Vegas - 55999
Starts at 00:19:48
6 - Commissioner Jackson's questions for Pablo Vegas - 55999
Starts at 00:23:36
6 - Chairman Gleeson's questions for Pablo Vegas - 55999
Starts at 00:28:14
2 - Docket No. 56954; SOAH Docket No. 473-24-25125 – Application of Texas-New Mexico Power Company for Approval of a System Resiliency Plan
Starts at 00:38:42
2 - Stacy Whitehurst – VP of Regulatory Affairs - overview of System Resiliency Plan - 56954
Starts at 00:39:40
2 - Chris Gerety – VP of Technical Services & System Reliability - Distribution System Resiliency Measure - 56954
Starts at 00:42:56
2 - Keith Nix – VP of Operations - Vegetation Management - 56954
Starts at 00:44:56
2 - Commissioner Hjaltman's questions for TNMP - 56954
Starts at 00:51:54
2 - Jason De Stigter - 1898 - Benefit cost analysis - 56954
Starts at 00:55:21
2 - Commissioner Hjaltman's questions on vegetation for TNMP - 56954
Starts at 00:56:11
2 - Commissioner Jackson's questions for TNMP - 56954
Starts at 00:59:04
2 - Chairman Gleeson's questions for TNMP - 56954
Starts at 01:09:59
6 - Matthew Arth - ERCOT - ERCOT's report on proposed magnitude methodology - 55999
Starts at 01:15:45
6 - Werner Roth - Commission Staff - Staff's recommendation on ERCOT's report for proposed magnitude methodology - 55999
Starts at 01:21:17
6 - Commissioner Jackson's questions to ERCOT - 55999
Starts at 01:21:58
9 - Project No. 53911 – Aggregate Distributed Energy Resource (ADER
Starts at 01:23:49
9 - Ramya Ramaswamy - Commission Staff - Moving ADER Pilot Project to ERCOT - 53911
Starts at 01:24:11
28 - Chairman Gleeson adjourns meeting
Starts at 01:26:38

Commissioner Memos

ControlItemFiling DatePartyDescriptionAction
56954161February 11, 2025CHAIRMAN THOMAS GLEESONCHAIRMAN THOMAS GLEESON MEMORANDUM