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  • 00:00:18
    Good afternoon, members of ERCOT Board of Directors
  • 00:00:20
    and guests. I'm Bill Flores, ERCOT Board Chair.
  • 00:00:23
    Welcome to the April 2025 Board of Directors
  • 00:00:26
    meetings. I've confirmed that a quorum is present
    EditCreate clip
  • Item 1 - Call General Session to Order
    00:00:29
    in person and hereby call this meeting the
  • 00:00:31
    order of the ERCOT Board of Directors. This
  • 00:00:33
    meeting is being webcast live to the public
  • 00:00:36
    on ERCOT's website. At this time, I'd like
  • 00:00:39
    to ask PUC Chair, Thomas Gleason, if he
  • 00:00:42
    would like to call an open meeting of
  • 00:00:43
    the Public Utility Commission of Texas to order.
  • 00:00:46
    Yes, sir. Thank you, Mr. Chairman. This meeting
  • 00:00:48
    of the Public Utility Commission of Texas will
  • 00:00:49
    come to order to consider matters that have
  • 00:00:51
    been duly posted with the Secretary of State
  • 00:00:53
    for 04/07/2025. Thank you, Chair Gleason. The antitrust
  • 00:00:58
    admonition and security map are each included with
  • 00:01:01
    the posted meeting materials. Before we proceed, I'd
  • 00:01:05
    like to recognize former Board Member Carlos Aguilar,
  • 00:01:08
    who recently resigned from the Board of Directors
  • 00:01:10
    to manage other existing opportunities. Carlos was one
  • 00:01:13
    of the first two Board members back in
  • 00:01:15
    October of twenty twenty one under the new
  • 00:01:17
    SB2 framework with just him and former Board
  • 00:01:22
    Chair Paul Foster. His expertise and guidance have
  • 00:01:25
    been instrumental in this Board's decision making. The
  • 00:01:29
    Board appreciates his service to ERCOT and to
  • 00:01:31
    the Texans and to Texans and we wish
  • 00:01:33
    him the best. I further notified the Board
  • 00:01:36
    Selection Committee last week of this vacancy and
  • 00:01:40
    they will begin the selection process to replace
  • 00:01:42
    Carlos in the coming weeks. Also for stakeholders
  • 00:01:46
    and public general awareness, I'd like to point
  • 00:01:48
    out that we will likely have two day
  • 00:01:50
    Board meetings going forward with the governance change
  • 00:01:52
    of moving the Reliability and Markets committee matters
  • 00:01:55
    to the full board. To manage our business
  • 00:01:59
    more efficiently, there may be times when I
  • 00:02:01
    move a discussion item from one day to
  • 00:02:03
    the next, but I do not anticipate moving
  • 00:02:05
    voting items when they're reflected on the agenda
  • 00:02:08
    for a specific day. This is to ensure
  • 00:02:10
    that anyone who wants to speak on a
  • 00:02:14
    voting item has certainty as to which day
  • 00:02:17
    that will occur. The first order of business
  • Item 2 - Notice of Public Comment, if Any
    00:02:20
    on today's agenda is item two notice of
  • 00:02:24
    public comment if any. Today's meeting agenda was
  • 00:02:27
    posted publicly on 03/31/2025 and provided instruction for
  • 00:02:33
    the public for commenting in person. Today is
  • 00:02:35
    where no one has expressed interest in commenting.
  • 00:02:38
    Is that still correct, Chad? That is correct,
  • 00:02:40
    Chair. Okay. Thank you, Chad. Next is agenda
  • Item 3 - Dissolve Establishment and Appointment of Reliability and Markets (R&M
    00:02:43
    Committee) item three, a dissolve establishment employment of the
  • 00:02:46
    reliability and markets committee. During the special meeting
  • 00:02:50
    of the board on February 2025, I moved
  • 00:02:53
    the jurisdiction R and M committee back to
  • 00:02:54
    the full board to allow all board members
  • 00:02:57
    to board direct to allow them to have
  • 00:02:59
    more direct participation in the policy matters associated
  • 00:03:02
    with the core functions of operations, planning and
  • 00:03:06
    markets and the mission of ERCOT. As such,
  • 00:03:08
    I will entertain a motion to dissolve the
  • 00:03:10
    establishment and appointment of the R and M
  • 00:03:12
    Committee. Thank you, John. Second. Second. Thank you,
  • 00:03:17
    Peggy. Any discussion? All in favor? Any opposed?
  • 00:03:24
    Any abstentions? Okay, the motion is approved unanimously.
  • Item 4 - February 3, 2025 Reliability and Markets Committee General Session Meeting Minutes
    00:03:28
    The next is agenda item for the 02/03/2025
  • 00:03:32
    reliability at markets committee general session meeting minutes.
  • 00:03:36
    There's a draft in the meeting materials. Does
  • 00:03:38
    anyone have any corrections? Okay, hearing no objections
  • 00:03:42
    and consistent since that committee no longer exists,
  • 00:03:45
    consistent with Robert's rules of order on approval
  • 00:03:47
    of minutes, The 02/03/2025 Reliability and Markets Committee
  • 00:03:51
    general session meeting minutes are deemed approved. Next
  • Item 5 - Commercial Markets
    00:03:55
    is agenda item five, commercial markets and our
  • 00:03:59
    four sub items. The first sub item is
  • 00:04:01
    item 5.1 recommendation regarding real time market price
  • 00:04:05
    correction, incorrect resource telemetry MW values when QSC
  • 00:04:10
    sends suspect quality telemetry. Gordon Drake is going
  • 00:04:14
    to be making this presentation. Gordon? Thank you,
  • Item 5.1 - Recommendation regarding Real-Time Market Price Correction – Incorrect Resource Telemetry MW Values When QSE Sends Suspect Quality Telemetry
    00:04:28
    Mr. Chairman and pleasure to be here making
  • 00:04:31
    this recommendation to the Board today. What I
  • 00:04:35
    hope to do is to provide some background
  • 00:04:38
    and context to the root cause of the
  • 00:04:42
    issue that led to the need to consider
  • 00:04:44
    a potential price correction today, speak to the
  • 00:04:46
    specific event and sequence of events and actions
  • 00:04:49
    taken by ERCOT, and then speak to the
  • 00:04:52
    impact to counterparties as detailed in the presentation
  • 00:04:57
    against the established board criteria and protocols and
  • 00:05:01
    then also speak to a refinement enhancement to
  • 00:05:06
    the methodology that we employ when performing these
  • 00:05:09
    price corrections to ensure we are limiting any
  • 00:05:17
    potential unwarranted payments that may have otherwise arisen
  • 00:05:20
    through previous methodology. And we are requesting the
  • 00:05:26
    of the board to approve the potential price
  • 00:05:29
    correction today for operating days between August 12
  • 00:05:32
    and September 11. So at the the the
  • 00:05:36
    root cause of what led to the the
  • 00:05:39
    the potential price correction event has to do
  • 00:05:42
    with how the our energy management system receives
  • 00:05:46
    and and processes telemetry from resources in the
  • 00:05:51
    field, which is the way in which we
  • 00:05:52
    have an understanding of the real time conditions
  • 00:05:55
    of of what's actually happening on the power
  • 00:05:57
    system as a result of what is sent
  • 00:06:00
    to us via telemetry from qualified scheduling entities
  • 00:06:03
    about their resources. As you can imagine, there
  • 00:06:06
    are quite a significant number of these telemetry
  • 00:06:09
    points out on the grid monitoring real time
  • 00:06:11
    conditions. And from time to time for a
  • 00:06:13
    variety of reasons, those data quantities can become
  • 00:06:17
    stale or incorrect. And when that happens, we
  • 00:06:20
    rely on qualified scheduling entities to notify us
  • 00:06:23
    by flagging that telemetry as suspect. When we
  • 00:06:27
    receive that flag of suspect telemetry, our energy
  • 00:06:31
    management system defaults to the last known good
  • 00:06:35
    quantity that had been telemetered. The understanding being
  • 00:06:38
    that the best expectation of what's happening now
  • 00:06:40
    is what was just happening. And so it
  • 00:06:43
    reverts to that last known good telemetry megawatt
  • 00:06:45
    megawatt value. In November of twenty twenty three,
  • 00:06:49
    during an update to our energy management system,
  • 00:06:53
    there was a defect that was introduced that
  • 00:06:57
    inadvertently introduced a fixed value that will be
  • 00:07:00
    substituted for megawatt quantity instead of the last
  • 00:07:04
    known good telemetry quantity from that resource. And
  • 00:07:09
    that data point and that telemetry megawatt value
  • 00:07:14
    that in this case was being substituted with
  • 00:07:18
    a stale value is important because our market
  • 00:07:20
    management system uses that in the determination of
  • 00:07:23
    dispatch schedules, base points and prices. When this
  • 00:07:29
    static megawatt value is being used, so we
  • 00:07:32
    have a suspect telemetry flag and the energy
  • 00:07:36
    management system reverted to the stale value. This
  • 00:07:40
    can have an impact on prices and dispatch
  • 00:07:44
    if three conditions are met. The first being
  • 00:07:47
    if we have that suspect data quality, the
  • 00:07:51
    current output, the megawatt output of that facility
  • 00:07:54
    is significantly different than what is happening in
  • 00:07:57
    reality. So the current output and the stale
  • 00:08:00
    value are quite significantly different. And if that
  • 00:08:04
    resource has a significant shift factor associated with
  • 00:08:08
    a binding or violated constraint. So if those
  • 00:08:10
    all those three conditions are true, then this
  • 00:08:14
    software defect can and that value being passed
  • 00:08:17
    from the energy management system to the MMS
  • 00:08:20
    can have a significant impact on pricing. On
  • 00:08:25
    September fifth of twenty twenty four, during the
  • 00:08:28
    morning ramping period, there were multiple resources represented
  • 00:08:31
    by a single qualified scheduling, sorry, qualified scheduling
  • 00:08:35
    entity that had telemetered, suspect quality, and status
  • 00:08:39
    on their measurements for their megawatt telemetry. And
  • 00:08:43
    as a result, EMS, our energy management system
  • 00:08:47
    picked up that stale megawatt value and passed
  • 00:08:50
    it to our market management system. When Sked
  • 00:08:54
    ran to determine base points at 08:35 in
  • 00:08:58
    the morning, because we saw the combination of
  • 00:09:02
    those three conditions met, the optimization using those
  • 00:09:07
    stale megawatt quantities led to prices spiking from
  • 00:09:11
    just below $21 a megawatt hour to nearly
  • 00:09:15
    $200 a megawatt hour. In the next Sked
  • 00:09:19
    interval, after the suspect telemetry had been corrected
  • 00:09:22
    and our EMS and MMS reverted to using
  • 00:09:26
    actual data from the field, the price dropped
  • 00:09:28
    to nearly $28 a megawatt hour. This unusual
  • 00:09:34
    spike in system Lambda, it's not something we
  • 00:09:36
    typically see at that time of year in
  • 00:09:38
    those morning ramps is what attracted our attention
  • 00:09:41
    to investigate further and seek out the root
  • 00:09:43
    cause of the price spike. And that led
  • 00:09:47
    to the discovery of the software defect that
  • 00:09:50
    was noted on the previous slide. And on
  • 00:09:52
    September eleven of twenty twenty four, we implemented
  • 00:09:56
    a fix to correct the defect and return
  • 00:09:59
    it to the expected behavior of reverting to
  • 00:10:02
    the last known good telemetry value. Also on
  • 00:10:05
    September 11, we issued a market notice notifying
  • 00:10:08
    the market of the issue and our intent
  • 00:10:11
    upon completion of our impact analysis to seek
  • 00:10:14
    Board of Directors approval to correct prices as
  • 00:10:17
    specified in the protocol sections noted there. And
  • 00:10:21
    also to preserve the eligibility of up to
  • 00:10:24
    thirty days of potential price correction for our
  • 00:10:28
    ability to review, which is what the protocols
  • 00:10:30
    specify in terms of the duration that we
  • 00:10:32
    can go back in time to perform this
  • 00:10:34
    price correction. So though the issue first appeared
  • 00:10:38
    in November of twenty twenty three, we are
  • 00:10:41
    only able to request correction for a thirty
  • 00:10:44
    day window. And that is the reason why
  • 00:10:47
    the price correction we brought for you today
  • 00:10:49
    spans from August 12 to September eleven of
  • 00:10:52
    twenty twenty four. In terms of the impact
  • 00:10:58
    this had on the real time market, we
  • 00:11:00
    evaluate the impact of these events against two
  • 00:11:04
    criteria specified in the protocols, which we deem
  • 00:11:08
    our significance criteria. So before seeking board approval,
  • 00:11:12
    the impact to any single counterparty must be
  • 00:11:15
    either an impact of 2% and also $20,000
  • 00:11:21
    absolute impact or a 20% impact to their
  • 00:11:25
    settlements and also greater than $2,000 So those
  • 00:11:29
    are the two significance criteria that we test
  • 00:11:31
    the impact against. And using those criteria, it
  • 00:11:34
    was determined that 27 of the days between
  • 00:11:37
    August 12 and September 11 met the significance
  • 00:11:40
    criteria. In terms of a dollar impact, the
  • 00:11:48
    maximum estimated absolute value impact to counterparties shows
  • 00:11:52
    for those twenty seven impacted operating days, the
  • 00:11:57
    amount that in dollars as well as the
  • 00:12:00
    evaluation of the criteria one and criteria two,
  • 00:12:07
    the dollars and percentages that met those significance
  • 00:12:10
    criteria that were specified in the previous slide.
  • 00:12:17
    In terms of the total impact to the
  • 00:12:19
    market over those twenty seven operating days, the
  • 00:12:22
    total impact to statement charges due to ERCOT
  • 00:12:24
    was $3,324,370 And so that is in sum
  • 00:12:39
    when you look at the tables there for
  • 00:12:41
    the 27 option data they sum to $3,000,000
  • 00:12:45
    to be collected from ratepayers. I mentioned that
  • 00:12:54
    there was a change in our refinement and
  • 00:12:57
    enhancement to our methodology. We were looking over
  • 00:13:02
    a significant data set, a significant period of
  • 00:13:05
    time. And that explains why it is April
  • 00:13:09
    and we're talking about a price correction event
  • 00:13:12
    going back to August and September of last
  • 00:13:14
    year. But throughout the course of our analysis,
  • 00:13:16
    it was discovered that our existing methodology for
  • 00:13:18
    calculating the impact to counterparties would have resulted
  • 00:13:22
    in unwarranted payments to certain resources. And where
  • 00:13:26
    this arises from is from a recalculation of
  • 00:13:31
    the prices, but in particular make whole payments
  • 00:13:34
    for resources that were dispatched to be online.
  • 00:13:38
    But with the determination of new prices, they
  • 00:13:43
    otherwise would not have been economic to run
  • 00:13:45
    had the introduction of the stale megawatts not
  • 00:13:50
    been introduced. And so upon discovery of those
  • 00:13:56
    unwarranted payments, we undertook some analysis again, sort
  • 00:14:00
    of we undertook the analysis again considering settlement
  • 00:14:03
    charges and changes only for those for whom
  • 00:14:06
    was appropriate to be held whole under what
  • 00:14:08
    we call our emergency settlement process. So as
  • 00:14:11
    we correct the prices, that applies resource, but
  • 00:14:16
    this subset of resources who are eligible for
  • 00:14:18
    those make whole payments is where the refinement
  • 00:14:21
    to our methodology led to a reduction in
  • 00:14:25
    the total cost to consumers. Going forward, ERCOT
  • 00:14:30
    is going to employ this refined and enhanced
  • 00:14:33
    methodology. We will also be going to the
  • 00:14:36
    wholesale market working group and providing some education
  • 00:14:40
    to market participants and stakeholders about the price
  • 00:14:42
    correction process as a whole as well as
  • 00:14:45
    the specifics of the methodology enhancements so that
  • 00:14:49
    it's well understood. Cord, before you leave that
  • 00:14:53
    page. Yes. So if a resource was dispatched
  • 00:15:02
    and it wouldn't have otherwise been dispatched, is
  • 00:15:04
    that resource going to get paid? That? Yes.
  • 00:15:06
    Okay. So that's not one of the unwarranted
  • 00:15:08
    payments? No, the unwarranted payments be an example
  • 00:15:12
    where a resource was indicating that they were
  • 00:15:17
    essentially a price taker. So they were insensitive
  • 00:15:20
    to what the price would have been in
  • 00:15:23
    the market. They were going to inject or
  • 00:15:25
    consume at a fixed megawatt quantity. And those
  • 00:15:28
    are the ones that we would say, as
  • 00:15:31
    the price changes, they don't need to be
  • 00:15:32
    held whole because they were going to be
  • 00:15:35
    operating regardless. Okay. Does the enhanced methodology require
  • 00:15:39
    any sort of a protocol change? It's covered
  • 00:15:41
    under our existing protocol. It is. Okay. Thank
  • 00:15:44
    you. And with that, we can proceed with
  • 00:15:51
    the with our recommendation to correct prices for
  • 00:15:56
    August 12 to 09/11/2024 as a result of
  • 00:15:59
    this issue. Okay. Thank you, Gordon. Does anyone
  • 00:16:02
    have any questions for Gordon or wish to
  • 00:16:05
    discuss this matter? Okay. If not, I'll entertain
  • 00:16:09
    a motion to approve the recommendation regarding real
  • 00:16:12
    time market price correction, incorrect resources telemetry MW
  • 00:16:17
    values when QSC sends suspect quality telemetry as
  • 00:16:21
    presented. Is there a motion? Okay. Thank you,
  • 00:16:27
    John. Second? Thank you, Linda. All in favor?
  • 00:16:32
    Aye. Any opposed? Any abstentions? Okay. Price correction
  • Item 5.2 - Independent Market Monitor (IMM
    00:16:38
    Report) is approved. Next is agenda item 5.2, Independent
  • 00:16:42
    Market Monitor. IMM Director, Jeff McDonald is presenting.
  • 00:16:45
    Jeff? It's good to see you again. Thank
  • 00:17:10
    you. Good to see you Thank you for
  • 00:17:12
    the time. Good afternoon, directors. I so I
  • 00:17:15
    only submitted two slides. I had a nice
  • 00:17:18
    conversation with Director England a few weeks ago.
  • 00:17:21
    And my question to her was, what would
  • 00:17:25
    the Board like to see from me rather
  • 00:17:28
    than come up? You get a fantastic palette
  • 00:17:31
    of market performance metrics. If there are interesting
  • 00:17:35
    things in market outcomes, I'm happy to bring
  • 00:17:38
    that forward to you during meetings. But I
  • 00:17:40
    didn't want to take up your time with
  • 00:17:44
    eight slides of there wasn't really anything interesting
  • 00:17:47
    in the last two months. So Director England
  • 00:17:51
    mentioned that there might be some interest in
  • 00:17:54
    getting the IMM's perspective on market design in
  • 00:17:59
    general, some of the challenges that ERCOT and
  • 00:18:02
    Texas are facing right now, and provide a
  • 00:18:05
    little bit more of a forward looking perspective
  • 00:18:07
    rather than a retrospective aspect of a conversation.
  • 00:18:12
    So with that in mind, in my one
  • 00:18:15
    year here, I've had quite a few conversations
  • 00:18:18
    with different market participants about different I won't
  • 00:18:24
    call them smaller, but specific market design aspects.
  • 00:18:29
    How do we achieve resource adequacy, of course,
  • 00:18:32
    has been a topic for everybody, probably predating
  • 00:18:35
    my year here. And as you know, ERCOT's
  • 00:18:40
    got a load forecast that shows a tremendous
  • 00:18:43
    amount of load growth over the next five
  • 00:18:45
    years and the questions of how do we
  • 00:18:48
    meet that as an RTO successfully and how
  • 00:18:52
    do can we do that through the market
  • 00:18:54
    or are there other means. And so I
  • 00:18:56
    just thought I would provide my perspective. Again,
  • 00:18:59
    I only put together two slides. I know
  • 00:19:01
    there's only probably ten or fifteen minutes slotted
  • 00:19:04
    for this discussion, so I didn't want to
  • 00:19:06
    do a full brain dump on all the
  • 00:19:08
    options. Hopefully, it will be an interesting discussion.
  • 00:19:13
    And part of, hopefully, what you'll take away
  • 00:19:17
    from this is from a markets and an
  • 00:19:21
    economist perspective, we like to see very deliberate
  • 00:19:26
    actions taken. And so if there's a need
  • 00:19:29
    that that need is expressly written out and
  • 00:19:33
    understood, a product is designed to meet that
  • 00:19:37
    need and that the payment structure or price
  • 00:19:40
    formation is calibrated in such a way that
  • 00:19:43
    as the market executes, you would expect to
  • 00:19:46
    meet your need through that market when the
  • 00:19:48
    need arose. So and a lot of this
  • 00:19:52
    isn't news, it's a little bit of fundamental
  • 00:19:55
    background, but I thought it was important to
  • 00:19:58
    understanding my perspective and how myself and my
  • 00:20:01
    team approach some of the market design issues
  • 00:20:04
    that come up in the stakeholder process. So
  • 00:20:13
    at a very high level, ERCOT's identified both
  • 00:20:16
    short term and immediate term concerns regarding resource
  • 00:20:21
    adequacy. In the short term, there are some
  • 00:20:24
    more extreme conditions that can produce lower reliability.
  • 00:20:30
    And in the medium term, of course, there's
  • 00:20:33
    the projected load growth out through twenty twenty
  • 00:20:36
    nine, two thousand thirty that has a considerable
  • 00:20:39
    amount of load coming into the ERCOT control
  • 00:20:43
    area projected or anticipated to come in. And
  • 00:20:48
    so those are two different problems in my
  • 00:20:51
    view. And one of the punch lines, I
  • 00:20:54
    think, from this discussion other than a very
  • 00:20:58
    deliberate product design for markets to meet specific
  • 00:21:02
    needs is in any of these markets, whether
  • 00:21:06
    it's a spot market like ERCOT or markets
  • 00:21:09
    that have a very some variant of a
  • 00:21:12
    capacity construct, whether it be prompt or a
  • 00:21:16
    forward capacity construct, The market that we observe
  • 00:21:22
    where prices form won't signal for new investment
  • 00:21:26
    until it experiences the shortage that creates the
  • 00:21:30
    pricing. I know everybody knows that, but it
  • 00:21:33
    is just an absolute fundamental attribute of a
  • 00:21:38
    market mechanism. So part of the issue that
  • 00:21:42
    we see getting back to ERCOT's identified potential
  • 00:21:46
    short term deficiencies, is that we're not seeing
  • 00:21:49
    a lot of shortage conditions priced into the
  • 00:21:55
    market. We do see some. I know this
  • 00:21:58
    last in the twelve months that I've been
  • 00:22:01
    here, we haven't had we didn't have a
  • 00:22:05
    severe summer, and I don't believe it was
  • 00:22:07
    a very severe winter this winter that we're
  • 00:22:10
    wrapping up now. Or maybe in Texas, we've
  • 00:22:13
    already wrapped wrapped it up. So part of
  • 00:22:18
    the consternation, I think, is that there's discussion
  • 00:22:22
    about short term and medium term resource adequacy
  • 00:22:27
    adequacy or reliability issues, but we're not seeing
  • 00:22:30
    the market prices in. So if we don't
  • 00:22:33
    see the prices form in the market reflecting
  • 00:22:36
    those shortages and the value to reliability of
  • 00:22:40
    having additional reliable capacity, then there's not going
  • 00:22:45
    to be any type of price signal or
  • 00:22:48
    revenue stream to incent either better performance or
  • 00:22:53
    new investment in upgrading existing facilities or building
  • 00:22:57
    new generation facilities. So from and I know
  • 00:23:03
    folks in this room have been in a
  • 00:23:04
    lot of conversations about resource adequacy and even
  • 00:23:08
    shorter term reliability. I'm not calibrating my observation
  • 00:23:15
    just on the twelve months that I've been
  • 00:23:17
    here, but even in the last three years,
  • 00:23:20
    ever since 2021, we really haven't seen that
  • 00:23:25
    much in the way of genuine shortage conditions
  • 00:23:29
    providing revenue streams. So the question is, do
  • 00:23:33
    we have a problem in the short run?
  • 00:23:36
    And the medium run's a different question that
  • 00:23:40
    I'll get to in a minute. But weather
  • 00:23:45
    and temperature vary from year next twelve months
  • 00:23:50
    might produce a very different set of outcomes.
  • 00:23:52
    We might have a hot summer. We might
  • 00:23:54
    have some very severe winter conditions that would
  • 00:23:58
    produce greater shortage conditions that would be priced
  • 00:24:01
    in or evident through price formation and provide
  • 00:24:06
    a signal that some additional revenue or excuse
  • 00:24:10
    me, some additional capacity or better performance were
  • 00:24:13
    needed. So in the short term, I think
  • 00:24:18
    I view the short term concern as being
  • 00:24:22
    more of a price formation and are we
  • 00:24:28
    actually observing tight conditions or not type of
  • 00:24:31
    issue and more of an existing resource performance
  • 00:24:35
    issue. In the medium term, with this large
  • 00:24:39
    load growth that's projected in Texas, it's a
  • 00:24:42
    different matter altogether. So for the medium term,
  • 00:24:48
    you've as I mentioned when I started, there
  • 00:24:52
    is no revenue stream through price formation if
  • 00:24:57
    you don't observe the shortage conditions that you
  • 00:25:00
    would expect to create higher prices. The medium
  • 00:25:04
    term Jeff, may I ask you just a
  • 00:25:07
    clarifying point because you keep using the term
  • 00:25:09
    over and over? That you were using the
  • 00:25:12
    second bullet point you say that we need
  • 00:25:15
    to experience shortage in order to provide the
  • 00:25:19
    proper price signals. Are you talking about actual
  • 00:25:22
    physical shortage? Yes. Well, the terms are tricky.
  • 00:25:30
    Thank you for asking that question. So I
  • 00:25:32
    use shortage because historically I've spoke of relative
  • 00:25:36
    shortage, meaning you're not short to the point
  • 00:25:43
    where you're experiencing involuntary load shed, but you
  • 00:25:47
    are short enough that you're having to dispatch
  • 00:25:50
    much higher cost or maybe even getting into
  • 00:25:54
    ERCOT scarcity pricing where you don't have the
  • 00:25:58
    level of reserves that are prescribed, and so
  • 00:26:01
    you're seeing a higher price as a result
  • 00:26:03
    of that reserve shortage. So when I talk
  • 00:26:06
    about shortages, I'm not talking about involuntary load
  • 00:26:09
    shed. I'm talking about tighter conditions, having to
  • 00:26:15
    dispatch higher cost units and winding up in
  • 00:26:19
    a circumstance where you either have operating reserve
  • 00:26:21
    shortage or even a power balance constraint violation
  • 00:26:24
    where they're just for some period of time,
  • 00:26:27
    there's not enough energy to meet demand, but
  • 00:26:31
    it isn't so severe that you wind up
  • 00:26:33
    curtailing load. Does that help? It does. That
  • 00:26:38
    would be helpful as we move along. Okay.
  • 00:26:40
    What you have to say? Yes. So anyway,
  • 00:26:45
    the market needs to experience the shortage in
  • 00:26:47
    order to see the shortage pricing, in order
  • 00:26:49
    to provide the revenue, in order to get
  • 00:26:51
    the greater performance or the new investment. And
  • 00:26:55
    so that's the debate. Since I've been here,
  • 00:26:59
    much of the conversations that I've been in
  • 00:27:02
    have been around how do we get more
  • 00:27:05
    revenue in the market. Do we need new
  • 00:27:07
    products? Do we need to adjust the operating
  • 00:27:10
    reserve demand curve so that we get higher
  • 00:27:12
    shortage pricing? Those are two of the primary
  • 00:27:17
    conversations that I've had, and I've spoken with
  • 00:27:19
    a lot of stakeholders who have brought these
  • 00:27:21
    issues up with me. And those are reasonable
  • 00:27:26
    ways to go about injecting more revenue. But
  • 00:27:29
    the second slide that I have well, actually,
  • 00:27:33
    before I get to the second slide, I'll
  • 00:27:34
    get back to that in a second. One
  • 00:27:38
    of the things that I mentioned first was
  • 00:27:39
    you have to have a well defined need,
  • 00:27:42
    you have to have a well defined product,
  • 00:27:44
    and it's got to be set up or
  • 00:27:45
    calibrated such that it provides what the revenue
  • 00:27:48
    stream to give you the performance or the
  • 00:27:49
    new investment that you need. So one of
  • 00:27:53
    the things that I noticed when we started
  • 00:27:56
    talking about the reliability standard last summer and
  • 00:28:01
    the value of loss load that's approved for
  • 00:28:05
    planning purposes is in ERCOT, we've calibrated to
  • 00:28:11
    some degree, we've calibrated the operating reserve demand
  • 00:28:14
    curve to a value of loss load that
  • 00:28:17
    is much lower than what we have approved
  • 00:28:22
    for a planning purpose. So on the one
  • 00:28:23
    hand, we've approved $35,000 for the value of
  • 00:28:28
    loss load for planning purposes and an equivalent
  • 00:28:31
    measure of that for the operating reserve demand
  • 00:28:33
    curve would be about $5,000 So the demand
  • 00:28:37
    curve is calibrated to value losing load at
  • 00:28:41
    just $5,000 Therefore, when you get these shortage
  • 00:28:46
    conditions that cause price formation and shortage pricing,
  • 00:28:50
    you're going to get a revenue stream for
  • 00:28:53
    new investment or better performance that only reflects
  • 00:28:56
    $5,000 for the value of last load. You're
  • 00:29:00
    not going to get a revenue stream that
  • 00:29:02
    would reflect a higher value of lost load
  • 00:29:05
    that might induce additional investment to help you
  • 00:29:09
    in the shorter term overcome short term reliability
  • 00:29:14
    issues and in the medium term, help get
  • 00:29:16
    enough new investment in order to meet your
  • 00:29:19
    resource adequacy requirements. So that is one example
  • 00:29:25
    of, I think an operating reserve demand curve
  • 00:29:28
    is a fantastic tool for sending signals to
  • 00:29:31
    the market, but there's a disconnect between how
  • 00:29:35
    we value losing load at a planning level
  • 00:29:38
    and how we value it at the operational
  • 00:29:41
    level. So that's an interesting point and one
  • 00:29:45
    area where some different calibration could provide a
  • 00:29:49
    better incentive to achieve the goals. So moving
  • 00:29:55
    to the next slide. I mentioned I've had
  • 00:29:58
    dozens of conversations with market participants about how
  • 00:30:02
    to get more revenue into the market in
  • 00:30:06
    order to help meet resource adequacy goals. One
  • 00:30:11
    of the things I'd like to highlight, and
  • 00:30:13
    I'm sure everybody here knows it, but it's
  • 00:30:15
    worth stating, the revenue requirement in order to
  • 00:30:20
    avert retirement is much lower for existing resources
  • 00:30:25
    than the revenue requirement in order to incent
  • 00:30:28
    new investment and new generation resources. And so
  • 00:30:32
    there's a gap. So if you're choosing to
  • 00:30:38
    tweak market design or create new products just
  • 00:30:42
    to try and move more money into the
  • 00:30:44
    market, you may be achieving staving off some
  • 00:30:48
    retirement, which helps with your resource adequacy goal,
  • 00:30:52
    but you may not be getting anywhere near
  • 00:30:55
    where you need to be in order to
  • 00:30:56
    incent new investment. The market signal just isn't
  • 00:31:00
    there for new investment. And because of the
  • 00:31:02
    gap between staving off retirement and achieving revenue
  • 00:31:08
    that incents new investment, you could easily wind
  • 00:31:11
    up pushing an amount of money or revenue
  • 00:31:15
    or rate payer money into the market that
  • 00:31:19
    is well above what you need in order
  • 00:31:22
    to stave off retirement, but not nearly close
  • 00:31:25
    enough to incent new investment is that I
  • 00:31:29
    forget which term I used in here, excess
  • 00:31:31
    cost. So that would be an example of
  • 00:31:34
    excess cost and that would come about by
  • 00:31:38
    not having a very targeted market instrument that
  • 00:31:41
    was calibrated to produce a level of revenue
  • 00:31:44
    where you would achieve what you wanted if
  • 00:31:46
    what you want is new investment. So I
  • 00:31:49
    wanted to highlight that because a lot of
  • 00:31:51
    the conversations that I've been in have been
  • 00:31:54
    about just trying to push some more money
  • 00:31:57
    into the spot market. And I don't favor
  • 00:32:02
    that approach. I like a more structured approach,
  • 00:32:04
    but I wanted to highlight the potential excess
  • 00:32:07
    cost to taking that approach. If you don't
  • 00:32:09
    know what it is that you're trying to
  • 00:32:11
    achieve and you don't know how much extra
  • 00:32:14
    revenue you need to get it, there could
  • 00:32:17
    be a considerable amount of excess cost by
  • 00:32:23
    taking more of a patchwork approach just trying
  • 00:32:26
    to move money into the market. So I
  • 00:32:29
    wanted to share that perspective with you. I
  • 00:32:31
    gave some thought to what might be valuable
  • 00:32:35
    to you. I've been in so many of
  • 00:32:37
    these conversations, I thought that this concept was
  • 00:32:40
    at least worth discussing, thought and I'd be
  • 00:32:43
    happy to answer any questions. I have another
  • 00:32:47
    question. Go ahead, Peg. So if I understand
  • 00:32:51
    what you're saying correctly is that there's a
  • 00:32:53
    disconnect between value of loss loan at $35,000
  • 00:32:57
    and what we're using for operating purposes and
  • 00:33:01
    that we should meet the ORDC would need
  • 00:33:04
    to be increased. Do we have the authority
  • 00:33:09
    to do that? Or is that a legislative
  • 00:33:11
    change? I don't have the answer to that.
  • 00:33:17
    My hunch is that's a PUC matter. I'm
  • 00:33:21
    getting nods. So I believe that's a PUC
  • 00:33:23
    matter. Jeff, do you have a question? That's
  • 00:33:30
    correct. It's a PUC decision. Any other question?
  • 00:33:38
    I have one. Go ahead, Courtney. Your last
  • 00:33:41
    line, revenue source should be tied to reliability
  • 00:33:44
    goal. What do you mean there? So I
  • 00:33:48
    phrased it that way because in the short
  • 00:33:51
    term, it's usually a reliability issue. So take
  • 00:33:54
    DRRS, for example. So there's an identified gap
  • 00:34:01
    for forecast error far enough out that you
  • 00:34:06
    wouldn't expect your non spin procurement to cover
  • 00:34:08
    it. So there was a very specific gap
  • 00:34:13
    in reliability. ERCOT will go through a process
  • 00:34:18
    through engineering analysis, determining how much to procure
  • 00:34:23
    to fill that gap. How it's integrated in
  • 00:34:27
    with energy and reserves determine how prices are
  • 00:34:31
    formed, but it's a very specific reliability issue
  • 00:34:35
    that's being addressed with DRRS. The medium term
  • 00:34:39
    example is your resource adequacy. So if the
  • 00:34:43
    goal is to meet the reliability standard, then
  • 00:34:46
    we need to have a look at what
  • 00:34:48
    the reliability standard prescribes in terms of a
  • 00:34:53
    current deficiency. We have to understand what that
  • 00:34:56
    means in terms of how many more megawatts
  • 00:34:59
    need to be built to meet that. And
  • 00:35:01
    then that tells us how much revenue we
  • 00:35:05
    need to inject into the market. And so
  • 00:35:07
    if a new product is intended to meet
  • 00:35:10
    the reliability standard or a reliability standard, you
  • 00:35:14
    have to work from their back as you
  • 00:35:16
    design a product that will help you meet
  • 00:35:18
    that so you understand how much revenue that
  • 00:35:20
    product has to produce in order to get
  • 00:35:22
    you to your goal. If you only get
  • 00:35:25
    halfway to your goal, but you spend I'll
  • 00:35:29
    make up a number, dollars 5,000,000,000, but you
  • 00:35:33
    only get halfway to your goal, that could
  • 00:35:35
    be for a couple of reasons. One is
  • 00:35:37
    the market may just not have signaled enough
  • 00:35:39
    need in the five years that we might
  • 00:35:41
    be talking about hypothetically, but it also might
  • 00:35:44
    be that the designers did not calibrate the
  • 00:35:48
    revenue that they would expect from that product
  • 00:35:51
    to meet the need. Is that I'd be
  • 00:35:58
    happy if you have a follow-up question or
  • 00:36:00
    if part of that wasn't clear, I'd be
  • 00:36:01
    happy to clarify. Okay. Let me sort of
  • 00:36:05
    expand on that with a little going in
  • 00:36:07
    a little bit different direction. I mean you
  • 00:36:09
    talked about the concept of shortage setting shortages
  • 00:36:14
    sending pricing market price signals. You also talked
  • 00:36:18
    about reliability has revenue value. You didn't say
  • 00:36:25
    that, I'm saying that, but I'm reading between
  • 00:36:27
    the lines. But when you look at resource
  • 00:36:31
    mixes, does the growth and certain types of
  • 00:36:35
    resource types, let's say intermittent resources in particular,
  • 00:36:40
    potentially mask the shortage signals that would otherwise
  • 00:36:44
    be present for scenarios when they're not when
  • 00:36:47
    those intermittent resources aren't available? Yes. So that's
  • 00:36:51
    a great question. And there's probably two parts
  • 00:36:55
    to my answer to that. One is this
  • 00:36:58
    concept of effective load carrying capacity or ELCC
  • 00:37:02
    is intended to address that in a planning
  • 00:37:05
    space. So with respect to your RA goal,
  • 00:37:11
    you would want to factor in how much
  • 00:37:17
    contribution to your reliability each of those different
  • 00:37:20
    types of resources makes because as you point
  • 00:37:23
    out, it is different. So recently with the
  • 00:37:27
    FFSS program, part of the discussion there has
  • 00:37:33
    been can we put natural gas resources with
  • 00:37:38
    very firm expectations of delivery of fuel? Can
  • 00:37:41
    we add those in with the oil storage?
  • 00:37:46
    Or can we not because the differential in
  • 00:37:49
    reliability between the two is sufficient that they
  • 00:37:53
    don't belong together in the same service. So
  • 00:37:58
    I think at least from a planning perspective
  • 00:38:01
    and of course, your planning is forward looking
  • 00:38:04
    if you get your planning perspective correct and
  • 00:38:06
    your ELCC correct for the different resources when
  • 00:38:10
    you move forward in time and you get
  • 00:38:12
    to that point in time where you're utilizing
  • 00:38:14
    them in an operational space, hopefully, world unfolds
  • 00:38:18
    such that your analysis was accurate and you
  • 00:38:21
    discounted reliability from intermittent appropriately. And what that
  • 00:38:27
    would also mean is that with a reliability
  • 00:38:29
    product that you develop to help meet those
  • 00:38:32
    goals, the other resources that were less intermittent
  • 00:38:36
    and more reliable would have a greater revenue
  • 00:38:38
    source or stream. Okay. And just to talk
  • 00:38:42
    about ELCC for a minute. So Diamond supports
  • 00:38:47
    the ELCC concept that, that is a reliable
  • 00:38:50
    way to value the capacity of renewable resources
  • 00:38:55
    or intermittent resources? Yes. Okay. And in fact,
  • 00:39:00
    in New England, they moved into ELCC a
  • 00:39:04
    few years ago and the issue of pipeline
  • 00:39:07
    curtailments came up as well because that is
  • 00:39:11
    a form of intermittency, especially when you need
  • 00:39:14
    them. So it's not just for traditionally intermittent
  • 00:39:17
    or renewable resources. It's a generic concept that
  • 00:39:21
    should apply to all resources. Yes, that's a
  • 00:39:23
    good point. I haven't thought about that. Any
  • 00:39:25
    other questions, comments? Okay. Well, any closing comments,
  • 00:39:32
    Jeff? Okay. Thanks for your report and we
  • 00:39:37
    look forward to seeing you in the future.
  • 00:39:39
    Thank you. Thank you for your time. Thank
  • 00:39:41
    you. We're next going to move to agenda
  • Item 5.3 - Commercial Markets Update
    00:39:44
    item ES excuse me, 5.3 commercial markets update.
  • 00:39:50
    Keith Collins is going to present. All right.
  • 00:40:03
    Thank you. Happy to present to you today
  • 00:40:08
    the commercial market update. We're going to cover
  • 00:40:12
    three items today. The first one is introduce
  • 00:40:16
    to you a new initiative we're working on,
  • 00:40:20
    which is residential demand response. We did talk
  • 00:40:22
    at the last R and M meeting about
  • 00:40:25
    the importance of demand response, and so we
  • 00:40:28
    will sort of outline what we're planning to
  • 00:40:29
    work on this year. The second item is
  • 00:40:33
    related to credit. We do we've sort of
  • 00:40:38
    rolled our presentations together here for the full
  • 00:40:43
    Board. And so I'll be covering some work
  • 00:40:45
    we're doing on credit. And then finally, with
  • 00:40:48
    some discussion around pricing outcomes during February's winter
  • 00:40:53
    weather event. All right. So I'll start here
  • 00:40:57
    with our new residential demand response program. We
  • 00:41:01
    do have some ideas that we're going to
  • 00:41:04
    be working through the stakeholder process on. We've
  • 00:41:07
    reached out to commission staff as well. And
  • 00:41:10
    ultimately, this program, when we think of the
  • 00:41:14
    efforts we're doing on demand response, there's sort
  • 00:41:17
    of we're hitting different elements, whether it's in
  • 00:41:21
    some programs, it allows for aggregated resources, industrial
  • 00:41:27
    resources. But we do think that there's an
  • 00:41:31
    opportunity in terms of smart devices, thermostats, pool
  • 00:41:35
    pumps, water heaters, things along that line and
  • 00:41:40
    to allow for a program that focus on
  • 00:41:42
    those types of resources. And I'll sort of
  • 00:41:45
    note that when we look at our corporate
  • 00:41:47
    priorities for 2025, demand response is a priority
  • 00:41:52
    for us, and we're working on this to
  • 00:41:55
    help meet those needs. And ultimately, even based
  • 00:42:00
    on some of Jeff's comments a minute ago
  • 00:42:02
    is, you know, what are the short term
  • 00:42:04
    reliability challenges and how do we meet them
  • 00:42:06
    in the short run if it takes a
  • 00:42:08
    while to build new resources and there's perhaps
  • 00:42:11
    some uncertainties on what we might see in
  • 00:42:15
    the medium term, well, demand response can play
  • 00:42:18
    a big role on that. And so we
  • 00:42:20
    see this as an important priority for 2025
  • 00:42:23
    to create those rules so that we can
  • 00:42:24
    get access to these resources moving forward. Ultimately,
  • 00:42:31
    it's an incentive payment that will make its
  • 00:42:33
    way to the retail energy providers through the
  • 00:42:38
    QSCs, but ultimately to identify what the value
  • 00:42:44
    that those demand response are providing during the
  • 00:42:48
    highest net load periods. Ultimately, our discussions with
  • 00:42:52
    stakeholders is going to it actually already has
  • 00:42:55
    commenced, but we'll be working on them, working
  • 00:42:58
    with stakeholders in the following quarters, Q2, Q3,
  • 00:43:02
    and have something by the end of the
  • 00:43:05
    year. The intent of the program is ultimately
  • 00:43:08
    something that's quick to develop, simple and as
  • 00:43:12
    administration can be popular for folks to be
  • 00:43:15
    a part of, and ultimately is cost effective
  • 00:43:18
    in the end. So that's our goals for
  • 00:43:20
    this year, and we do think that we
  • 00:43:23
    have some novel concepts that we'll be able
  • 00:43:26
    to accomplish this in the coming year. So
  • 00:43:28
    I'll pause and see if there's any questions
  • 00:43:30
    on on the Doctor program. Do you have
  • 00:43:35
    a timeline? The timeline is ultimately by the
  • 00:43:39
    end of the year, we want to have
  • 00:43:40
    the initiative complete. And in terms of implementation,
  • 00:43:45
    I think realistically, we'd love to have it
  • 00:43:49
    next year. But I think given realistically, it'd
  • 00:43:52
    probably be for 2027 is that we would
  • 00:43:55
    implement it. So work on design this year,
  • 00:43:58
    work on development in 'twenty six and implement
  • 00:44:02
    in the 'twenty seven time frame. The next
  • 00:44:12
    item to talk about that commercial operations is
  • 00:44:15
    working on, this is something that we had
  • 00:44:17
    given an update to the R and M
  • 00:44:19
    Committee at its last meeting, is that we
  • 00:44:22
    had developed some policy items that we're working
  • 00:44:25
    on to modify some formulas that evaluate the
  • 00:44:31
    aggregate liability in that we assess. We had
  • 00:44:36
    identified at the R and M that we
  • 00:44:38
    had an approach and a method. And ultimately,
  • 00:44:41
    what we're bringing to you today is to
  • 00:44:42
    say that we now have an NPRR,
  • 00:44:46
    NPRR1277 that essentially codifies those policy
  • 00:44:52
    changes into the NPRR. I will note that
  • 00:44:56
    ultimately, the goals of this policy change is
  • 00:45:00
    to address sort of overcollateralization during periods of
  • 00:45:05
    essentially when you have significant price movements upwards.
  • 00:45:10
    What we found is that it can create
  • 00:45:13
    a large overcollection. We did show some examples
  • 00:45:17
    at the RMM last time, And this will
  • 00:45:20
    address that. We'll address some of the volatility
  • 00:45:22
    in those collateral requirements. And also, it will
  • 00:45:26
    address some undercollateralization as well. Ultimately, we think
  • 00:45:30
    that there's been a broad consensus on these
  • 00:45:35
    changes to the formulation. And we think that
  • 00:45:37
    this is ultimately going to be an improvement
  • 00:45:40
    and enhancement going forward. So we see this
  • 00:45:43
    as just continuation of what we did with
  • 00:45:47
    the policy. I will note that credit is
  • 00:45:50
    obviously something that we see as a high
  • 00:45:53
    potential risk to the organization. But what we're
  • 00:45:57
    doing here is helping to further mitigate that
  • 00:46:01
    risk as we're moving forward. So I'll pause
  • 00:46:03
    and see if there are any additional questions
  • 00:46:05
    on the formula changes on the credit. Any
  • 00:46:11
    questions? Okay. Okay. Hearing none, we'll keep going
  • 00:46:16
    forward. The third item that I wanted to
  • 00:46:18
    cover today was some discussion about the February
  • 00:46:22
    winter weather event. I know Dan's going to
  • 00:46:24
    be approaching it from an operational perspective, but
  • 00:46:28
    wanted to also approach it from a market
  • 00:46:30
    perspective and what we saw during the recent
  • 00:46:33
    winter cold snap in February. And so we'll
  • 00:46:38
    cover pricing. We'll talk a little bit about
  • 00:46:40
    firm fuel supply service, reliability unit commitment during
  • 00:46:44
    that period and some of the congestion that
  • 00:46:47
    we saw. All right. So what we have
  • 00:46:51
    here in the first couple the first slide
  • 00:46:54
    here and the first two charts that we
  • 00:46:56
    have is we do have day head pricing
  • 00:47:01
    in the top chart and the real time
  • 00:47:02
    pricing in the bottom chart. And one of
  • 00:47:06
    the things that did stand out in this
  • 00:47:07
    event was the timing, let's say, of some
  • 00:47:12
    of the pricing impacts differed in the market.
  • 00:47:15
    So for instance, on that first day on
  • 00:47:18
    Wednesday, February 19, the day ahead market was
  • 00:47:22
    generally fairly quiet. But what we saw in
  • 00:47:24
    the real time that we started to see
  • 00:47:26
    some elevated prices in both the morning ramp
  • 00:47:29
    and the evening ramp during the cold as
  • 00:47:33
    the cold snap was coming in. And ultimately,
  • 00:47:37
    the highest prices we saw at the hub
  • 00:47:39
    level during the real time happened to be
  • 00:47:42
    on that first day. So as that event
  • 00:47:44
    came in, the day ahead didn't did not
  • 00:47:48
    to the same extent that the same impacts
  • 00:47:52
    were not seen, but we did have the
  • 00:47:53
    real time reactions in both those ramping periods.
  • 00:47:57
    In the day ahead market on the Thursday,
  • 00:47:59
    you'll see that we had our highest day
  • 00:48:01
    ahead prices of over $800 at the hub,
  • 00:48:04
    particularly noted in the morning ramp. And we
  • 00:48:07
    saw the morning ramp also high in real
  • 00:48:10
    time on that day as well. And then
  • 00:48:12
    over the course of the next couple of
  • 00:48:14
    days, we did see ramping impacts during the
  • 00:48:18
    morning and evening ramping periods, but nothing nothing
  • 00:48:21
    as extreme as as what we saw on
  • 00:48:23
    on that Thursday Thursday event. And so one
  • 00:48:29
    of the things to to take away from
  • 00:48:32
    from the importance of pricing, and I'll I'll
  • 00:48:35
    get to that in a second. Actually, I'll
  • 00:48:37
    skip ahead to it, is the connection and
  • 00:48:40
    the relationship of the pricing and what we
  • 00:48:43
    saw in in terms of reliability unit commitment.
  • 00:48:46
    So when operators are are taking actions to
  • 00:48:50
    secure the the system through reliability unit commitment,
  • 00:48:54
    when the pricing was strongest in the day
  • 00:48:58
    ahead, and that was on that Thursday, you'll
  • 00:49:00
    see that the RUC the RUCs during that
  • 00:49:02
    period were were the were the lowest. And
  • 00:49:05
    that's that's an important outcome. And I I
  • 00:49:07
    think that's actually gonna be important discussion point
  • 00:49:09
    when we we talk about NPRR1269
  • 00:49:12
    later today and and into tomorrow is the
  • 00:49:15
    the stronger the the signal in in in
  • 00:49:18
    the market, in this case, the day ahead
  • 00:49:20
    market, the less use of RUC that we
  • 00:49:23
    saw in on those days. And and ultimately,
  • 00:49:28
    that that month on the Wednesday, the nineteenth
  • 00:49:31
    and Friday, the twenty first, what we saw
  • 00:49:34
    there were were some elevated levels of RUC,
  • 00:49:36
    as we compare that to other periods. These
  • 00:49:40
    were were higher instances of RUC, whereas on
  • 00:49:42
    that Thursday was was significantly less, given the
  • 00:49:45
    price signals were stronger in the day ahead
  • 00:49:47
    on that day. Okay. So just stepping back
  • 00:49:51
    for a minute. Another thing that is important
  • 00:49:54
    is firm fuel supply service. So this is
  • 00:49:58
    a program to help ensure that we have
  • 00:50:01
    availability of on-site as it is now on-site
  • 00:50:05
    availability, particularly fuel oil resources available? And are
  • 00:50:09
    those resources called upon during these events? And
  • 00:50:13
    in this case, yes, we saw on the
  • 00:50:16
    nineteenth, the twentieth and the twenty first, we
  • 00:50:18
    did activate those resources that have those firm
  • 00:50:21
    fuel on these days. So it was ultimately
  • 00:50:24
    four resources up to just under 500 megawatts
  • 00:50:28
    of availability. So this is looking back over
  • 00:50:32
    the last couple of years, we saw firm
  • 00:50:34
    fuel during one cold snap. I believe it
  • 00:50:37
    was winter storm Heather in 2024. And in
  • 00:50:43
    the 'twenty three time frame, we did see
  • 00:50:45
    a couple instances of firm fuel. So it's
  • 00:50:48
    common to see these things at least once
  • 00:50:51
    a season. And this was the event that
  • 00:50:54
    we saw and the performance we had during
  • 00:50:56
    those days. Keith? Yes. How does it take
  • 00:51:00
    so long to evaluate the performance? So ultimately
  • 00:51:05
    we're looking at ultimately the reasons for why
  • 00:51:12
    you can see there's a delta between what
  • 00:51:14
    the points are versus their obligation and HSL.
  • 00:51:18
    And so we have to reach out to
  • 00:51:21
    the the resources, look at the data, and
  • 00:51:23
    and be able to do that. I think
  • 00:51:25
    the the other reason why it takes so
  • 00:51:27
    long is that a lot of the resources
  • 00:51:29
    that would do that analysis are also focused
  • 00:51:31
    on our real time co optimization analysis. And
  • 00:51:34
    so it's it's a competing resource challenge that
  • 00:51:37
    we see to evaluate it. So I think
  • 00:51:39
    our hope is that we'll be able to
  • 00:51:41
    do it. But given some of the challenges
  • 00:51:43
    with with what we're doing with the RTC,
  • 00:51:47
    those resources were dedicated to evaluating that. Okay.
  • 00:51:54
    All right. Okay. And then the final point
  • 00:52:00
    I wanted to cover is congestion. And what
  • 00:52:03
    we saw, there was some significant difference between
  • 00:52:05
    congestion in the day ahead and in the
  • 00:52:08
    real time. The day ahead, the highest congestion
  • 00:52:11
    levels were on the Thursday. And then in
  • 00:52:14
    the real time, was on the Tuesday on
  • 00:52:18
    the nineteenth. And you can see the South
  • 00:52:21
    Zone is the prominent congestion zone, and that's
  • 00:52:25
    where we've seen a lot of the sort
  • 00:52:26
    of South export constraint, and that did play
  • 00:52:29
    a role in this event as well. So
  • 00:52:32
    that's one of the reasons why we did
  • 00:52:33
    see the high congestion on those days. On
  • 00:52:36
    the nineteenth, as we noted, even for the
  • 00:52:38
    energy prices, it was more in the real
  • 00:52:42
    time was more significant than what we saw
  • 00:52:44
    in the day ahead, and and the congestion
  • 00:52:45
    pattern reflects that as well. Okay. And then,
  • 00:52:53
    ultimately, we did have some additional slides where
  • 00:52:55
    we did cover things like ancillary services. I
  • 00:52:58
    will note that ancillary services during this period
  • 00:53:00
    did reach over $200 while the prices reached
  • 00:53:05
    over $800 We do have additional slides on
  • 00:53:07
    that. I also note that we do have
  • 00:53:09
    a credit slide at the end where I
  • 00:53:12
    think the key takeaway is that there's the
  • 00:53:17
    credit outcomes are very normal even given the
  • 00:53:19
    pricing outcomes we saw during this event. So
  • 00:53:22
    I'll pause and see if any final questions
  • 00:53:24
    for me. Keith, have a question on the
  • 00:53:26
    congestion on this Is it atypical to have
  • 00:53:31
    that bigger variance between day ahead and real
  • 00:53:33
    time when it comes to congestion? Think we
  • 00:53:37
    generally don't see these large differences in congestion
  • 00:53:41
    unless there's something significant happening. I think so
  • 00:53:46
    your question is, is it atypical? The answer
  • 00:53:48
    is yes. Is there anything happening here that
  • 00:53:51
    happened between day ahead and real time that
  • 00:53:54
    caused this. And I think the big difference
  • 00:53:56
    here was that when you look at the
  • 00:53:59
    market outcomes on the nineteenth in particular for
  • 00:54:04
    the day ahead, they didn't reflect the same
  • 00:54:06
    conditions that actually materialized in real time. And
  • 00:54:09
    so that congestion was exacerbated and particularly noted
  • 00:54:13
    on that nineteenth day. Okay. Any other question?
  • 00:54:17
    Yes. Really a question. I just I'd ask
  • 00:54:20
    Heath if I could ask him to just
  • 00:54:21
    go to the appendix real quick. Slide 16
  • 00:54:25
    in your appendix. Could you talk a little
  • 00:54:27
    bit about the kind of structural change in
  • 00:54:30
    drivers for ERCOT that look like we've got
  • 00:54:34
    quite a bit more congestion consistently driving rocking
  • 00:54:37
    activities versus historical periods. Can you talk a
  • 00:54:40
    little bit about that? Yes. So the you'll
  • 00:54:44
    know that represented in that dark gray line
  • 00:54:47
    that we see here. And as Pablo was
  • 00:54:50
    noting in the sort of that spring period,
  • 00:54:52
    we saw an increase and in several months,
  • 00:54:56
    it's been the bigger portion of the RUC.
  • 00:54:59
    And it is related to the essentially the
  • 00:55:03
    same constraint that our RMR resources are looking
  • 00:55:07
    to address. And so we see that constraint
  • 00:55:10
    being more of a role in the market.
  • 00:55:13
    We see that constraint playing a role with
  • 00:55:15
    RUC activity and so and obviously the need
  • 00:55:19
    for the RMR resources. So it is playing
  • 00:55:22
    a significantly larger role over the last several
  • 00:55:26
    months in what we're doing here. Okay. Any
  • 00:55:33
    other questions for Keith on the operations reports?
  • 00:55:38
    Keith, anything else we should have asked if
  • 00:55:39
    we didn't? No, no, that's it. Thank you.
  • 00:55:42
    Thank you. The last or the next item
  • 00:55:44
    for today is agenda item 5.3.1 real time
  • 00:55:49
    co station update. Matt is going to present
  • Item 5.3.1 - Real-Time Co-optimization Update
    00:55:51
    this. Good afternoon board members. Matt Marinas, ERCOT.
  • 00:56:03
    Apologies for the updates. We had quite a
  • 00:56:05
    few red lines through this. The main reason
  • 00:56:07
    we knew that we want to update this
  • 00:56:09
    presentation is that we've been reaching out to
  • 00:56:11
    stakeholders to see if they're ready for RTC.
  • 00:56:13
    So we did get a dashboard folded in
  • 00:56:16
    there. The main piece is that we had
  • 00:56:18
    a market cost of reconstructions. As we start
  • 00:56:21
    to unpack the analysis in today's presentation, one
  • 00:56:25
    of the things that came up after TAC
  • 00:56:27
    was, well, if this is the cost of
  • 00:56:29
    an AS demand curve hanging up being a
  • 00:56:31
    floor, if we don't have that floor and
  • 00:56:33
    we have to rock more, what would those
  • 00:56:36
    costs look like? So we tried to put
  • 00:56:38
    the other side of the equation in on
  • 00:56:39
    this. And we'll hit that as we go
  • 00:56:40
    through the presentation. Alright. So today, we're going
  • 00:56:46
    to focus on two main things. One is
  • 00:56:48
    just the general program update. It's a one
  • 00:56:50
    pager instead of six. And really want to
  • 00:56:52
    do that to make room for this middle
  • 00:56:55
    piece, is the explanation of the three NPRRs.
  • 00:56:58
    Keith and I talked, the best thing I
  • 00:56:59
    can do today is prepare you for NPRR
  • 00:57:01
    NPRR1269 tomorrow. And so I'm happy
  • 00:57:03
    to dive into the program updates and go
  • 00:57:05
    there as needed, but we kind of restructured
  • 00:57:07
    this a little bit to hit mainly on
  • 00:57:09
    those. The key takeaways we'll hit at the
  • 00:57:12
    end again. So in terms of what is
  • 00:57:15
    the RTC plus B program and task force
  • 00:57:18
    doing, first on the policy items, again, those
  • 00:57:21
    three NPRRs are here before you today. A
  • 00:57:24
    lot of work went into that by the
  • 00:57:25
    way. The next is the initial task force
  • 00:57:27
    discussion of state of charge. So if we
  • 00:57:29
    have real time co optimization, it's cycling every
  • 00:57:31
    five minutes and batteries are in a currently
  • 00:57:35
    hourly market, should any of those parameters change
  • 00:57:38
    as we transition to RTC. So Jeff Bello,
  • 00:57:42
    Didica under Dan Woodfin's leadership is starting to
  • 00:57:45
    study that state of charge and how it
  • 00:57:47
    would be affected with real time compensation. And
  • 00:57:51
    we hope to bring an NPRR forward at
  • 00:57:53
    the next board meeting in June. The good
  • 00:57:55
    news is that is not a redesign element,
  • 00:57:57
    that's merely a parameter. Is the duration two
  • 00:57:59
    hours or four hours in a number that
  • 00:58:01
    we put in? The next one of the
  • 00:58:04
    program milestones, we hit a big one last
  • 00:58:06
    week. JP hit on it earlier. Internally, our
  • 00:58:09
    job in this best of breed systems that
  • 00:58:11
    we have, we have an energy management system,
  • 00:58:14
    a market management system, settlements and billing. And
  • 00:58:17
    those are the big three when it comes
  • 00:58:18
    to telemetry, markets and settling that market, that
  • 00:58:21
    is probably 90% of the cost of this
  • 00:58:24
    $50,000,000 program. And so what we've been able
  • 00:58:26
    to do is last week, we were able
  • 00:58:28
    to run our first operating day on those
  • 00:58:30
    three primary systems. JP had asked me what
  • 00:58:33
    keeps me up at night. That was the
  • 00:58:34
    test that was keeping me up. There's some
  • 00:58:36
    other stuff on the side, but if we
  • 00:58:37
    don't get that one right back in 2010,
  • 00:58:40
    that's when we turned the crank and things
  • 00:58:41
    didn't come out, and this was a real
  • 00:58:43
    win for the team. So probably 100 plus
  • 00:58:45
    people went into that one. The next one
  • 00:58:48
    is market readiness update. We sent out a
  • 00:58:51
    market notice to the Quasis with Resources and
  • 00:58:54
    we did this back last year in the
  • 00:58:56
    fall timeframe and said real time co optimization
  • 00:58:59
    is coming. Do you have an accountable executive
  • 00:59:01
    that we can work with on this? And
  • 00:59:03
    we scorecarded everyone. That was 105 QUEZYS and
  • 00:59:06
    everyone went green. We looked that up again
  • 00:59:08
    on mid March because we're getting ready to
  • 00:59:11
    start trials in May. And so we've hit
  • 00:59:13
    107 QUEZYS, 103 have responded back. We're still
  • 00:59:16
    working with those last four to check that
  • 00:59:19
    off, but we had a great response. So
  • 00:59:20
    I would love to say it was 100%,
  • 00:59:22
    but no one's told us they're not coming
  • 00:59:25
    to the trials at this point. So we'll
  • 00:59:26
    continue to work through that and you'll see
  • 00:59:28
    a completed scorecard at the next meeting. We've
  • 00:59:31
    also been working on a lot of market
  • 00:59:33
    trial handbooks. What does it look like? These
  • 00:59:35
    are our contracts with the market on how
  • 00:59:37
    do we test our systems and interact with
  • 00:59:39
    market participants as we go through those trials.
  • 00:59:42
    We've also set up some new training. We
  • 00:59:44
    went through a demand response. If you're a
  • 00:59:46
    load resource and here's how you respond in
  • 00:59:48
    RTC, what would that look like? We also
  • 00:59:51
    focus on the day ahead market changes and
  • 00:59:53
    operations changes. And then the bigger one right
  • 00:59:56
    now is the operator training seminar is going
  • 00:59:58
    on out in Taylor. Every week, we have
  • 01:00:00
    200 operators rolling to town and they go
  • 01:00:03
    through all this NERC certified training. Real time
  • 01:00:05
    co optimization has an hour and a half
  • 01:00:07
    of that training just to get everyone speaking
  • 01:00:09
    the same language. And then again, have a
  • 01:00:11
    lot more in Appendix A. I wasn't going
  • 01:00:13
    to plan to hit that today, but we
  • 01:00:14
    have another six slides in there if you
  • 01:00:15
    need it. So any questions on the program?
  • 01:00:18
    That was just kind of our helicopter flyby.
  • 01:00:22
    All right. I'll hit this one and then
  • 01:00:25
    we'll transition into the NPRRs. We've also been
  • 01:00:28
    what's it look like to protect a program?
  • 01:00:31
    The best thing you do is manage change.
  • 01:00:33
    And so the market has been really good
  • 01:00:35
    about not adding scope to the RTC program,
  • 01:00:39
    but it's also about minimizing changes. So first
  • 01:00:41
    of all, ERCOT has to have discipline. So
  • 01:00:43
    that's where JP brought forward the idea that
  • 01:00:45
    internal to ERCOT, there's a production freeze on
  • 01:00:47
    these impacted systems starting essentially at the May
  • 01:00:51
    through go live. And so essentially, it will
  • 01:00:52
    be take quite a bit of a reason,
  • 01:00:55
    reliability and executive sign off to roll more
  • 01:00:58
    changes into our systems between now and then.
  • 01:01:00
    So it's discipline is really the change. Sorry,
  • 01:01:03
    there's always discipline under our cockpit. We're raising
  • 01:01:06
    the bar on changes into our production systems.
  • 01:01:09
    The next one is this no major market
  • 01:01:11
    changes. For those of you that are PRS
  • 01:01:15
    or TAC, we have this dashboard that shows
  • 01:01:17
    up and it's kind of hard to see
  • 01:01:19
    on the right. But what I wanted to
  • 01:01:20
    tease out is normally Troy Anderson comes and
  • 01:01:22
    says, here's all the NPRRs that we're releasing
  • 01:01:24
    every month or every other month. And there's
  • 01:01:27
    lots of NPRRs, lots of changes coming. But
  • 01:01:29
    as you see, once we hit May, June,
  • 01:01:31
    July is boxed out. That's where we're just
  • 01:01:33
    doing real time co optimization. So we've reserved
  • 01:01:35
    the runway for that work. Okay. So the
  • 01:01:38
    NPRRs today, they're all connected. That's the weird
  • 01:01:42
    part. That's why I have to talk about
  • 01:01:43
    the ones that are consent to get to
  • 01:01:45
    the ones that aren't consent. So there's three
  • 01:01:48
    of these. The timeline that we've had, we've
  • 01:01:50
    had six RTCBTF meetings just to get to
  • 01:01:53
    this point. We've had TAC approval last month
  • 01:01:56
    on March 26, and we're here today for
  • 01:01:58
    your consideration tomorrow. And NPRR1268
  • 01:02:02
    and sixty nine and seventy, I have a
  • 01:02:04
    story on each of those. But the reason
  • 01:02:05
    we need this now is to get these
  • 01:02:07
    systems changed and into market trials so that
  • 01:02:10
    we can execute what protocols show. So the
  • 01:02:15
    first of is AS demand curves. You've heard
  • 01:02:17
    that, I don't know how many times you've
  • 01:02:19
    heard that word today. It's the idea of
  • 01:02:21
    these AS demand curves are something that if
  • 01:02:24
    you look at the top left figure, that's
  • 01:02:26
    what our ORDC curve looks like. That's the
  • 01:02:29
    current day price adder. That shows that there's
  • 01:02:31
    a $5,000 adder when we're on the edge
  • 01:02:33
    of running out of energy. So that's the
  • 01:02:35
    high demand of $5,000 and then it drops
  • 01:02:38
    off a slope. And essentially as our reserves
  • 01:02:40
    get tighter and tighter and tighter, the prices
  • 01:02:42
    go up. Well, was put in place to
  • 01:02:45
    offset what should have been there is AS
  • 01:02:46
    demand curves, which are used at other ISOs
  • 01:02:48
    because everybody else has RTC. We don't yet,
  • 01:02:51
    but that's what we're getting to. And so
  • 01:02:54
    when we filed with the commission back in
  • 01:02:55
    2019, the idea is what should those demand
  • 01:02:58
    curves look like and it was policy was
  • 01:03:00
    kind of framed out to say, let's get
  • 01:03:02
    them under the ORDC curve. So that's our
  • 01:03:04
    boundary that we've been working with. And the
  • 01:03:06
    idea was as those were approved in 2019,
  • 01:03:10
    we came back to the market today and
  • 01:03:13
    the IMM said, you know, there's actually a
  • 01:03:14
    better way to do this. There's a way
  • 01:03:16
    to remove slice and dice under that curve
  • 01:03:19
    to create these ramps. So what's being approved
  • 01:03:21
    is the one on the top left you'll
  • 01:03:23
    see are sudden drops. For example, top left
  • 01:03:26
    figure $5,000 says that the first megawatt of
  • 01:03:29
    regulation you go short on, the price goes
  • 01:03:30
    straight to $5,000 Well now on the bottom
  • 01:03:33
    right, NPRR1268 is where as
  • 01:03:35
    we go short on regulation, there's actually it's
  • 01:03:38
    a small, but there is a ramp that
  • 01:03:39
    doesn't start at $5,000 It starts in the
  • 01:03:42
    hundreds of dollars. And that's for the same
  • 01:03:44
    for the other services. So that's what was
  • 01:03:46
    brought in as a concept. It's been studied.
  • 01:03:49
    So the purpose was to improve the shape
  • 01:03:52
    of the AS domain curves. The history, it
  • 01:03:54
    was filed by the IMM in January 28.
  • 01:03:57
    Clarifying comments were submitted by ERCOT and Hunt
  • 01:04:00
    Energy. The IMM filed minor corrections on March
  • 01:04:03
    19, and TAC unanimously approved this. So that
  • 01:04:07
    one's good to go. But this is the
  • 01:04:09
    one to talk to remember because when we'll
  • 01:04:11
    come back to this AS demand curve shapes,
  • 01:04:13
    this is the slide to reference. NPRR1270. We had some additional clarifications. The big
  • 01:04:18
    seventy. We had some additional clarifications. The big
  • 01:04:21
    one was the idea that there's an original
  • 01:04:24
    market design that said, if a QUESI with
  • 01:04:27
    a resource can dispatch in SCAD, we'll automatically
  • 01:04:31
    qualify for non spin in ECRS. And thinking
  • 01:04:35
    through that at the task force was realizing,
  • 01:04:37
    wow, we're gonna start awarding ancillary services to
  • 01:04:40
    someone that didn't even qualify for them. Just
  • 01:04:42
    because they can dispatch to them, do they
  • 01:04:44
    know how to offer in? Do they know
  • 01:04:46
    how to telemetry? Do they know these other
  • 01:04:48
    things? And so we recognize that was a
  • 01:04:50
    gap. So we closed the gap by saying,
  • 01:04:52
    you can still qualify, but you have to
  • 01:04:54
    go through a process. It's not automatically done.
  • 01:04:57
    The big thing was, I have it here
  • 01:04:58
    on this bullet, is the removal of that
  • 01:05:00
    automatic qualification was ensure reliable ancillary services and
  • 01:05:04
    deployment and then also to help mitigate the
  • 01:05:07
    risk of market distortions by proxy offers. So
  • 01:05:10
    you say, what's a proxy offer? Well, a
  • 01:05:12
    proxy offer is something administratively created when Aqueasy
  • 01:05:16
    does not provide an offer price for the
  • 01:05:18
    full range of the resource or at all.
  • 01:05:20
    It's what does ERCOT administratively put in its
  • 01:05:23
    place. So if we had a bunch of
  • 01:05:25
    queasies accidentally participating in market with a bunch
  • 01:05:29
    of blank spaces, we would be dialing in
  • 01:05:30
    these numbers that would distort the market. So
  • 01:05:34
    the market was pleased with this because getting
  • 01:05:36
    rid of this automatic thing means people are
  • 01:05:39
    there because they've qualified, they're trained and they're
  • 01:05:41
    registered to do this stuff. So that helps
  • 01:05:43
    to mitigate the risk to these proxy offers.
  • 01:05:47
    So again, that was filed January 28. No
  • 01:05:50
    comments, PAC approval, good to go. Okay.
  • 01:05:56
    NPRR1269. So I called this an
  • 01:05:58
    omnibus thing because it had lots of stuff
  • 01:06:01
    in it, I regret that. It's a lot
  • 01:06:03
    in one thing. So let me kind of
  • 01:06:05
    untangle the easy stuff from the things where
  • 01:06:07
    we're getting stuck. So the purpose was to
  • 01:06:10
    codify a group of policy changes. I've been
  • 01:06:14
    coming here to the R and M group
  • 01:06:15
    with a list of all these things to
  • 01:06:16
    do. This is three out of the four
  • 01:06:18
    we needed to get done. So the first
  • 01:06:20
    one was scaling factors. It's done. We don't
  • 01:06:24
    need to talk about it. It's the idea
  • 01:06:25
    of how do we share ramping between energy
  • 01:06:27
    and ancillary services. The next one is the
  • 01:06:30
    parameters for AS proxy offer floors. That's been
  • 01:06:34
    an evolving discussion since November of last year.
  • 01:06:37
    Originally, ERCOT and the independent market monitor said,
  • 01:06:40
    if someone doesn't submit something, let's put in
  • 01:06:42
    a $0 per megawatt. While most RTC+BTF
  • 01:06:48
    stakeholders said, well, you can offer it in
  • 01:06:51
    free or you offer it at the cap.
  • 01:06:53
    It's kind of like put them in the
  • 01:06:54
    front of the line of the offer stack
  • 01:06:55
    or the end of the line. So after
  • 01:06:58
    extensive debate and some evaluations, ERCOT proposed a
  • 01:07:01
    compromise of using the minimum of $2,000 or
  • 01:07:06
    that x percentile of the AS demand curves,
  • 01:07:09
    95% of the AS demand curves. Just to
  • 01:07:12
    orient you to that, the idea of a
  • 01:07:14
    95% on the AS demand curve will be
  • 01:07:17
    going from left to right. So the 95%
  • 01:07:19
    is on those values at the end of
  • 01:07:20
    the demand curve, not at the high side
  • 01:07:22
    of this. So this is where non spin
  • 01:07:24
    could be in the tens of dollars when
  • 01:07:26
    it hits that proxy at 95% or $100
  • 01:07:29
    for ECRS. So I just want to give
  • 01:07:31
    you kind of how that the mechanics of
  • 01:07:33
    that work. So ERCOT submitted comments to memorialize
  • 01:07:37
    that at 95%. The Independent Market Monitor and
  • 01:07:41
    the Texas Industrials submitted concerns with the approach,
  • 01:07:45
    including TIAC proposed a minimum of $15 or
  • 01:07:49
    95% of the curves. So that's policy number
  • 01:07:54
    two. Policy number three was the idea of
  • 01:07:59
    we when we run reliability unit commitment today,
  • 01:08:03
    we almost factors. It's a very high penalty
  • 01:08:06
    factor to make sure we get what we
  • 01:08:07
    need. So the idea was, can we use
  • 01:08:10
    those AS demand curves as the financial signal
  • 01:08:13
    in RUC for the operator to say, I
  • 01:08:15
    have scarcity, I need to cover the load
  • 01:08:18
    forecast error and get us through the day
  • 01:08:20
    securely and reliably. So the idea is what
  • 01:08:23
    does the ruck study tool for operators have
  • 01:08:25
    economically behind it to commit? And so the
  • 01:08:28
    ERCOT operator uses a ruck study tools to
  • 01:08:30
    ensure there's enough capacity for energy and ancillary
  • 01:08:33
    services. Assumed ERCOT assumed that we would have
  • 01:08:36
    to come back and analyze the ASDCs to
  • 01:08:40
    see if those would work in RUC. And
  • 01:08:42
    so we provided the RUC tool and found
  • 01:08:44
    that the AS demand curve for real time
  • 01:08:47
    and day ahead was such that it actually
  • 01:08:49
    worked with minimal changes. So we went from
  • 01:08:51
    penalty factors to an economic curve and it
  • 01:08:54
    looked like the numbers were there. With one
  • 01:08:56
    exception, when we got to a type of
  • 01:08:59
    operating day where that AS demand curve gets
  • 01:09:02
    very low at non spin, you can end
  • 01:09:04
    up $20 15 dollars 0 5 dollars 0
  • 01:09:07
    3 dollars 0 2 dollars out of this
  • 01:09:09
    nine megawatt range, there's no price signal there.
  • 01:09:13
    The control room wants ancillary services. The price
  • 01:09:18
    signal is $02 And so what ERCOT found
  • 01:09:20
    is if we put in the study tool
  • 01:09:22
    to increase that floor to $15 all of
  • 01:09:26
    a sudden things started to work better and
  • 01:09:27
    start to find and reoptimize to find a
  • 01:09:30
    solution. So ERCOT codified $15 We studied $50
  • 01:09:34
    down to $5 down to $0 in $5
  • 01:09:38
    increments. And $15 was the sweet spot to
  • 01:09:40
    get the most for minimal price. So that
  • 01:09:44
    was done in comments on March 3. Okay.
  • 01:09:48
    So those are the three policies that when
  • 01:09:51
    the RUC demand curve was studied, TCPA recognized
  • 01:09:57
    and filed on March 4, and we've all
  • 01:09:59
    been working together, right? We're at the task
  • 01:10:00
    force. They see what's coming. And as they
  • 01:10:03
    see our studies, there had been ongoing discussion
  • 01:10:07
    of the current AES demand curve may not
  • 01:10:09
    get the right market signals to get all
  • 01:10:11
    the ancillary services you want, ERCOT, should there
  • 01:10:13
    be a change. So as the RUC study
  • 01:10:16
    came out, that's when ERCOT identified the need
  • 01:10:19
    for an AS demand curve floor of $15
  • 01:10:22
    multiple market participants voiced belief that there should
  • 01:10:25
    be the same price signal for real time
  • 01:10:27
    and day ahead for those AS demand curves.
  • 01:10:30
    So ERCOT did a study for PRS and
  • 01:10:32
    TAC to demonstrate the reliability and market impacts
  • 01:10:35
    of that $15 floor. So Keith will touch
  • 01:10:38
    on that tomorrow. It's the idea is if
  • 01:10:39
    you have a $15 floor, what does it
  • 01:10:42
    reliably look like in terms of the number
  • 01:10:44
    of megawatts moving around and what's the price
  • 01:10:46
    on that? So we weren't going to get
  • 01:10:48
    into that today. I'm here to set the
  • 01:10:50
    stage for that tomorrow. Prior to attack, the
  • 01:10:54
    joint consumers had filed comments to propose the
  • 01:10:56
    AS demand curve, offer floor be zero. That's
  • 01:11:00
    how I said offer floor. AS demand curve
  • 01:11:03
    floor be $0 instead of $15 They're thinking
  • 01:11:07
    as they said, not what they said. As
  • 01:11:10
    they filed what was implied was that go
  • 01:11:13
    ahead and build the floor logic but implement
  • 01:11:15
    it at $0 and then you can change
  • 01:11:17
    the price up to $15 later if you
  • 01:11:18
    want to. So at the TAC, TAC approves
  • 01:11:22
    the version and the one that you'll have
  • 01:11:23
    before you tomorrow. It has the AS proxy
  • 01:11:26
    offer floor at the minimum of 2,000 or
  • 01:11:28
    95%, the RUC AS demand curve with a
  • 01:11:31
    $15 floor, the real time market and day
  • 01:11:35
    ahead market ASDCs with that same $15 floor.
  • 01:11:39
    And so since then ERCOT has filed comments
  • 01:11:41
    in support of $12.69 dollars ERCOT took the
  • 01:11:44
    time to kind of put that in the
  • 01:11:45
    study. Also the joint consumers filed comments on
  • 01:11:49
    Friday regarding this. And again, they were reinforcing
  • 01:11:52
    the idea of a $0 floor. So again,
  • 01:11:56
    Keith will talk more about this tomorrow, but
  • 01:11:58
    what tact is after filing our comments, the
  • 01:12:03
    idea was to put that analysis into comments
  • 01:12:06
    and as we brought that analysis forward of
  • 01:12:08
    what those price changes may look like, it's
  • 01:12:10
    actually commission staff said, again, what would it
  • 01:12:13
    look like if you were rucking instead? And
  • 01:12:16
    so that's why we started to put these
  • 01:12:18
    weave this story together, how things fit together.
  • 01:12:21
    And in the appendix are 16 pages of
  • 01:12:24
    study notes. So we can go into those
  • 01:12:26
    today if we want to. I would rather
  • 01:12:27
    not. But Keith will hit some of the
  • 01:12:29
    highlights of those tomorrow. So first one was
  • 01:12:32
    a proxy offer floor. ERCOT does believe it's
  • 01:12:34
    a good compromise to achieve the using the
  • 01:12:37
    minimum of 2,000 or the 95% of ASDCs.
  • 01:12:41
    Although ERCOT has not tested other specific values,
  • 01:12:44
    all studies performed in recent months have used
  • 01:12:46
    these values and we have not observed any
  • 01:12:48
    price formation issues. This has been the backbone
  • 01:12:51
    of all of our studies. If we don't
  • 01:12:53
    have a curve, put in the price or
  • 01:12:55
    an offer, put in the price and run
  • 01:12:56
    the study and we've run this over and
  • 01:12:58
    over again. And we're not seeing that $2,000
  • 01:13:00
    striking the price. The next piece, this is
  • 01:13:03
    a more important one, the ASCC floor for
  • 01:13:06
    real time and day ahead. ERCOT believes the
  • 01:13:08
    $15 floor is appropriate and reasonable to help
  • 01:13:11
    align and incent self commitment by the Queasies
  • 01:13:14
    to reduce risk of RUC operator commitments and
  • 01:13:18
    to properly value the full ancillary service plan.
  • 01:13:20
    In other words, not come up short. While
  • 01:13:23
    the AS demand curve floor would impact energy
  • 01:13:26
    and ancillary services prices, as you'll see in
  • 01:13:28
    our study, the RUC instructions will also impact
  • 01:13:31
    the market in the form of inferior long
  • 01:13:33
    term price signals and increased cost of when
  • 01:13:36
    we commit those units. So with that, that's
  • 01:13:40
    setting the stage for tomorrow. Again, have
  • 01:13:42
    NPRR1268, NPRR1269, NPRR1270 are on the
  • 01:13:46
    consent agenda. NPRR1269 is the one
  • 01:13:48
    that we'll have ERCOT present. So TAC will
  • 01:13:51
    present, then ERCOT will present and possibly the
  • 01:13:54
    IMM and consumers will present. And those are
  • 01:13:57
    what's posted with your packet for agenda item
  • 01:14:02
    12 tomorrow. Again, we'll work with stakeholders on
  • 01:14:04
    state of charge this month. Market readiness details
  • 01:14:08
    will be available at the next meeting. I
  • 01:14:10
    would like to this is kind of a
  • 01:14:13
    policy meeting. The theme for the next meeting
  • 01:14:14
    will be the market trials and how we're
  • 01:14:16
    unpacking those with the market going forward. And
  • 01:14:18
    with that, I'll close and see if there
  • 01:14:21
    are any questions. John, do you have a
  • 01:14:23
    question? Is it fair to assume that if
  • 01:14:27
    we don't make this decision then we can't
  • 01:14:30
    go into the trials? No. We can still
  • 01:14:32
    go into trials. We can still enhance our
  • 01:14:36
    software to build these the curve logic that's
  • 01:14:39
    been reshaped. I would say that we can
  • 01:14:42
    go the first two months into trials because
  • 01:14:45
    it's mainly connectivity testing. But once we go
  • 01:14:47
    it's mainly connectivity testing. But once we go
  • 01:14:49
    into observing price formation, we'd like that in
  • 01:14:53
    the June, July timeframe, yes. So we can't
  • 01:14:56
    complete the trials? We can't complete the trials
  • 01:14:58
    without that, not without seeing something. You could
  • 01:15:01
    go blind into live, but we're trying to
  • 01:15:03
    exercise everything before we go live. Think that's
  • 01:15:06
    a good Matt, can you back up a
  • 01:15:15
    slide? So embedded in that last comment, I
  • 01:15:21
    guess is a reliability comment, correct? Yes. So
  • 01:15:27
    just wanted to confirm that one of the
  • 01:15:30
    reasons ERCOT is proposing what they're proposing is
  • 01:15:33
    to enhance reliability? Correct. And so I'll steal
  • 01:15:38
    a little bit of Keith's thunder. For example,
  • 01:15:41
    by having the AS demand curve floor in
  • 01:15:44
    there, we would see an increase of 92
  • 01:15:47
    megawatts being available to the RUC operator to
  • 01:15:49
    commit. So it's that idea of filling that
  • 01:15:51
    reliability gap of megawatts of capacity by using
  • 01:15:54
    a better price signal in the tool. Any
  • 01:16:00
    other questions? Matt, is there something we should
  • 01:16:04
    have asked that we didn't? Okay. Well, I
  • 01:16:07
    confess my one that was okay, so what
  • 01:16:10
    do I lose sleep at overnight was that
  • 01:16:12
    operating day test we just did. It's harder
  • 01:16:15
    than it looks and it worked. So that
  • 01:16:16
    was really big news. The next piece is
  • 01:16:18
    the July time frame. That's where we'll start
  • 01:16:20
    to put QUEZYS not just sending us data
  • 01:16:23
    but actually moving the resources to follow the
  • 01:16:25
    RTC telemetry signals. That will be the next
  • 01:16:28
    get to the other side of that one
  • 01:16:30
    to feel better. Now we thank you for
  • 01:16:32
    support of getting these NPRRs out. That's our
  • 01:16:34
    main need today. Okay. Thank you. If there's
  • 01:16:38
    nothing else for Matt, what I'd like to
  • 01:16:40
    do given where we are on time is
  • 01:16:42
    go ahead and pull forward a couple of
  • 01:16:43
    items, one or two items from tomorrow. The
  • 01:16:47
    first would be agenda item 14.3 system operations
  • 01:16:50
    update. Dan Woodfin was originally scheduled to do
  • 01:16:54
    that and he has graciously agreed to do
  • 01:16:59
    it today, right now. And as a heads
  • 01:17:14
    up, depending on time, we may segue to
  • 01:17:17
    agenda item 14.2 and Christy will present that
  • 01:17:20
    one once Dan's done. All right. Good afternoon.
  • Item 14.3 - System Operations Update
    01:17:24
    So I've got a few things I want
  • 01:17:26
    to share with you, kind of the normal
  • 01:17:28
    hot topics of things that are going on.
  • 01:17:31
    One is, I guess when I put this
  • 01:17:33
    together I was thinking you had already approved
  • 01:17:36
    the consent agenda tomorrow, but this actually may
  • 01:17:39
    be better because we've done some analysis of
  • 01:17:42
    some tight day that we had back in
  • 01:17:45
    November that led to the need for
  • 01:17:48
    NPRR1273. And so I'm going to
  • 01:17:51
    walk through that before you vote on it
  • 01:17:53
    as opposed to after. We've hit some records.
  • 01:17:57
    We're going to talk a little bit about
  • 01:17:58
    the February event and then talk about some
  • 01:18:01
    additional large load trips that have occurred that
  • 01:18:03
    I talked to you about back in December.
  • 01:18:08
    So on November 10, if you recall, we
  • 01:18:11
    had a pretty tight operating day. We wound
  • 01:18:13
    up releasing a lot of the reserves. On
  • 01:18:16
    that day, the state of charge of all
  • 01:18:20
    the kind of the entire fleet of batteries
  • 01:18:24
    went from nearly 93% down to 11.6% by
  • 01:18:32
    9PM after we released all the ancillary services
  • 01:18:35
    and all the batteries were leased into the
  • 01:18:38
    market. On that day, our physical responsive reserve
  • 01:18:42
    capacity, that's the amount that when we get
  • 01:18:45
    into tight conditions we monitor and once we've
  • 01:18:47
    released all the ancillary services, we monitor that
  • 01:18:50
    number to see, okay, how much reserves do
  • 01:18:54
    we really have left that's capable of withstanding
  • 01:18:57
    if a unit were to trip, do we
  • 01:18:59
    have enough to recover frequency? And so that's
  • 01:19:03
    the amount that we monitor. On that night,
  • 01:19:05
    the PRC was 6,000 some odd megawatts. But
  • 01:19:10
    what we have recognized is the when we
  • 01:19:15
    get into very tight conditions, we need to
  • 01:19:18
    always be prepared for the loss of the
  • 01:19:21
    largest unit and be able to not let
  • 01:19:23
    frequency go too low, but have it be
  • 01:19:26
    able to recover it. And so we always
  • 01:19:28
    need there's a NERC requirement that we need
  • 01:19:31
    to do whatever it takes, including load shed,
  • 01:19:34
    to maintain enough reserves so that if the
  • 01:19:36
    largest unit trips, we can recover. And we
  • 01:19:41
    don't get into uncontrolled load shed or something
  • 01:19:44
    like that. And what we've recognized is that
  • 01:19:48
    if we got into the conditions that we
  • 01:19:50
    like that, where we were out of everything
  • 01:19:54
    else, we needed to shed load in order
  • 01:19:56
    to preserve the in a controlled way, in
  • 01:20:00
    order to preserve those reserves, we would need
  • 01:20:03
    to when we order load shed, we can
  • 01:20:07
    take up to thirty minutes for that load
  • 01:20:09
    shed to occur. We need to make sure
  • 01:20:11
    that those reserves are capable of lasting at
  • 01:20:15
    least that thirty minutes plus some time to
  • 01:20:18
    actually make the operating instructions and that kind
  • 01:20:21
    of thing. So in NPRR1270, looking
  • 01:20:24
    at this event made us realize, okay, we
  • 01:20:28
    were down to where we didn't have that
  • 01:20:30
    much state of charge left. The PRC number
  • 01:20:33
    today only assumes fifteen minutes of state of
  • 01:20:38
    charge. So if you have how much you
  • 01:20:41
    have there. And so we need to change
  • 01:20:43
    that because on this day, PRC, as it's
  • 01:20:48
    calculated today with that fifteen minute duration, probably
  • 01:20:54
    wasn't a good indicator of how much how
  • 01:20:58
    close we were to needing to shed load.
  • 01:21:01
    And so we've proposed NPRR1273
  • 01:21:03
    that would increase that state of charge requirement
  • 01:21:07
    out to forty five minutes so that we're
  • 01:21:09
    counting how much PRC would be that is
  • 01:21:12
    able to sustain for long enough to give
  • 01:21:15
    us room to shed load if we were
  • 01:21:17
    to need that. And so that's really what
  • 01:21:20
    we found from analyzing that event. I use
  • 01:21:23
    this as an illustration of we're doing this
  • 01:21:25
    kind of analysis all the time on near
  • 01:21:29
    misses, things that aren't a problem, but we
  • 01:21:34
    analyze the near misses to investigate whether is
  • 01:21:39
    there something we need to change to fix
  • 01:21:42
    to make it where that near miss doesn't
  • 01:21:44
    become a problem the next time something like
  • 01:21:47
    that happens. And so in this case, we're
  • 01:21:49
    making that change. You'll have NPRR1273 before you tomorrow. When we went back
  • 01:21:51
    three before you tomorrow. When we went back
  • 01:21:55
    and recalculated the PRC for that night as
  • 01:21:59
    to what it would be under 1273, it dropped from 6,100 megawatts down by
  • 01:22:01
    2,000 megawatts. So we would still been well
  • 01:22:08
    above the level that we at which EEA
  • 01:22:11
    would be declared. But it would have been
  • 01:22:15
    significantly lower than what we were seeing that
  • 01:22:17
    night. So the next thing is March has
  • 01:22:21
    been a pretty eventful month from a renewables
  • 01:22:26
    perspective. We hit a new wind record for
  • 01:22:29
    the total amount of wind generation that we
  • 01:22:33
    saw in the system actually occurring. The amount
  • 01:22:35
    of solar that we saw being output onto
  • 01:22:40
    the system was a new record. And sometimes
  • 01:22:42
    we're not at kind of the maximum solar
  • 01:22:47
    or the maximum wind, but the combination of
  • 01:22:50
    the two is at a maximum level. And
  • 01:22:53
    so that's what's shown in the third column
  • 01:22:55
    here, this renewable column, which means that between
  • 01:22:57
    here, this renewable column, which means that between
  • 01:23:00
    solar and wind, they were generating nearly 40
  • 01:23:03
    gigawatts, which at the time was about 73%
  • 01:23:08
    of the load on the system was being
  • 01:23:11
    served by those renewables. And then the penetration
  • 01:23:16
    is that number. How much of the load
  • 01:23:19
    at that point in time was being served
  • 01:23:21
    by wind, solar, wind or solar? And what
  • 01:23:25
    you see on that kind of bottom part
  • 01:23:27
    of the table is we also hit a
  • 01:23:30
    new wind not a new wind record, that
  • 01:23:33
    was back in 2022, but a new solar
  • 01:23:36
    record of 56.6% of the load was being
  • 01:23:40
    served by solar. And then we had a
  • 01:23:42
    combined record on March 2 of over 76%
  • 01:23:47
    being served by the aggregate of the renewables.
  • 01:23:51
    So lots of new records of those types.
  • 01:23:58
    Keith talked a lot about the February event,
  • 01:24:01
    which the weather channel has called Kingston in
  • 01:24:04
    the same way they called Uri Uri. They
  • 01:24:07
    named these things. And so on February that
  • 01:24:10
    cold weather that was on February 1920, we've
  • 01:24:15
    gone back and looked at the highest net
  • 01:24:19
    load hours, the hours in which load minus
  • 01:24:24
    wind minus solar, which is really the amount
  • 01:24:27
    of load that has to be served by
  • 01:24:29
    dispatchable generation plus batteries, what were the highest
  • 01:24:33
    hours that we've ever seen? And you can
  • 01:24:36
    see the highest was back in August of
  • 01:24:39
    twenty twenty three when we were over 70.4
  • 01:24:42
    gigawatts. But this winter storm in Kingston was
  • 01:24:46
    really the highest winter hour we've seen in
  • 01:24:51
    terms of the net demand on the system
  • 01:24:54
    of a little under 70 gigawatts. And then
  • 01:25:00
    from the in fact, most of the top
  • 01:25:02
    well, the top four, five hours there have
  • 01:25:05
    all been in the summer. So it's really
  • 01:25:07
    the highest winter hour that we've seen so
  • 01:25:10
    far, including through Heather and Elliot and the
  • 01:25:14
    amount that we were served before the load
  • 01:25:17
    shed started in Erie. So that's interesting. We've
  • 01:25:26
    done that across kind of the peaks by
  • 01:25:29
    season. And there's some interesting things here. One,
  • 01:25:33
    you see the kind of the light blue
  • 01:25:35
    bar on the right shows that we have
  • 01:25:37
    seen net load growth in the last year.
  • 01:25:42
    During the summer season, you don't see a
  • 01:25:45
    lot of growth. It's pretty flat. And what
  • 01:25:48
    that means is at least during the summer
  • 01:25:51
    for peak demand conditions, the solar has kind
  • 01:25:54
    of been keeping up the solar growth has
  • 01:25:56
    been keeping up to some extent with peak
  • 01:25:59
    demand. Of course, then the sun goes down
  • 01:26:01
    and we have tight conditions in the later
  • 01:26:03
    evening, which we've talked about several times. In
  • 01:26:07
    the winter though, the growth in solar hasn't
  • 01:26:09
    been helping a lot in terms of serving
  • 01:26:12
    the net peak demand. And so you see
  • 01:26:15
    that kind of a consistent growth through the
  • 01:26:17
    years. I mean there's some up and down
  • 01:26:20
    just because of weather conditions. But we thought
  • 01:26:24
    that was interesting to share. Back in December,
  • 01:26:31
    I talked a lot about the many events
  • 01:26:34
    we've been having with due to large electronic
  • 01:26:40
    loads tripping on the system, and these are
  • 01:26:42
    primarily crypto miners, not kind of conventional data
  • 01:26:48
    centers or those kind of data centers. But
  • 01:26:53
    we've had some more since December. So these
  • 01:26:56
    continue to happen. I I kind of want
  • 01:26:58
    to keep this in front of you because
  • 01:26:59
    we have several NPRRs that are going to
  • 01:27:02
    be another kind of revision request that are
  • 01:27:04
    going to be coming before you over the
  • 01:27:06
    next few months and to try to help
  • 01:27:10
    us start to solve this problem. Our staffs
  • 01:27:14
    have been doing a lot of work with
  • 01:27:17
    across the industry with people in other areas
  • 01:27:20
    that have large data centers, with EPRI, with
  • 01:27:23
    NERC, with E cig and lots of other
  • 01:27:26
    folks trying to really the whole industry is
  • 01:27:28
    trying to understand what are the requirements that
  • 01:27:31
    would lead to these large loads tripping when
  • 01:27:34
    you have a voltage dip on the system,
  • 01:27:37
    What can we expect? How do we protect
  • 01:27:39
    against that? Does it happen when you have
  • 01:27:43
    one fault on the system? Or does it
  • 01:27:44
    take multiple faults on the system to cause
  • 01:27:46
    these loads to trip off? And so we
  • 01:27:51
    started to look at that. Just kind of
  • 01:27:52
    want to keep it before you because it
  • 01:27:54
    is coming and we're continuing to see those
  • 01:27:57
    even after what we talked about in December.
  • 01:28:02
    And all of the normal operating metrics are
  • 01:28:06
    looking good. So happy to answer any questions
  • 01:28:10
    you have. Chairman, I have a question. Go
  • 01:28:16
    ahead, Jim. So Dan, thank you for the
  • 01:28:18
    analysis, what I call the near miss, which
  • 01:28:20
    I also like to call the yellow zone.
  • 01:28:22
    So pre EEA, but some cushion. That was
  • 01:28:27
    very interesting. My question is about IBR right
  • 01:28:32
    through that we discussed last year. Are you
  • 01:28:34
    tracking those? And are those increasing or decreasing
  • 01:28:37
    in frequency? Yes. So we still see a
  • 01:28:42
    few. As part of NOGRR245,
  • 01:28:45
    I think Christy is going to talk about
  • 01:28:47
    this, right? Okay. Maybe I'll just defer that.
  • 01:28:51
    April the April was kind of a momentous
  • 01:28:54
    time for the implementation of NOGRR245.
  • 01:28:57
    So I think she's going to talk
  • 01:28:59
    about that. All right. Any other questions for
  • 01:29:03
    Dan? Dan, thanks for your report. Next, we're
  • 01:29:06
    going to move to agenda item 14.2, system
  • 01:29:09
    planning and weatherization update. Christie Hobbs is our
  • 01:29:12
    presenter. All right. Good afternoon board members. So
  • Item 14.2 - System Planning and Weatherization Update
    01:29:27
    take you to through our normal system planning
  • 01:29:31
    and weatherization update. I threw in a few
  • 01:29:33
    extra slides this time, given this is the
  • 01:29:35
    first time that the board is going to
  • 01:29:36
    hear all of this material. But then some
  • 01:29:39
    of them, I'll just move into the appendix
  • 01:29:41
    as we go forward. But did want to
  • 01:29:42
    make sure you have a good baseline as
  • 01:29:44
    we start off. All right. So as Dan
  • 01:29:55
    alluded to he stole my thunder, no. NOGRR
  • 01:30:00
    245, which you recall a lot
  • 01:30:02
    of debate and discussion last year at the
  • 01:30:04
    board was ultimately approved by the commission and
  • 01:30:07
    went into effect as our rules as of
  • 01:30:11
    October first of last year. And so just
  • 01:30:14
    as a reminder, what NOGRR245
  • 01:30:17
    does is it put in place requirements for
  • 01:30:20
    all existing as well as some of the
  • 01:30:23
    new or all the new IVRs, so wind,
  • 01:30:27
    solar, coming to the system to be able
  • 01:30:30
    to maximize or have a certain level of
  • 01:30:33
    voltage ride through requirements. And so, by December
  • 01:30:41
    1, later this year, they have to have
  • 01:30:45
    requirements for implementing quick changes that they can
  • 01:30:48
    make to their settings, their parameters, or software,
  • 01:30:53
    some of their firmware modifications to get to
  • 01:30:55
    a set of standards to improve those ride
  • 01:30:57
    through capabilities. So, those resources that were currently
  • 01:31:01
    on the system and had signed agreements by
  • 01:31:04
    August first of last year. They have to
  • 01:31:09
    at least meet legacy voltage ride through requirements
  • 01:31:12
    and frequency ride through requirements. And then they
  • 01:31:16
    have an opportunity, which we had this April
  • 01:31:18
    1 deadline, where they can either request an
  • 01:31:21
    extension for compliance with that December 31 deadline,
  • 01:31:25
    or they can request an exemption, meaning maybe
  • 01:31:28
    they have some older equipment that just cannot
  • 01:31:30
    be updated to meet those requirements. For those
  • 01:31:35
    newer resources that were currently in our generation
  • 01:31:38
    interconnection queue and moving forward, they had the
  • 01:31:42
    ability, if they wanted to request an extension
  • 01:31:46
    to comply with certain requirements. So I'm gonna
  • 01:31:48
    walk you through kind of what those two
  • 01:31:52
    parameters are for extensions and exemptions. And then
  • 01:31:55
    I've got some initials, early stats. Again, we
  • 01:31:59
    just got all of those requests in last
  • 01:32:02
    week. We're still going through the data quality
  • 01:32:05
    of what we received, but I've got some
  • 01:32:07
    high level stats to share with you. Alright,
  • 01:32:10
    so what is our review process? So, if
  • 01:32:14
    an entity requests an exemption from the rule,
  • 01:32:17
    we've got to take a look and make
  • 01:32:19
    sure that that exemption is not going to
  • 01:32:21
    have a reliability impact on the system. And
  • 01:32:24
    so, ERCOT will perform studies to see what
  • 01:32:28
    that reliability impact is from that exemption. So
  • 01:32:31
    what we're currently going through the process is
  • 01:32:34
    to see if the information provided to us
  • 01:32:36
    was complete, as well as trying to define
  • 01:32:40
    what our scope is for moving forward for
  • 01:32:43
    those exemption studies. So as you can imagine,
  • 01:32:46
    we may have a set of IVRs that
  • 01:32:48
    are clustered together. So we may define part
  • 01:32:51
    of our scope to look at that part
  • 01:32:52
    of the system where they're all clustered together
  • 01:32:54
    and impact to the system. So, those are
  • 01:32:56
    some of the things that we're going to
  • 01:32:57
    be working through this summer. And, we'll start
  • 01:33:00
    our exemption studies, reliability assessment studies in the
  • 01:33:05
    fall with the goal of having responses back
  • 01:33:08
    on whether or not those extensions can move
  • 01:33:10
    forward in the November, early December timeframe. Now
  • 01:33:15
    from an extension process, ERCOT's got to review
  • 01:33:20
    the request for extensions as soon as practical.
  • 01:33:24
    So the team is going through those right
  • 01:33:25
    now. We've started that process. If their information
  • 01:33:28
    is not complete, they have ten business days
  • 01:33:31
    to update and improve the quality of the
  • 01:33:34
    information they provided us. Once their requests are
  • 01:33:37
    complete, we've got seven days to put an
  • 01:33:40
    accountable senior representative on that request. We've got
  • 01:33:46
    a hundred and eighty days to make a
  • 01:33:47
    decision. We may request longer if we need
  • 01:33:50
    additional time to review. And then we have
  • 01:33:54
    to notify the market participant of the decision.
  • 01:33:56
    Those decisions can be appealed up to the
  • 01:33:59
    commission if the market participant disagrees with the
  • 01:34:03
    outcome of our decision. So what did we
  • 01:34:08
    see? I will say that I was very
  • 01:34:10
    pleased with the responses that we got back.
  • 01:34:12
    Again, we're still digging into the quality. But
  • 01:34:15
    for those current resources, we sent requests for
  • 01:34:18
    information to seven ninety five resources that are
  • 01:34:22
    in our network operations model. We received seven
  • 01:34:26
    sixty five response back. And of those, 60%
  • 01:34:32
    said they will be able to maximize their
  • 01:34:35
    ride through capabilities by December thirty first of
  • 01:34:37
    this year. We're still trying to work to
  • 01:34:39
    tell you how many megawatts that is, but
  • 01:34:42
    was very pleased to see that level of
  • 01:34:44
    response back. Of those, we had two zero
  • 01:34:48
    five that requested an extension. So they would
  • 01:34:51
    like to go they would like to comply,
  • 01:34:54
    but they're saying it's gonna take them longer
  • 01:34:55
    than December 31 to be able to comply.
  • 01:34:59
    We had 28 that gave us a notice
  • 01:35:02
    of intent to request an exemption so that
  • 01:35:05
    they can they're saying they can't meet those
  • 01:35:08
    standards. We had 59 that requested both an
  • 01:35:12
    extension or an exemption. The reason that we
  • 01:35:15
    saw that is that the protocols were very
  • 01:35:17
    clear. You had to make that request for
  • 01:35:20
    either or by that date. And if they
  • 01:35:22
    know that one may not be granted, meaning
  • 01:35:25
    their exemption may not be granted, then they
  • 01:35:27
    might need time for an extension. So they
  • 01:35:29
    requested both to make sure their bases were
  • 01:35:32
    covered. There were 30 that did respond. As
  • 01:35:36
    we started reviewing through those and how do
  • 01:35:38
    we reconcile and how do we continue moving
  • 01:35:39
    forward, we took a look and we sent
  • 01:35:41
    a market notice on Friday. We actually extended
  • 01:35:44
    for ten business days to be able to
  • 01:35:47
    respond to get those requests in. We felt
  • 01:35:50
    that was consistent with the other provisions that
  • 01:35:54
    say if your application's not complete, you have
  • 01:35:56
    ten business days to complete that. So we're
  • 01:35:59
    trying to get that additional information in to
  • 01:36:01
    get those final responses in. So for those
  • 01:36:05
    new interconnecting entities or resources that are in
  • 01:36:08
    those early stages, meaning they're just going or
  • 01:36:10
    finalizing going through the generation interconnection queue, they
  • 01:36:14
    only had to respond if they wanted to
  • 01:36:16
    ask for an extension or a notice of
  • 01:36:19
    an intent for an exemption. We received a
  • 01:36:22
    hundred and four responses from those new resources.
  • 01:36:27
    85 of them said that they received said
  • 01:36:32
    they can maximize by December 31. '13 requested
  • 01:36:36
    an extension. Five requested a notice and intent
  • 01:36:40
    for an exemption, and one provided both an
  • 01:36:43
    extension and exemption request. So overall, we're pleased
  • 01:36:48
    with the responses that we received. The teams
  • 01:36:52
    are working right now again to do the
  • 01:36:54
    due diligence to go through the quality of
  • 01:36:56
    the data, but we will continue to provide
  • 01:36:59
    updates as we have more detail what's behind
  • 01:37:02
    those requests and as we move through the
  • 01:37:04
    study and exemption request reliability assessment process. Alright,
  • 01:37:12
    Texas Energy Fund. This was one of the
  • 01:37:15
    updated slides in your deck provided on Friday.
  • 01:37:19
    And because of some of the changes that
  • 01:37:20
    we've seen happening at the commission, we wanted
  • 01:37:24
    to get you the most current stats. So
  • 01:37:25
    we're currently tracking the 16 projects that are
  • 01:37:29
    going through due diligence at the commission. Those
  • 01:37:31
    account for about 8,000 megawatts of new gas
  • 01:37:37
    generation on the system. What you'll see is
  • 01:37:40
    that all of them have submitted their full
  • 01:37:42
    interconnection study applications with ERCOT, and they're advancing
  • 01:37:46
    through. Seven have actually completed those full interconnection
  • 01:37:50
    study processes. So moving forward, a lot of
  • 01:37:54
    progress on those. Now the overall generation interconnection
  • 01:38:00
    queue. We're tracking just under 2,000 new generation
  • 01:38:04
    interconnection requests in the market. So as we
  • 01:38:08
    talked about in finance and audit, a number
  • 01:38:12
    of requests that we're working with new entities
  • 01:38:15
    as well as the transmission service providers to
  • 01:38:18
    try to process those megawatts that want to
  • 01:38:20
    come to the system. It's about 400 gigawatts.
  • 01:38:23
    We recognize that not all of that will
  • 01:38:25
    materialize, but it is a lot of work
  • 01:38:27
    to process the studies and work them through
  • 01:38:30
    the process. Again, solar and battery energy storage
  • 01:38:33
    continue to account for well over the majority
  • 01:38:36
    of what we're tracking and the interest we're
  • 01:38:39
    seeing coming into the market. Now, our current
  • 01:38:43
    large load interconnection queue. We have surpassed the
  • 01:38:50
    100 gigawatt mark of large loads request to
  • 01:38:54
    enter into the market. We're tracking about 108,000
  • 01:38:59
    megawatts of large loads. That's compared to in
  • 01:39:03
    December when I reported to you about 63,000.
  • 01:39:06
    So you see we've almost doubled in the
  • 01:39:08
    amount of large loads that are seeking to
  • 01:39:11
    enter into the process. One of the things
  • 01:39:13
    I did want to highlight, again kind of
  • 01:39:15
    like Dan, there's an important NPRR and PGRR
  • 01:39:18
    that are coming before you tomorrow on the
  • 01:39:20
    consent agenda that has to do with the
  • 01:39:22
    large load interconnection process. So just as a
  • 01:39:26
    reminder, we have been working in an interim
  • 01:39:28
    process for well over the last two years.
  • 01:39:31
    When we started that process, we had about
  • 01:39:33
    2,000 megawatts of large loads in interconnection queue.
  • 01:39:37
    We're now well over 100. So it's very
  • 01:39:39
    important that we get these rules established and
  • 01:39:41
    codified in the protocols. Some of the key
  • 01:39:45
    things I'll just highlight why it's important that
  • 01:39:47
    we continue moving this forward. It adds the
  • 01:39:51
    official definition of what a large load is.
  • 01:39:54
    It helps provide ERCOT visibility and situational awareness
  • 01:39:58
    for those large loads that are 25 megawatts
  • 01:40:01
    and greater. Why is this important? You know,
  • 01:40:04
    we've been through some previous winter storms, we
  • 01:40:06
    get questions. Are those large loads on? Have
  • 01:40:08
    they turned off? And as we start to
  • 01:40:10
    get additional data points, that helps us with
  • 01:40:12
    our forecasting as we go forward once we
  • 01:40:15
    start to see the behavior of these large
  • 01:40:17
    loads. It specifically defines those timelines and processes
  • 01:40:22
    for the interconnection studies and the requirements that
  • 01:40:24
    go with connecting. It provides certainty into that
  • 01:40:28
    process. It also allows us to update some
  • 01:40:31
    of our tools so we can get better
  • 01:40:33
    visibility into the transmission service providers so they
  • 01:40:36
    know where things are in the process, what
  • 01:40:38
    needs their attention, what needs additional approval, and
  • 01:40:41
    how we continue to move those through. There
  • 01:40:44
    have been some questions as it's made its
  • 01:40:47
    final tracks through the stakeholder process. How does
  • 01:40:51
    this align with Senate Bill six that's currently
  • 01:40:54
    in process? And from our initial review of
  • 01:40:56
    where SB six sits today, There are no
  • 01:40:59
    issues. They just complement each other. If there
  • 01:41:02
    are additional changes, we can always come back
  • 01:41:05
    and adjust the rules just like we always
  • 01:41:07
    do to align if there are changes that
  • 01:41:09
    are needed down the road. So those large
  • 01:41:14
    loads that we've already studied and given the
  • 01:41:17
    approval to energize and move through, what have
  • 01:41:19
    we observed? There's about 6,300 megawatts that have
  • 01:41:24
    been improved to energize. What we've observed as
  • 01:41:27
    at any simultaneous point, the most we've seen
  • 01:41:31
    on is about 3,300. Now that means they
  • 01:41:34
    could be on at different times. It may
  • 01:41:36
    mean it's a new large load that's ramping
  • 01:41:39
    up their operations and they're ramping into their
  • 01:41:41
    full amount. But we'll continue to update you
  • 01:41:44
    on what we've seen in the Q. So
  • 01:41:49
    we've talked about loads, we've talked about generation,
  • 01:41:51
    we've got to have a good transmission plan
  • 01:41:54
    to make sure that we can connect the
  • 01:41:56
    two together so they can operate efficiently. This
  • 01:41:58
    is typically a slide that I put in
  • 01:42:00
    the appendix just to keep you aware. Christy,
  • 01:42:02
    can I just ask a question on the
  • 01:42:03
    last topic? I think it'd be helpful for
  • 01:42:05
    the board if you could at least categorize
  • 01:42:08
    the types of large loads that you're seeing,
  • 01:42:11
    whether they're data centers, industrial, hydrogen plants, LP,
  • 01:42:18
    gas, etcetera, just because I think part just
  • 01:42:22
    triggering off your last comment, part of this
  • 01:42:24
    is because each one of those might have
  • 01:42:26
    somewhat And then we'll question. And represent that
  • 01:42:40
    for you. All right, from a transmission planning,
  • 01:42:44
    really there are a lot of words on
  • 01:42:46
    this slide, but what a key takeaway I'd
  • 01:42:48
    like you to have is really by looking
  • 01:42:50
    at that graph. So the number of projects
  • 01:42:53
    that come through to you and you're considering
  • 01:42:55
    we're recommending for endorsement moving forward, as you
  • 01:42:58
    can see over the last several years that's
  • 01:43:00
    continued to increase. I mean in fact in
  • 01:43:03
    2023 there was $3,200,000,000 endorsed, 2024, dollars '3
  • 01:43:09
    point '7 excuse me, 3,800,000,000.0. So, we're continuing
  • 01:43:14
    to see the need for investment to meet
  • 01:43:17
    both growing load as well as where generations
  • 01:43:20
    being and connecting the two. We've done a
  • 01:43:25
    lot of talk about the Permian Basin transmission
  • 01:43:29
    plan. Just a little bit of history for
  • 01:43:32
    board members that are new. This was something
  • 01:43:35
    that came out of HB5066. The commission directed
  • 01:43:38
    us in December of twenty twenty three to
  • 01:43:41
    do a transmission reliability plan study for the
  • 01:43:44
    Permian Basin and looking at the incredible load
  • 01:43:47
    growth in that area. We made a recommendation
  • 01:43:50
    to the commission in July of twenty twenty
  • 01:43:52
    four. And because of what we saw in
  • 01:43:54
    the increased load growth in that region, but
  • 01:43:58
    the lack of conventional generation in that area
  • 01:44:01
    was the need for import pass to move
  • 01:44:05
    power into the region. And we provided the
  • 01:44:07
    commission two options, one at the current import
  • 01:44:10
    level of three forty five kb and the
  • 01:44:13
    second was using going to a higher voltage
  • 01:44:15
    of seven sixty five. The commission continued through
  • 01:44:19
    their due diligence. We provided our statewide kind
  • 01:44:22
    of overview of what we saw progressing through
  • 01:44:24
    the state. They've been taking a lot of
  • 01:44:27
    time to take comments and questions from the
  • 01:44:30
    stakeholders as they review and make a decision.
  • 01:44:32
    They're due to make a decision at their
  • 01:44:34
    April 24 open meeting on those import paths.
  • 01:44:38
    Now back in July of last year when
  • 01:44:42
    we put our recommendation out for those options,
  • 01:44:45
    when we do a transmission plan we typically
  • 01:44:48
    go out to the transmission service providers and
  • 01:44:50
    get cost estimates on what it's gonna cost
  • 01:44:53
    to build those lines. We got those updates
  • 01:44:56
    in May of twenty twenty four last year
  • 01:44:59
    for the March. But because there were limited
  • 01:45:03
    TSPs that had experience in building at that
  • 01:45:06
    time of July, we chose to use a
  • 01:45:09
    generic MISO estimate for Texas on the cost
  • 01:45:14
    estimate for the seven sixty five lines. When
  • 01:45:17
    the commission approved their order last September, they
  • 01:45:20
    told the TSPs to start working on both
  • 01:45:23
    so that they'd be ready to move forward
  • 01:45:25
    when a decision was made. Because of that,
  • 01:45:27
    the transmission service providers started working with vendors,
  • 01:45:30
    and they've got a lot more experience and
  • 01:45:32
    exposure now to what cost to expect. So
  • 01:45:35
    we recently filed with the commission an update
  • 01:45:38
    on cost. What we saw was if you
  • 01:45:41
    look at the three forty five import paths,
  • 01:45:44
    what we saw was several of the TSPs
  • 01:45:48
    provided cost estimates. Several told us their cost
  • 01:45:50
    wouldn't change for three forty five. So overall,
  • 01:45:53
    we saw their cost increase from last year's
  • 01:45:56
    estimates by 7.6%. For the seven sixty five
  • 01:46:00
    comparing to the generic MISO estimates once we
  • 01:46:04
    put more granularity to it, Again, fast forward
  • 01:46:07
    a lot has changed in the last year
  • 01:46:10
    with as it relates to cost. We saw
  • 01:46:13
    the July plan increase by 11.6%. End of
  • 01:46:18
    the day, we recognize it's going to be
  • 01:46:20
    an investment for the consumers to be able
  • 01:46:22
    to get the transmission built that they need.
  • 01:46:25
    But the cost estimates came in still fairly
  • 01:46:29
    close to each other. These numbers just look
  • 01:46:33
    at the cost. They don't I don't have
  • 01:46:35
    the information here, but if you're interested later
  • 01:46:37
    in going into, I can definitely get you
  • 01:46:39
    that additional information we've continued to share about
  • 01:46:42
    the future benefits of one versus the other
  • 01:46:45
    and how they compare. One additional piece of
  • 01:46:50
    information we provided to the commission last week
  • 01:46:52
    is we've often said that we feel like
  • 01:46:55
    our current transmission system has maximized its capability,
  • 01:46:59
    meaning we have squeezed all we can out
  • 01:47:02
    of the current transmission system. And so, one
  • 01:47:04
    of the ways that we were able to
  • 01:47:06
    try to quantify and put numbers to that
  • 01:47:09
    is Dan's team actually helped me out. They
  • 01:47:11
    pulled information from our outage coordination system and
  • 01:47:14
    looked at over the past decade the number
  • 01:47:17
    of transmission outages on the three forty five
  • 01:47:19
    system that we have worked with the transmission
  • 01:47:22
    service providers for either them to withdraw it
  • 01:47:26
    or we've had to reject their request. And
  • 01:47:29
    the reason is, is when they put those
  • 01:47:31
    requests in, we have to look at system
  • 01:47:32
    conditions and whether or not the transmission system
  • 01:47:35
    would remain secure. And because of how we've
  • 01:47:39
    seen the grid evolved, it's becoming increasingly more
  • 01:47:42
    difficult to take outages on that three forty
  • 01:47:44
    five system. Again, either way, there's more transmission
  • 01:47:49
    capability that's needed. But this is just a
  • 01:47:52
    way to kind of share how that's evolved
  • 01:47:54
    over time. Is this load based? This load
  • 01:47:59
    based, Christy? Is that what happened in 2020,
  • 01:48:01
    the load went up significantly? It's load. You're
  • 01:48:07
    seeing load increases. You're also seeing maybe different
  • 01:48:10
    outages. So if a resource is taking an
  • 01:48:13
    outage, it impacts the power flow of the
  • 01:48:16
    system. And so a requested transmission outage may
  • 01:48:21
    have to be canceled or moved to be
  • 01:48:24
    able to accommodate those outages on the system
  • 01:48:27
    as well. So it's a combination. Yeah. I'd
  • 01:48:32
    also add that when those outages are withdrawn
  • 01:48:35
    or rejected, they're put back in again And
  • 01:48:39
    they're still taking because you still have to
  • 01:48:40
    do the maintenance on the line, but they're
  • 01:48:42
    done at a they're either done hot or
  • 01:48:44
    they're done with shorter restoration time, which is
  • 01:48:47
    a more expensive way of performing the maintenance
  • 01:48:51
    work. So ultimately, when that graph rises, that's
  • 01:48:55
    a higher cost to take those outages to
  • 01:48:58
    consumers. All right. We've wrapped up the winter
  • 01:49:06
    weatherization season. We've closed out the season doing
  • 01:49:10
    four sixty inspections. That was our fourth winter
  • 01:49:14
    season to complete the inspections of the generation
  • 01:49:18
    and transmission fleet. We continue to see good
  • 01:49:22
    results from the performance of units. You heard
  • 01:49:27
    from Dan and Keith earlier about those winter
  • 01:49:29
    storms. What we observed was very limited impact
  • 01:49:33
    to thermal outages on the systems during those
  • 01:49:36
    timeframes. So we will continue working with providers
  • 01:49:39
    to keep that information in front of them
  • 01:49:42
    as we go into each season so that
  • 01:49:45
    everyone is prepared to the best of their
  • 01:49:47
    ability to meet those standards for whatever weather
  • 01:49:50
    we're impacted by. Then last but not least,
  • 01:49:54
    our monthly outlook on resource adequacy. Right here
  • 01:49:57
    I've got April and May. We actually also
  • 01:50:00
    put out on Friday our June moron. And
  • 01:50:03
    what you consistently see is we do a
  • 01:50:06
    set of probabilistic runs to look at the
  • 01:50:08
    potential for going into an emergency type event
  • 01:50:12
    under various conditions. And what we consistently see
  • 01:50:16
    is in those evening hours as the sun
  • 01:50:18
    starts setting, that's where we see our risk
  • 01:50:21
    of a potential emergency type conditions. But what
  • 01:50:24
    you see highlighted here is those percentages are
  • 01:50:27
    very low. And the reason that we're seeing
  • 01:50:29
    those decrease from what we observed last year
  • 01:50:32
    is we're continuing to see more batteries added
  • 01:50:34
    to the system, and that helps to provide
  • 01:50:38
    more coverage in those shorter duration type events.
  • 01:50:42
    The June number is also the highest risk
  • 01:50:45
    is the hour ending nine p. M. And
  • 01:50:46
    it's less than one percent as well. I
  • 01:50:50
    think it's zero point three five percent at
  • 01:50:52
    that nine hour. Thank you, Christi. Any questions
  • 01:50:59
    for Christi? Julie? I'd like to go back
  • 01:51:01
    to my question. I appreciate Christi's presentation on
  • 01:51:04
    the NOGRR245 implementation. It's good
  • 01:51:07
    to see the response from the market participants.
  • 01:51:10
    But my question was, are we tracking the
  • 01:51:13
    IBR write through event and what does that
  • 01:51:15
    trend look like? Is Christy tracking it? Is
  • 01:51:20
    Dan tracking it? Yes, we're looking at that.
  • 01:51:26
    We've got folks that look at that all
  • 01:51:28
    the time. I just don't have the numbers
  • 01:51:30
    in front of me, but I can get
  • 01:51:31
    them for you by tomorrow. But is your
  • 01:51:33
    sense It's they're still occurring, yes. Okay. We're
  • 01:51:39
    hoping that this maximization cuts that number. Yes,
  • 01:51:44
    but it looks like we've got over a
  • 01:51:46
    year to actually implement it. So that's why
  • 01:51:49
    I was like curious about the current state
  • 01:51:51
    of IBR events. Yes, I'll get you those
  • 01:51:56
    kind of the volume numbers tomorrow. Yes, that'd
  • 01:51:59
    be great. Any other questions for Christy or
  • 01:52:03
    Yes, Mr. Chairman, just really quickly. Christy, on
  • 01:52:06
    the Permian Basin reliability plan, what is the
  • 01:52:11
    difference in transfer capability between the July import
  • 01:52:15
    plan and the March? Do you know approximately?
  • 01:52:18
    So it's approximately and the reason I know
  • 01:52:21
    this number is because it's July which is
  • 01:52:24
    easy to remember. I think it's in our
  • 01:52:29
    if I go back to report, I actually
  • 01:52:30
    have it in my bag if we want
  • 01:52:32
    to pull out specifics. But when we did
  • 01:52:34
    the Permian study, we looked at for both
  • 01:52:37
    plans, the March plan and the July plan,
  • 01:52:41
    we looked at, okay, you serve the current
  • 01:52:43
    demand by having these additional import pass in,
  • 01:52:47
    how much more capacity could we serve? So
  • 01:52:51
    the way the power flows. What we saw
  • 01:52:54
    was higher for the seven sixty five by
  • 01:52:58
    seven sixty five megawatts in comparison. So again,
  • 01:53:03
    it doesn't go line by line. It looks
  • 01:53:04
    at the total through the power flow analysis
  • 01:53:07
    and with the three seven sixty five lines
  • 01:53:09
    because they have lower impedance, power more power
  • 01:53:13
    can flow over them into the region. Okay.
  • 01:53:16
    Thank you. Any other questions or comments? Christie,
  • 01:53:24
    thank you. There are any objections, this will
  • 01:53:28
    conclude the general session for today. Our meeting
  • 01:53:31
    will resume in general session at webcast will
  • 01:53:37
    be suspended. Chairman Gleason? This meeting, the Public
  • 01:53:39
    Utility Commission of Texas is adjourned. All right,
  • 01:54:19
    we're going. Good morning members of the ERCOT
  • 01:54:22
    Board of Directors and guests. I'm Bill Flores,
  • 01:54:24
    ERCOT Board Chair. I hereby reconvene and call
  • 01:54:27
    to order the April 7 and April 8
  • 01:54:29
    meeting of the ERCOT Board of Directors. As
  • 01:54:31
    a reminder, this meeting is being webcast live
  • 01:54:34
    to the public on ERCOT's website. Before we
  • 01:54:37
    get going, I'd like to provide PUC Chairman,
  • 01:54:39
    Thomas Gleeson, an opportunity to reconvene the open
  • 01:54:41
    meeting of the Public Utility Commission of Texas.
  • 01:54:44
    Thank you, Mr. Chairman. This meeting of the
  • 01:54:45
    Public Utility Commission of Texas will come to
  • 01:54:47
    order to consider matters that have been duly
  • 01:54:49
    posted with the Secretary of State for 04/08/2025.
  • 01:54:52
    Thank you, Chair Gleason. Before moving on today's
  • 01:54:55
    business, again, the antitrust admonition and the security
  • 01:54:58
    map are each included in the posted meeting
  • 01:55:01
    materials. Chad, just to confirm, has anyone from
  • 01:55:04
    the public expressed interest in commenting today on
  • 01:55:08
    any items? No. Okay. Thank you, Chad. We're
  • Item 6 - Consent Agenda
    01:55:12
    going to start with agenda item six, the
  • 01:55:15
    consent agenda, including item 6.1 unopposed revision request
  • 01:55:19
    recommended by TAC for approval. Chad, please proceed
  • 01:55:22
    with providing budget impacts request. Thank you, Chair.
  • Item 6.1 - Unopposed Revision Requests Recommended by TAC for Approval
    01:55:27
    There are 12 revision requests on the consent
  • 01:55:30
    agenda. A couple were discussed yesterday during the
  • 01:55:34
    first part of our board meeting in the
  • 01:55:36
    afternoon. Several of them do have budgetary impacts
  • 01:55:41
    and FTE impacts. Specifically I would note NPRR1234
  • 01:55:45
    which deals with large loads
  • 01:55:48
    has a budget impact between $600,000 and $800,000
  • 01:55:53
    and some annual reoccurring O and M staffing
  • 01:55:56
    costs. It also has a FTE impact of
  • 01:55:59
    10.7 employees to incorporate that across multiple divisions
  • 01:56:04
    within the organization. A couple of other revision
  • 01:56:07
    requests twelve fifty has a budget impact between
  • 01:56:10
    25,000 and 50,000. NPRR1268 does
  • 01:56:16
    not have any budgeting impact that's an RTC
  • 01:56:19
    one along with NPRR1270. And then two
  • 01:56:22
    other revision requests which is SCR829
  • 01:56:25
    nine and VCMRR042 have budget impacts between
  • 01:56:32
    100,000 and 200,000. Happy to answer any questions.
  • 01:56:37
    Are there any question for Chad on any
  • 01:56:40
    of the unanimously approved NPRRs? If there's no
  • 01:56:45
    further discussion, I'll entertain a motion to approve
  • 01:56:47
    the consent agenda as presented. So moved. Okay,
  • 01:56:51
    thank you Julie. Thank you, Peggy. All in
  • 01:56:55
    favor? Aye. Aye. Any opposed? Any abstentions? The
  • 01:56:59
    consent agenda is unanimously approved. Next is agenda
  • Item 7 - General Session Meeting Minutes
    01:57:03
    item seven, the general session meeting minutes including
  • Item 7.1 - February 4, 2025 General Session Meeting Minutes
    01:57:06
    item 7.1, the 02/04/2025 general session meeting minutes
  • Item 7.2 - February 25, 2025 General Session Special Meeting Minutes
    01:57:11
    and item 7.2, the 02/25/2025 general session special
  • 01:57:17
    meeting minutes. There are drafts in the meeting
  • 01:57:19
    materials would any board member like to discuss?
  • 01:57:22
    If not, I'll entertain a motion to approve
  • 01:57:25
    the 02/04/2025 general session meeting minutes and the
  • 01:57:29
    February 25 general session special meeting minutes. Thank
  • 01:57:33
    you, John. And a second from Peggy. Thank
  • 01:57:37
    you. All in favor? Aye. Any opposed? Any
  • 01:57:41
    abstentions? Both sets of meeting minutes are unanimously
  • 01:57:44
    approved. We're now going to move to agenda
  • 01:57:47
    item eight and ERCOT CEO Pablo Viegas is
  • 01:57:50
    our first presenter today presenting agenda item eight,
  • 01:57:54
    the CEO update. Pablo, the floor is yours.
  • Item 8 - CEO Update
    01:57:56
    Thanks. Thank you, Chair Flores. Appreciate it. Thank
  • 01:57:59
    you all for your time today and your
  • 01:58:02
    commitment to the important work that we're doing
  • 01:58:04
    here at ERCOT. Today, I am going to
  • 01:58:08
    cover a few topics related to kind of
  • 01:58:10
    where we are seasonally. We're in the shoulder
  • 01:58:12
    month of spring. I'm going talk a little
  • 01:58:14
    bit about what that means and kind of
  • 01:58:15
    what are some of the typical communications that
  • 01:58:19
    the market sees as a result of us
  • 01:58:21
    being in a shoulder month. Then I'll cover
  • 01:58:24
    briefly a brief update on what's going on
  • 01:58:26
    with Braunig Unit three, the latest information that
  • 01:58:29
    we have on the inspection and repair work
  • 01:58:31
    that's happening there, followed by an update on
  • 01:58:34
    where we are with the life cycle, mobile
  • 01:58:37
    generator, transition from the Houston area over to
  • 01:58:41
    the San Antonio area as part of the
  • 01:58:44
    RMR mitigation solution. And then talk about a
  • 01:58:49
    couple of activities and external events that we're
  • 01:58:51
    going to be doing. And so some really
  • 01:58:54
    important external stakeholder opportunities coming up in the
  • 01:58:58
    next couple of months that I think are
  • 01:58:59
    going to be very valuable for for participants.
  • 01:59:03
    So starting off with kind of the shoulder
  • 01:59:05
    season scheduled maintenance period. So during this period
  • 01:59:09
    of time, this is when the generators in
  • 01:59:12
    the system, and this is really all generators,
  • 01:59:14
    the renewables as well as the thermal generators,
  • 01:59:18
    take the opportunity during the kind of more
  • 01:59:20
    moderate weather to take outages, do maintenance, plan
  • 01:59:23
    maintenance. And we are seeing that going on.
  • 01:59:25
    It's a really critical cycle for the, for
  • 01:59:28
    any grid, and it's super critical here as
  • 01:59:30
    well because we know during the extremes of
  • 01:59:32
    summer and the peaks in the winter, we
  • 01:59:34
    need all of these resources to be able
  • 01:59:36
    to be contributing. And so what it looks
  • 01:59:38
    like at a time like this, I checked
  • 01:59:40
    today's numbers on our outages. Today, we have
  • 01:59:43
    about 38,800 megawatts of resources that are out
  • 01:59:49
    on maintenance right now. The large majority of
  • 01:59:52
    that is planned. There are some forced outages
  • 01:59:56
    as there always is, you know, around the
  • 01:59:58
    clock, but that's not an unusual level of
  • 02:00:00
    outages to have on a beautiful April day
  • 02:00:03
    like we have today. We have not had
  • 02:00:07
    an issue with limiting scheduled maintenance outages on
  • 02:00:10
    the generator side this season. Those have been
  • 02:00:12
    able to proceed as necessary. We are continuing,
  • 02:00:15
    though, seasonally year after year, seeing challenges with
  • 02:00:18
    always taking the transmission level outages at the
  • 02:00:21
    times and at the durations that they are
  • 02:00:23
    requested. And we have had to move around
  • 02:00:25
    those transmission outages periodically in order to manage
  • 02:00:29
    local reliability or congestion issues. But we try
  • 02:00:33
    not to do that to the extent possible.
  • 02:00:36
    So this is the period of time we
  • 02:00:37
    experience. It's in the spring from March 15
  • 02:00:39
    through May 15. In the fall, September 15
  • 02:00:42
    through December 15, we take these periods of
  • 02:00:44
    time to make sure that the fleet can
  • 02:00:46
    be, reliably, maintenance in order to continue operating
  • 02:00:50
    during the peak seasons. A couple of things
  • 02:00:54
    that we do during the these periods that
  • 02:00:57
    are more common in the shoulder periods. One
  • 02:01:00
    of them is advanced action notices. An advanced
  • 02:01:03
    action notice is essentially us seeing a condition
  • 02:01:06
    coming on the grid based on could be
  • 02:01:09
    a variety of factors. It could be a
  • 02:01:12
    change in the weather forecast. We could see
  • 02:01:14
    an unseasonably warm day all of a sudden,
  • 02:01:17
    happen in the spring or in the fall.
  • 02:01:19
    And, or we may see, you know, a
  • 02:01:21
    combination of, you know, a change expected renewable
  • 02:01:24
    output or because of the amount of forced
  • 02:01:26
    outages that were on top of the planned
  • 02:01:28
    outages. We just have a different condition and
  • 02:01:30
    and different circumstance evolving on the grid. And
  • 02:01:33
    so we communicate an advanced action notice to
  • 02:01:36
    the market, letting them know that we may
  • 02:01:38
    need to make changes and move planned or
  • 02:01:41
    scheduled outages around either the generation or the
  • 02:01:44
    transmission system. Some of the things that we
  • 02:01:47
    can do, as part of an AAN include
  • 02:01:49
    adjusting the actual outage schedule, reducing the outage
  • 02:01:53
    restoration time, saying, hey, we're gonna need to
  • 02:01:55
    have the ability to bring something back a
  • 02:01:57
    little bit sooner if these conditions materialize as
  • 02:02:00
    we are seeing the possibility of, Or if
  • 02:02:04
    we can adjust the system configuration in some
  • 02:02:06
    way in order to route the topology in
  • 02:02:09
    a way that can manage that risk, that's
  • 02:02:11
    something that we would look to do if
  • 02:02:13
    we can avoid having to change the schedules.
  • 02:02:17
    As you can see, we look we brought
  • 02:02:19
    some data from the last few springs, have
  • 02:02:21
    had more AANs with associated megawatts in prior
  • 02:02:25
    years. This spring, we really haven't had any
  • 02:02:27
    as of the start of this month, but
  • 02:02:29
    that could change as we continue the season
  • 02:02:32
    into April and into May and early June.
  • 02:02:35
    We definitely have had to be stricter in
  • 02:02:38
    managing these maintenance outages as the kind of
  • 02:02:41
    the tightness of the grid overall continues to
  • 02:02:47
    grow as we see the growth on the
  • 02:02:49
    system, we see growth on the demand. And
  • 02:02:51
    so we're going to have to be very
  • 02:02:52
    careful with these outages and managing those very
  • 02:02:54
    closely. And the market participants that have been
  • 02:02:57
    on the other side of these AANs understand
  • 02:02:58
    that very well. But just wanted to let
  • 02:03:00
    you know, this is one of the core
  • 02:03:01
    tools we use. It's primarily during these shoulder
  • 02:03:04
    months that we use them, and it's something
  • 02:03:07
    that is very helpful to ensure that we
  • 02:03:08
    can maintain reliability and be flexible to the
  • 02:03:12
    conditions that are experienced on the grid. Another
  • 02:03:16
    thing that we do is issue operating condition
  • 02:03:19
    notices. And this is really not limited to
  • 02:03:23
    the shoulder months. This is something that happens
  • 02:03:25
    throughout the year pretty regularly. And the types
  • 02:03:28
    of things that would kind of drive that
  • 02:03:31
    would be when we see a threshold criteria
  • 02:03:34
    met, like if we see 94 degrees or
  • 02:03:38
    higher in the months of October through May
  • 02:03:41
    between San Antonio and the Dallas Fort Worth
  • 02:03:43
    regions. So that would be considered the cooler
  • 02:03:47
    periods of the grid, you know, October through
  • 02:03:49
    May. And so if we see an elevated
  • 02:03:51
    temperature, average temperature sustained in this region, then
  • 02:03:54
    that would meet the criteria for us to
  • 02:03:56
    let the market know there's an operating condition
  • 02:03:57
    notice that could lead to some kind of
  • 02:04:00
    a future action. It's basically an early notice
  • 02:04:04
    that we are seeing the conditions exist that
  • 02:04:07
    could lead to us having to take some
  • 02:04:08
    action to manage that condition in the future.
  • 02:04:11
    So it's kind of putting the market on
  • 02:04:12
    notice. It's not signaling that we expect there
  • 02:04:15
    to be some kind of a reliability issue
  • 02:04:17
    or some kind of a constraint, but we
  • 02:04:20
    are being proactive in letting people know that
  • 02:04:22
    the conditions are ripe for us to have
  • 02:04:24
    to take some kind of action to deal
  • 02:04:26
    with these conditions. We've seen this also happen
  • 02:04:29
    in recent months because of the wildfire risks,
  • 02:04:31
    where transmission operators are taking the prudent steps
  • 02:04:35
    to, take off recloser actions on some of
  • 02:04:38
    their transmission lines to avoid the risk of
  • 02:04:40
    sparking and creating a wildfire. And so when
  • 02:04:43
    the condition gets when the when the system
  • 02:04:45
    gets configured in that way, we would put
  • 02:04:47
    out a notice into the market to say
  • 02:04:49
    that the operating condition is, in place that
  • 02:04:52
    this situation exists. And so because of the
  • 02:04:54
    lack of reclose or action, ERCOT may have
  • 02:04:57
    to deal with the transmission system in a
  • 02:04:59
    different way in order to manage events that
  • 02:05:01
    happen. And so it's really just one of
  • 02:05:03
    those letting people know there's a situation out
  • 02:05:06
    there based on heat or operating conditions that
  • 02:05:09
    we want the market just to be aware
  • 02:05:11
    of and that we're going to do what
  • 02:05:12
    we need to do on a routine basis
  • 02:05:13
    in order to manage that condition. Any questions
  • 02:05:17
    on those two before I move on to
  • 02:05:18
    the next topics of the overall kind of
  • 02:05:20
    shoulder seasons, the AANs or the OCNs? If
  • 02:05:23
    there's any hard ones, I'll give them to
  • 02:05:25
    Dan because he's best at answering those. All
  • 02:05:29
    right. Thank you. So let's talk a little
  • 02:05:33
    bit about the Braunig unit updates that have
  • 02:05:37
    been going on. So if you recall, we
  • 02:05:40
    put in the RMR agreement and approved that
  • 02:05:44
    on February, twenty fifth of this year. The
  • 02:05:47
    outage began promptly afterwards on March 2. Inspections
  • 02:05:50
    of all of the kind of core components
  • 02:05:52
    and kind of taking apart the unit to
  • 02:05:54
    do the inspection and maintenance has been underway.
  • 02:05:57
    And there has been some pretty significant findings
  • 02:06:00
    recently related to the to those inspections. In
  • 02:06:04
    on March 28, the contractor determined that the
  • 02:06:07
    boiler super heater header is going to need
  • 02:06:09
    to be replaced, which is a fairly significant
  • 02:06:11
    replacement item, and it's a fairly costly one.
  • 02:06:15
    Right now, the costs that we have incremental
  • 02:06:19
    costs for repairs that we have received are
  • 02:06:22
    at about $2,700,000 That does not yet include
  • 02:06:26
    the cost estimate for the replacement of the
  • 02:06:28
    boiler super heater header. So that will be
  • 02:06:31
    an incremental cost on top of that that
  • 02:06:33
    we'll have to evaluate. In addition, we have
  • 02:06:36
    gotten signals that there may be some components
  • 02:06:39
    that need to be replaced that have longer
  • 02:06:41
    lead times in order to be able to
  • 02:06:43
    get those components in and get the unit
  • 02:06:45
    up and running. Right here in this slide,
  • 02:06:48
    it says the two to three months in
  • 02:06:50
    delays anticipated. We've gotten recent information that indicate
  • 02:06:54
    it could be longer than that. It could
  • 02:06:55
    be upwards of six to twelve months. But
  • 02:06:58
    that needs to be validated still with the
  • 02:07:00
    OEMs and with potential other suppliers. And so
  • 02:07:03
    we'll be looking at the impact of those
  • 02:07:05
    delays to understand what that means in terms
  • 02:07:07
    of the actual availability potential and then evaluate
  • 02:07:11
    the cost benefit of continuing to work through
  • 02:07:14
    this maintenance and repair cycle with Braunig Unit
  • 02:07:18
    three versus looking at some other alternative. That
  • 02:07:21
    data is very new, and we're still going
  • 02:07:22
    to need to evaluate kind of what the
  • 02:07:24
    implications of that. But at this point in
  • 02:07:26
    time, the team at CPS is working diligently
  • 02:07:30
    to try to fully go through that unit,
  • 02:07:31
    make sure that once it is brought back,
  • 02:07:33
    if it's able to be done so, that
  • 02:07:35
    it will be operating safely and reliably for
  • 02:07:37
    the term that it's going be able to
  • 02:07:38
    do so during this RMR period. Here's a
  • 02:07:44
    couple of pictures that were shared by CPS
  • 02:07:47
    Energy to give you a little bit of
  • 02:07:48
    perspective of the scale and the size of
  • 02:07:50
    some of these and vintage of some of
  • 02:07:52
    these assets that inside of Groning Unit 3,
  • 02:07:56
    we're looking at the low pressure turbine rotor
  • 02:07:59
    on the top left and the cleaning process
  • 02:08:01
    that's going on there and then the generator
  • 02:08:03
    rotor on the bottom right. So some significant,
  • 02:08:06
    significant large components that are of a significant
  • 02:08:10
    vintage. And so there's a of work going
  • 02:08:14
    into making sure that they can be operated
  • 02:08:15
    safely continually. Regarding the, life cycle power mobile
  • 02:08:23
    generation update, so in also on February 25,
  • 02:08:27
    the Board authorized moving forward with an option
  • 02:08:30
    to relocate these life cycle units from Houston
  • 02:08:33
    to San Antonio in order to help manage
  • 02:08:35
    the local transmission constraint that, existed in, during
  • 02:08:40
    that that was revealed during the RMR analysis.
  • 02:08:43
    The one of the issues that was at
  • 02:08:45
    bay was trying to determine whether or not
  • 02:08:47
    how the air permitting process would work, and
  • 02:08:49
    we believe that that issue has been resolved.
  • 02:08:52
    TCQ has identified a workable path forward for
  • 02:08:55
    an air permit that was a significant accomplishment
  • 02:08:59
    and milestone that needed to be achieved. Right
  • 02:09:01
    now, we're still in the final stages of
  • 02:09:03
    the negotiations with Lifecycle Power. There's Lifecycle Power
  • 02:09:09
    determining the discussing the terms of release with
  • 02:09:11
    CenterPoint. And then Lifecycle Power is negotiating QUIZI
  • 02:09:14
    services and an interconnection agreement with CPS Energy
  • 02:09:18
    as well as with ERCOT. And so we've
  • 02:09:22
    been working together to get these kind of
  • 02:09:24
    three components of the contract finalized. Expect that
  • 02:09:26
    to be done soon and focus on getting
  • 02:09:29
    these units up and running in the San
  • 02:09:31
    Antonio area. We are planning to do everything
  • 02:09:35
    we can to incentivize bringing these units on
  • 02:09:38
    as quickly as possible in the San Antonio
  • 02:09:43
    area. Given the fact that we are seeing
  • 02:09:46
    significant cost and potential schedule delays on the
  • 02:09:50
    Braunig unit, increases the importance in our view
  • 02:09:54
    of having these resources available during this the
  • 02:09:57
    peak parts of this summer in order to
  • 02:09:59
    support the reliability in that region. And so
  • 02:10:03
    that's something that we really want to focus
  • 02:10:05
    on and work closely with CPS and LCP
  • 02:10:08
    to do everything we can to potentially accelerate
  • 02:10:10
    the availability of those resources as early as
  • 02:10:13
    possible this summer, knowing that likely we're not
  • 02:10:16
    going to any of the Braunig units running
  • 02:10:18
    during the summer. So let me pause there
  • 02:10:21
    and see if there's any questions on either
  • 02:10:23
    the Braunig schedule or on the power. Thanks,
  • 02:10:27
    Pablo. With the delay on getting the life
  • 02:10:31
    cycle power contract signed, has any work commenced
  • 02:10:37
    on getting the facilities ready for that for
  • 02:10:39
    the mobile generation? Yes. Maybe I can ask
  • 02:10:45
    Woody perhaps or Chad to jump in and
  • 02:10:47
    support that. They've been close to the transactional
  • 02:10:50
    activities that are happening actually on the ground.
  • 02:10:52
    And so Chad? So work on the specific
  • 02:10:54
    sites, no, but there's obviously been a lot
  • 02:10:57
    of coordination between life cycle, CPS and ERCOT
  • 02:11:02
    on model data information that will be necessary
  • 02:11:05
    to move through the interconnection process to study
  • 02:11:08
    those facilities. The reason it's taking so long
  • 02:11:12
    is, as Pablo highlighted on that third bullet
  • 02:11:16
    point, there's multiple contracts involved here released by
  • 02:11:20
    CenterPoint, CPS and Lifecycle and then the agreement
  • 02:11:25
    between ERCOT and Lifecycle that does impact CPS.
  • 02:11:28
    And this is a new thing. And so
  • 02:11:31
    it involves a lot of legal work among
  • 02:11:36
    all those parties to make sure that that
  • 02:11:37
    risk is being appropriately managed. We are very
  • 02:11:41
    close, I believe to getting the ERCOT version
  • 02:11:44
    with LCP done. But obviously we don't have
  • 02:11:47
    control over how LCP works with CenterPoint or
  • 02:11:52
    CPS works with LCP on their kind of
  • 02:11:54
    bilateral arrangement. We're putting as much pressure on
  • 02:11:58
    those parties to get those issues wrapped up
  • 02:12:00
    as well. But I'm pretty optimistic that we
  • 02:12:03
    should be able to get all this resolved
  • 02:12:04
    hopefully by the end of this week as
  • 02:12:06
    far as the contracts to allow that to
  • 02:12:08
    move forward with anticipation of getting those assets
  • 02:12:11
    onto the grid sometime this summer. All of
  • 02:12:13
    the contracts not just the ERCOT contract? They're
  • 02:12:16
    all kind of contingent on everything being folded
  • 02:12:19
    up together. Thanks, Peggy. Any other questions? Sig?
  • 02:12:27
    Is there a drop dead date when for
  • 02:12:31
    whatever reason you can't get everything done that
  • 02:12:34
    you'll miss this summer window where you'll punt
  • 02:12:37
    the whole project? Not a drop dead date
  • 02:12:42
    that I'm aware of, but obviously every day
  • 02:12:44
    that goes by puts more risk on those
  • 02:12:47
    15 mobile generators not being there during that
  • 02:12:50
    kind of August peak, which is when we
  • 02:12:52
    need them. So again, the emphasis is to
  • 02:12:55
    try to get all this wrapped up by
  • 02:12:57
    the end of the week so that we
  • 02:12:58
    can continue to move forward with the best
  • 02:13:01
    possibility of having those assets available for the
  • 02:13:03
    summer peak. And just to put a maybe
  • 02:13:07
    broader point on that, there isn't a scenario
  • 02:13:08
    where we're going to punt this for the
  • 02:13:10
    summer. We're going to move forward irrespective to
  • 02:13:14
    try to get this put in as quickly
  • 02:13:15
    as possible. Okay. Appreciate the questions. Last couple
  • 02:13:26
    of items that I've got, related to some
  • 02:13:28
    of our external activities. So last year, we
  • 02:13:30
    had our first annual innovation summit that we
  • 02:13:33
    hosted and brought in stakeholders and industry participants
  • 02:13:40
    and research participants from around the country to
  • 02:13:43
    talk about what's going on in the innovations
  • 02:13:46
    on the grid, broadly speaking. I think it
  • 02:13:49
    was a very successful, gathering of professionals where
  • 02:13:53
    really interesting ideas shared across the board on
  • 02:13:56
    how differing grids around the country are dealing
  • 02:13:59
    with many different of the many of the
  • 02:14:00
    same challenges and some of the unique challenges
  • 02:14:02
    that are experienced in different regions in the
  • 02:14:04
    country. We're going to have another annual innovation
  • 02:14:07
    summit this year on May 6. We're gonna
  • 02:14:10
    be looking on an at an agenda that's
  • 02:14:13
    a little more, I'd say, maybe ERCOT focused
  • 02:14:15
    on some of the perspectives on some of
  • 02:14:17
    the issues that we're dealing with here in
  • 02:14:18
    ERCOT. We will be bringing in, experts and
  • 02:14:21
    industry participants from around the country. And the
  • 02:14:24
    agenda is going to include talking about kind
  • 02:14:26
    of what are some of the innovation roadmaps
  • 02:14:28
    that we are driving and why, talk about
  • 02:14:32
    the issues and opportunities and challenges around data
  • 02:14:36
    centers and the large load growth that we're
  • 02:14:38
    seeing. The we're going to talk about demand
  • 02:14:40
    response. Demand response is, as you've heard yesterday
  • 02:14:43
    with Keith's presentation, it's going to continue to
  • 02:14:45
    be a focus for us both at the
  • 02:14:47
    industrial level all the way down to the
  • 02:14:48
    residential level. So demand response opportunities, how we're
  • 02:14:52
    leveraging probabilistic modeling to improve our forecasting and
  • 02:14:56
    modeling tools across transmission and generation. And just
  • 02:15:01
    in general, an overall innovation kind of panel
  • 02:15:04
    with other ISOs and RTOs together coming you
  • 02:15:07
    know, coming together to share ideas. It really
  • 02:15:09
    was a I think a very helpful day
  • 02:15:13
    that we spent last year getting a chance
  • 02:15:15
    to really hear, make connections and network connections
  • 02:15:17
    that have been leveraged in the months since
  • 02:15:20
    working on issues with our peers around the
  • 02:15:23
    country. And we continue to build on those
  • 02:15:25
    relationships with planning and hosting this summit coming
  • 02:15:29
    up on May 6. There it is free
  • 02:15:31
    to event free to attend. And there's a
  • 02:15:33
    link here on the on our website that
  • 02:15:36
    you can go to if you're interested in
  • 02:15:38
    registering. So we welcome all that are interested
  • 02:15:40
    in participating. And then I'm really pleased to
  • 02:15:45
    announce that, we are publishing for the first
  • 02:15:48
    time in quite a few years, a version
  • 02:15:51
    of what you would call an annual report.
  • 02:15:53
    And, we're calling this advancing reliability for 2024,
  • 02:15:57
    the state of the grid. This QR code,
  • 02:15:59
    you can be you can use to access
  • 02:16:01
    the digital copy of it. It's also linked
  • 02:16:04
    on our website, and you can get access
  • 02:16:06
    to it there. But it's really highlighting a
  • 02:16:09
    lot of the things that have occurred since
  • 02:16:11
    really the last time we published an annual
  • 02:16:12
    report. And there's been a lot of changes
  • 02:16:14
    and a lot of progress made on the
  • 02:16:16
    ERCOT grid that we've talked a lot about
  • 02:16:18
    in these meetings. But more broadly speaking, what
  • 02:16:20
    we wanted to do is bring that together
  • 02:16:22
    into kind of one view to kind of
  • 02:16:24
    have a perspective on how we're thinking about
  • 02:16:26
    core aspects of reliability and innovation, technology investments,
  • 02:16:31
    and the important work that ERCOT has done
  • 02:16:33
    in conjunction with the legislature and their policy
  • 02:16:36
    changes with the Public Utility Commission and the
  • 02:16:39
    regulatory and policy support from them, and how
  • 02:16:42
    we've worked together to really advance the reliability
  • 02:16:45
    of the grid over these last few years.
  • 02:16:48
    I think it's a well done report. I
  • 02:16:49
    hope that you get a chance to review
  • 02:16:51
    it. It's something that we want to start
  • 02:16:52
    to do on an annual basis to reflect
  • 02:16:54
    on those progress points we've made in the
  • 02:16:57
    prior year as well as where some of
  • 02:16:59
    the challenges and the opportunities are as we
  • 02:17:01
    look down the road. And so we look
  • 02:17:03
    forward to your feedback on this new publication
  • 02:17:05
    and hope that it's helpful in understanding some
  • 02:17:08
    of the progress and some of the challenges
  • 02:17:09
    that we are facing in the years ahead.
  • 02:17:15
    And then like I always like to do
  • 02:17:16
    with my discussions here at the Board is
  • 02:17:19
    I'd like to offer some thanks. And this
  • 02:17:22
    time, I'd like to offer thanks to the
  • 02:17:24
    team that worked on NOGRR245.
  • 02:17:27
    NOGRR245 was the nodal operating
  • 02:17:30
    guide revision that dealt with the ride through
  • 02:17:34
    standards for inverter based resources. And it was
  • 02:17:37
    one of the most commented operating guide changes
  • 02:17:41
    that we've probably ever done in ERCOT. It
  • 02:17:44
    had a lot, a lot of focus and
  • 02:17:46
    attention from the market and the industry at
  • 02:17:48
    large. It was worked through for a period
  • 02:17:52
    of well over one point years, starting early
  • 02:17:55
    in 2023 through its passage late in 2024.
  • 02:18:00
    It was an effort that I think characterized
  • 02:18:03
    collaboration the way it's supposed to be done
  • 02:18:05
    in the market. It wasn't easy. It wasn't
  • 02:18:08
    always smooth. There was contention. There ended up
  • 02:18:12
    with compromise. I think there was something in
  • 02:18:15
    there for everybody to like and there was
  • 02:18:16
    something in there for everybody to hate. And
  • 02:18:18
    it really characterized, I think, some of the
  • 02:18:20
    more complex issues that we deal with as
  • 02:18:22
    a grid. And I think it's representative of
  • 02:18:24
    some of the things we'll deal with in
  • 02:18:25
    the future because the changes that are going
  • 02:18:27
    to be coming our way are going to
  • 02:18:29
    be harder. It's not going to get any
  • 02:18:32
    easier to manage the complexities of this grid
  • 02:18:34
    as we go forward. And the way we
  • 02:18:36
    work through these operating guides or planning protocols
  • 02:18:40
    are really, really consequential. I feel blessed to
  • 02:18:44
    be working in an ISO where that process
  • 02:18:47
    is might maybe one of the most transparent
  • 02:18:49
    and offers the most opportunity for real impact
  • 02:18:53
    by the market and the stakeholders that are
  • 02:18:55
    influenced most by the decisions. And that's a
  • 02:18:58
    really unique thing that we have here. And
  • 02:19:00
    so while this was one of the more
  • 02:19:02
    challenging ones that we worked through, I think
  • 02:19:03
    it represented some of the best work that
  • 02:19:06
    we can do together as a market. And
  • 02:19:08
    so I just want to offer my thanks
  • 02:19:10
    just to the internal team. And I also
  • 02:19:12
    want to thank the many, many external people
  • 02:19:14
    that worked on this and got us through
  • 02:19:15
    this process. This team here on the screen
  • 02:19:19
    spent countless hours, days and weeks focused on
  • 02:19:22
    trying to ensure we could get to a
  • 02:19:24
    compromise and to an answer that in the
  • 02:19:25
    end would advance reliability. And I think they
  • 02:19:28
    were successful in doing that. So with that,
  • 02:19:31
    I will conclude my comments unless there are
  • 02:19:34
    any questions from anybody. Thank you, Pablo. Any
  • 02:19:38
    questions for Pablo? Okay. Thank you. Thank you.
  • 02:19:45
    We will move on to the next agenda
  • 02:19:47
    item, which I know several people are looking
  • 02:19:49
    forward to abated breath. That is agenda item
  • Item 8.1 - Long-Term Load Forecast Update (2025–2031
    02:19:52
    and Methodology Changes) 8.1, the long term load forecast update for
  • 02:19:55
    2025 through 02/1931, along with methodology changes that
  • 02:19:59
    were used to prepare that report. It's going
  • 02:20:02
    to be presented by Pablo, Woody Rickerson and
  • 02:20:05
    Richard Shields. So gentlemen, let's start with Woody.
  • 02:20:11
    Good morning. So I will start this off.
  • 02:20:18
    So this item looks at changes to the
  • 02:20:21
    long term load forecast used by Archive. Some
  • 02:20:25
    of the key takeaways are a discussion of
  • 02:20:28
    the planning guide and protocol requirements for use
  • 02:20:31
    of the forecast. We'll look at the TSP
  • 02:20:34
    provided forecast and the treatment of data center
  • 02:20:37
    load growth. We'll look at a methodology behind
  • 02:20:40
    a new ERCOT adjusted long term load forecast.
  • 02:20:45
    And finally, we'll look at the energy forecast
  • 02:20:49
    used for the ERCOT system administration fee. There's
  • 02:20:53
    no voting action required on this from the
  • 02:20:57
    Board. So some of the implications of House
  • 02:21:03
    Bill 5,066, which was passed in 2023 for
  • 02:21:07
    transmission planning. So HB5066 clarified that
  • 02:21:13
    TSP provided load forecast provided that the TSP
  • 02:21:17
    provided load forecast the PUC must consider in
  • 02:21:19
    evaluating the need for a transmission facility. The
  • 02:21:24
    bill did not directly apply to ERCOT. However,
  • 02:21:28
    nodal protocol changes and planning guide changes revised
  • 02:21:31
    our protocols and planning guides regarding the ERCOT
  • 02:21:36
    load forecast to allow TSPs to include load
  • 02:21:39
    that is not supported by an interconnection agreement
  • 02:21:42
    while still honoring the quantifiable evidence standard in
  • 02:21:47
    the PUC substantive rule. So those that PGRR
  • 02:21:51
    eleven eighty or NPRR1180 and PGRR
  • 02:21:54
    107 provided that load forecast supported by one
  • 02:21:58
    of the following would be sufficient. So those
  • 02:22:02
    three categories that you see there. So the
  • 02:22:05
    first category was an executed interconnection or other
  • 02:22:08
    agreement, a third party load forecast or a
  • 02:22:12
    letter from a TSP officer attesting to such
  • 02:22:15
    a load. Those that NPRR and PGRR were
  • 02:22:19
    approved in January of this year. So keep
  • 02:22:23
    in mind that this is how HB5066 and
  • 02:22:28
    those guide changes apply to transmission planning. So
  • 02:22:38
    we also have resource adequacy. So the other
  • 02:22:40
    part of the story is what impact does
  • 02:22:41
    it have on resource adequacy reports. So ERCOT
  • 02:22:47
    must provide an annual report quantifying the capability
  • 02:22:50
    of existing and planned electric generation resources and
  • 02:22:53
    load resources every year. And so we do
  • 02:22:56
    that with the CDR. So ERCOT has the
  • 02:22:59
    flexibility to determine the appropriate values to include
  • 02:23:03
    in its load forecast that uses in that.
  • 02:23:06
    So the previous CDR, December 2024, we actually
  • 02:23:12
    used the TSP load forecast and resulted in
  • 02:23:16
    negative planning reserve margins as early as 2026.
  • 02:23:19
    So we're going to pivot away from using
  • 02:23:21
    that forecast in this year's May CDR and
  • 02:23:24
    we'll move to the ERCOT adjusted load forecast
  • 02:23:27
    that we'll talk about in subsequent slides. So
  • 02:23:35
    this graphic illustrates the process used to arrive
  • 02:23:39
    at the aggregate TSP provided load forecast. So
  • 02:23:44
    you start with this the ERCOT base econometric
  • 02:23:47
    forecast. We do some things with electric vehicles,
  • 02:23:50
    photovoltaics on rooftops, not your utility scale solar,
  • 02:23:55
    but the rooftop solar. And then we add
  • 02:23:58
    in transmit TSP information. And those are those
  • 02:24:01
    three categories we talked about in the previous
  • 02:24:03
    slide, executed contracts, third party forecast and TSP
  • 02:24:07
    officer attested loads. So the most impactful difference
  • 02:24:14
    that HB5066 added was the TSP officer attested
  • 02:24:20
    loads. That's where you see most of the
  • 02:24:25
    big difference that we'll show that in the
  • 02:24:27
    next slide. Another interesting point here is that
  • 02:24:30
    ERCOT is beginning to have actual load to
  • 02:24:33
    verify past TSP forecast future load. So for
  • 02:24:37
    example, a twenty twenty three forecast of a
  • 02:24:40
    2024 load, we can now go look at
  • 02:24:42
    that load and see how it matches the
  • 02:24:44
    forecast. So we're beginning to be able to
  • 02:24:47
    incorporate some of that information in the ERCOT
  • 02:24:50
    adjusted load forecast. We'll discuss how ERCOT will
  • 02:24:54
    use those performance measures in later slides. So
  • 02:25:02
    this graph is a comparison of the 2024
  • 02:25:06
    TSP provided load forecast and the 2025 TSP
  • 02:25:10
    provided load forecast. The gray line at the
  • 02:25:13
    top that you see is the 2025 aggregate
  • 02:25:17
    TSP load forecast, and the blue line is
  • 02:25:21
    the 2024 forecast. You can see there's a
  • 02:25:24
    substantial increase, 68 gigawatts in 02/1931. If you
  • 02:25:33
    look at the bar charts below that, you
  • 02:25:35
    can also see that most of the load
  • 02:25:36
    growth from last year is found in the
  • 02:25:39
    new officer letter loads. That's that last teal
  • 02:25:44
    colored bar you see. Those are the officer
  • 02:25:47
    letter loads. So breaking that growth down even
  • 02:25:54
    further in this graph, you see an increase
  • 02:25:56
    of 55 gigawatts of officer letter loads just
  • 02:26:00
    centers over last year. That's that middle set
  • 02:26:03
    of bar charts. In the bottom chart, you
  • 02:26:07
    also see an increase in the number of
  • 02:26:09
    TSPs providing new load in one of those
  • 02:26:12
    three categories we talked about on Slide four.
  • 02:26:14
    So we had those three categories. Last year,
  • 02:26:17
    we had seven TSPs providing additional load. This
  • 02:26:20
    year, we had 17. The total officer lettered
  • 02:26:24
    loads increased from twenty twenty four to twenty
  • 02:26:27
    twenty five, one hundred and 80 nine sites
  • 02:26:31
    were added additional over last year. So this
  • 02:26:43
    is the twenty twenty five aggregate TSP provided
  • 02:26:48
    load forecast broken down by types and by
  • 02:26:51
    years. It's an annual look. The bottom bar
  • 02:26:57
    that you see there, the cyan color is
  • 02:27:00
    the baseload that you see and you see
  • 02:27:02
    the load growth, just the load growth in
  • 02:27:04
    the base from 86 up to 94. The
  • 02:27:09
    gray bar the gray section there represents the
  • 02:27:14
    aggregate TSP forecasted data center growth alone. So
  • 02:27:18
    you see that that's a pretty substantial amount.
  • 02:27:21
    In 02/1930, the forecast the TSP part of
  • 02:27:25
    the forecast for data centers was $29,000.20 20
  • 02:27:28
    that grew to almost $78,000 in 2025. So
  • 02:27:33
    that's where most of that load growth is
  • 02:27:34
    coming. So this graphic illustrates the process that
  • 02:27:44
    ERCOT is going to use to produce a
  • 02:27:45
    new ERCOT adjusted load forecast. It's based on
  • 02:27:48
    three different adjustments. The first is a delay
  • 02:27:52
    in service delay in the in service date
  • 02:27:55
    of one hundred and eighty days for all
  • 02:27:57
    new large loads. The second adjustment is a
  • 02:28:01
    reduction of all new data center demand to
  • 02:28:04
    49.8% of the requested forecasted amount. And the
  • 02:28:09
    final one is a reduce of officer letter
  • 02:28:12
    loads to 55.4%. So the 49.855.4% represent a
  • 02:28:22
    measured percentage of power being used versus what
  • 02:28:26
    was forecasted. So those numbers were derived from
  • 02:28:30
    loads that had been forecasted that we can
  • 02:28:32
    now see and measure. So those numbers as
  • 02:28:36
    we move forward can change. As forecasts become
  • 02:28:39
    more accurate, those numbers will also change. So
  • 02:28:44
    I think that's an important part to keep
  • 02:28:46
    in mind here is that this is a
  • 02:28:48
    forecast based on the most recent data we
  • 02:28:51
    have and we'll continue to update that as
  • 02:28:53
    we move forward. So this chart compares three
  • 02:29:01
    different forecast methodologies. So starting from the bottom,
  • 02:29:06
    you see the green line. That is the
  • 02:29:09
    ERCOT forecast that we would have used before
  • 02:29:13
    HB5066 and Figure 107 and NPRR1180.
  • 02:29:17
    So that's the pre HB5066 forecast. The gray
  • 02:29:23
    line is the new ERCOT adjusted load forecast.
  • 02:29:27
    And then the line on top that you
  • 02:29:28
    see is the TSP provided forecast for 2025.
  • 02:29:33
    So one thing I'd point out is the
  • 02:29:35
    gray line is still a very aggressive load
  • 02:29:38
    forecast, a lot of new load growth there.
  • 02:29:42
    It's 26 gigawatts over what we would have
  • 02:29:45
    predicted before HB5066. The other thing I'd point
  • 02:29:49
    out is that little bar, dumbbell bar thing
  • 02:29:54
    that you see there on the gray line,
  • 02:29:56
    that is a 130 gigawatt to 148 gigawatt
  • 02:30:00
    range that was used in the 2024 regional
  • 02:30:03
    transmission plan that we put out last year.
  • 02:30:06
    So this year's adjusted load forecast fits very
  • 02:30:09
    well in the range of values we used
  • 02:30:12
    in last year's RTP for 02/1930. So there
  • 02:30:15
    should be no inconsistencies there. This is very
  • 02:30:18
    much in line with what we study in
  • 02:30:20
    the RTP. So this chart looks at the
  • 02:30:28
    annual comparison of the new ERCOT adjusted load
  • 02:30:31
    forecast versus the TSP forecast. You see the
  • 02:30:34
    TSP forecast behind in the gray. That's the
  • 02:30:37
    same values that you saw on Slide eight.
  • 02:30:40
    The values in the foreground are the ERCOT
  • 02:30:43
    adjusted forecast. And you'll see that the future
  • 02:30:45
    data center growth remains the single largest area
  • 02:30:48
    of adjustment. That's where most of the reduction
  • 02:30:50
    occurs. Once again, 138 gigawatt forecast in 02/1930
  • 02:30:55
    fits into that load range that we used
  • 02:30:57
    in the RTP. And you see that in
  • 02:30:59
    the 02/1930 bar there, which right here where
  • 02:31:02
    this represents the range that we used in
  • 02:31:06
    the RTP. And the new forecast fits that
  • 02:31:09
    range very well. We put this slide in
  • 02:31:16
    because all this new load growth is going
  • 02:31:19
    to require more generation. This slide provides some
  • 02:31:22
    context for how much generation has been added
  • 02:31:25
    in previous years. So for example, during the
  • 02:31:31
    early 2000s, more than 27,000 megawatts of new
  • 02:31:34
    gas generation was added over a five year
  • 02:31:36
    period. More recently, in the last three years,
  • 02:31:39
    we've seen 25,000 megawatts of wind and solar
  • 02:31:42
    added and about that 9,000 megawatt hours of
  • 02:31:47
    energy storage were also added. So these periods
  • 02:31:52
    of rapid growth represent some context for how
  • 02:31:56
    much new generation you could expect to be
  • 02:31:58
    built in the ERCOT grid. I mean there
  • 02:32:01
    are limits to what how much generation can
  • 02:32:04
    be added. And those limits should be factored
  • 02:32:06
    in when we talk about what a load
  • 02:32:07
    forecast looks like. The other thing I'd point
  • 02:32:10
    out about this line or this graph is
  • 02:32:13
    the red line that you see. And that
  • 02:32:15
    is a winner ELCC, effective load carrying capacity
  • 02:32:18
    of that generation. So even though you see
  • 02:32:21
    a lot of new generation being built recently,
  • 02:32:23
    the effective load carrying capacity is much less
  • 02:32:27
    than what it was in the early 2000s
  • 02:32:29
    for that new generation because of its ELCC
  • 02:32:32
    measurements. So what do you put that in
  • 02:32:39
    context? So even though in 2024 we added
  • 02:32:42
    looks like roughly just under 14 gigawatts of
  • 02:32:46
    total generation resources, about three gigawatts of that
  • 02:32:51
    is ELCC that's really usable generation that you
  • 02:32:55
    can count on in the winter. That's right.
  • 02:32:57
    Okay. Yes. A lot of that solar you
  • 02:33:00
    can't count on for a winter peak because
  • 02:33:02
    the peaks occur before and current situation is
  • 02:33:12
    of we're the the forecast goes many places
  • 02:33:23
    in the ERCOT system and in ERCOT analysis.
  • 02:33:26
    The first is the capacity and demand reserves
  • 02:33:29
    report. So beginning in May of this year,
  • 02:33:32
    we'll use the ERCOT adjusted load forecast for
  • 02:33:35
    developing the planning reserve margin. We may have
  • 02:33:38
    additional scenarios that include the TSP forecasted load
  • 02:33:42
    as well. The regional transmission plan is another
  • 02:33:45
    place. ERCOT will utilize the ERCOT adjusted load
  • 02:33:48
    forecast. A good cause exception may be required
  • 02:33:51
    from the PUC in order to use that
  • 02:33:55
    forecast in that particular plan because of the
  • 02:33:58
    NPRR and the figures that were passed earlier.
  • 02:34:01
    The regional planning group projects that are submitted
  • 02:34:03
    to ERCOT. So if the RTP is kind
  • 02:34:06
    of the road map, the RPG projects come
  • 02:34:10
    in to fill out and flush out that
  • 02:34:13
    road map. So ERCOT analysis will begin with
  • 02:34:16
    the adjusted load forecast, but we'll also consider
  • 02:34:20
    TSP provided load forecast in the RPG review
  • 02:34:23
    process. And finally, resource outage scheduling. Pablo talked
  • 02:34:28
    about the seasonal amount of resource outages that
  • 02:34:32
    are going on right now. That's the amount
  • 02:34:35
    that you allow is driven by the MDR
  • 02:34:38
    POC level, maximum daily resource planned outage something,
  • 02:34:47
    C. I should have written that down. But
  • 02:34:53
    anyway, we will update that MDR POC to
  • 02:34:56
    the ERCOT adjusted load forecast, which will provide
  • 02:35:00
    as a part of that process and it
  • 02:35:02
    will provide some more bandwidth for resource outages.
  • 02:35:12
    And finally, everything we've been talking about so
  • 02:35:14
    far through these slides are demand forecasts. Demand
  • 02:35:18
    is the amount of power being consumed at
  • 02:35:20
    any point in time. Energy is the amount
  • 02:35:23
    of power consumed over a period of time.
  • 02:35:25
    So the ERCOT adjusted load forecast we discussed
  • 02:35:28
    is a demand forecast, point in time forecast.
  • 02:35:31
    We use that in transmission planning, resource adequacy.
  • 02:35:35
    We use it to scale energy forecast. We
  • 02:35:37
    use it in transmission planning. The two charts
  • 02:35:40
    there show that you can have two periods
  • 02:35:43
    of time that have the same demand but
  • 02:35:45
    have different amount of energy. The area under
  • 02:35:47
    the curve is different but the demand is
  • 02:35:50
    the same. So the key takeaway here is
  • 02:35:55
    that the energy forecast used for the ERCOT
  • 02:35:57
    system administration fee is based on the same
  • 02:35:59
    information as the ERCOT load forecast, but differs
  • 02:36:03
    in being a forecast of energy. And Richard
  • 02:36:04
    is going to talk about the use of
  • 02:36:07
    that energy forecast. But before I go, is
  • 02:36:11
    there any questions about any of these slides
  • 02:36:13
    that we've covered? Yes. Woody, just real quick,
  • 02:36:16
    will you go back to Slide nine real
  • 02:36:20
    quick? So looking at those kind of discount
  • 02:36:28
    rates that you applied, I assume those are
  • 02:36:32
    averages ERCOT wide. Was any consideration given to
  • 02:36:37
    applying different methodologies for different TSP service territories
  • 02:36:41
    based on what you're seeing specific to those
  • 02:36:43
    territories as it pertains to those percentages? Yes.
  • 02:36:47
    So those percentages were to help us arrive
  • 02:36:50
    at an aggregate number for the forecast. How
  • 02:36:54
    we apply those percentages in a case because
  • 02:36:58
    when you take that overall percentage, you reduce
  • 02:37:00
    it to 49.8%, you still have to put
  • 02:37:04
    it in a case in positions in a
  • 02:37:06
    case. And so that's something we're going to
  • 02:37:07
    have to start talking with the TSPs about
  • 02:37:09
    how to apply that. So that could be
  • 02:37:11
    regional, that could be by TSP. There are
  • 02:37:14
    a lot of different ways. It could be
  • 02:37:15
    consistent across all, but that's to be determined
  • 02:37:18
    on how it will be applied. Okay. Any
  • 02:37:24
    other questions? Could you just remind the audience
  • 02:37:28
    what the definition of a large load? 75
  • 02:37:31
    megawatts and larger. So this is a process
  • 02:37:37
    question. So understanding what you did on Slide
  • 02:37:40
    10 was looking at adjusting the numbers that
  • 02:37:44
    coming in on Slide seven. So if you
  • 02:37:48
    go to Slide seven, you did make adjustments
  • 02:37:50
    to these projections. Oops, sorry, it's eight. Sorry,
  • 02:37:53
    the wrong one. So it's eight. So we
  • 02:37:55
    know that data is coming in on the
  • 02:37:57
    hydrogen centers in terms of funding going down.
  • 02:38:00
    We know that there may be supply chain
  • 02:38:03
    issues that will affect the growth of the
  • 02:38:07
    data We just don't know yet. So what's
  • 02:38:10
    the process for updating this as we get
  • 02:38:13
    new information? Right. So the ERCOT adjusted forecast
  • 02:38:18
    as we get historical information about hydrogen loads,
  • 02:38:22
    we can apply that same kind of factor
  • 02:38:24
    to hydrogen loads. We don't have those to
  • 02:38:26
    look at yet. We have data center loads
  • 02:38:28
    that we can look at, but we don't
  • 02:38:30
    have the hydrogen loads. So as we as
  • 02:38:32
    that becomes historic information, we can use that
  • 02:38:34
    to adjust. Yes. So do you have some
  • 02:38:37
    estimate like I know this is a new
  • 02:38:39
    like frequency, will you do it once a
  • 02:38:41
    quarter, once every six months, once what's your
  • 02:38:44
    sense of how often you'll be feeding data
  • 02:38:47
    into this and then using that new information?
  • 02:38:51
    Right now this is an annual process. Annual,
  • 02:38:54
    okay. Yes. There a in your mind, might
  • 02:38:58
    there be a change that's significant enough to
  • 02:39:00
    cause you to do it sooner than annual?
  • 02:39:02
    We could. We could. As we get more
  • 02:39:05
    information, we certainly can make this twice a
  • 02:39:07
    year, quarterly. I mean there are ways of
  • 02:39:09
    changing this and updating it. The problem is
  • 02:39:11
    that most of the transmission planning process is
  • 02:39:14
    an annual process. So you start with a
  • 02:39:17
    load in the transmission planning process, and it's
  • 02:39:22
    difficult to make a midyear adjustment. Right. But
  • 02:39:25
    you're open to if there is a significant
  • 02:39:27
    defining event that you can That's right. Yes.
  • 02:39:30
    And Woody, it may be helpful to add
  • 02:39:32
    like in the transmission planning process, the RTP
  • 02:39:35
    is a roadmap that doesn't just approve projects.
  • 02:39:39
    They still have to come back through, go
  • 02:39:42
    through the RPG review, get commission approval before
  • 02:39:45
    it's approved. So there's multiple places where if
  • 02:39:48
    there's adjustments and they can no longer justify
  • 02:39:50
    that load, there's protections in place before transmission
  • 02:39:55
    is built that's not needed. Any other questions
  • 02:40:00
    on these first slides? Yes. I have a
  • 02:40:03
    question. Recognizing that ERCOT and the TSPs are
  • 02:40:08
    adjusting to the HB5066 regime. Can you comment
  • 02:40:16
    on the quality of information we're getting because
  • 02:40:21
    that's critical to anything we do regardless how
  • 02:40:25
    we slice and dice the material we receive.
  • 02:40:28
    Yes. So I think TSPs and ERCOT both
  • 02:40:32
    are working through some very information. Data centers
  • 02:40:39
    are not something that we were forecasting or
  • 02:40:41
    looking at four years ago, five years ago.
  • 02:40:46
    So this is new information. How fast it
  • 02:40:49
    builds out is something we're all going to
  • 02:40:51
    learn together. And so as far as the
  • 02:40:53
    quality of information, I think it needs to
  • 02:40:55
    be adjusted. That's why we put out this
  • 02:40:56
    adjusted forecast. The adjustments though are based on
  • 02:41:00
    just the leading edge of historic numbers. As
  • 02:41:03
    we get more of those numbers, I think
  • 02:41:05
    we will merge. And what I hope happens
  • 02:41:08
    over time is the ERCOT adjusted load forecast
  • 02:41:11
    and the overall TSB aggregate forecast end up
  • 02:41:14
    merging into the same forecast eventually. And something
  • 02:41:18
    to add to that also is that there
  • 02:41:20
    is legislation being considered right now. Senate Bill
  • 02:41:22
    six is one of those that has provisions
  • 02:41:25
    in it to deal with the inputs. So
  • 02:41:26
    to standardize the requirements around what gets included
  • 02:41:30
    in a transmission company submitted forecast, that will
  • 02:41:34
    definitely be influential to this process as well.
  • 02:41:36
    And we would look to adapt our methodologies
  • 02:41:39
    to whatever the legislative requirements are. But that's
  • 02:41:42
    another quality kind of input that might affect
  • 02:41:45
    this. My comment really went to the information
  • 02:41:49
    provided from the TSPs. And I know they're
  • 02:41:53
    learning, we're learning. But having some vigor to
  • 02:41:57
    that process is critical because we get the
  • 02:41:59
    information from them. And we need to rely
  • 02:42:03
    on it to some extent in making these
  • 02:42:05
    decisions So just comment. Anything else? All right.
  • 02:42:14
    I'll turn this over to Richard then. Thank
  • 02:42:22
    you, Woody. Richard Scheele, CFO and Chief Risk
  • 02:42:25
    Officer for ERCOT. I want to walk through
  • 02:42:27
    the impacts of the adjusted load forecast and
  • 02:42:31
    how we're thinking about that for the system
  • 02:42:33
    administration fee rate setting purposes. So the adjusted
  • 02:42:38
    load forecast, Woody just discussed, we are planning
  • 02:42:41
    to modify for purposes of setting the system
  • 02:42:44
    administration fee rate and for forecasting purposes for
  • 02:42:47
    finances at So this adjustment that we're discussing
  • 02:42:52
    on the next two slides only affects those
  • 02:42:55
    two pillars. It affects the fee rate and
  • 02:42:57
    it will affect the financial forecasting at ERCOT.
  • 02:43:02
    And so what we did was when we're
  • 02:43:04
    thinking about the system administration fee rate and
  • 02:43:07
    about our cash flow and financing needs at
  • 02:43:09
    ERCOT and funding operations, we made two significant
  • 02:43:15
    adjustments to the adjusted load forecast Woody just
  • 02:43:18
    discussed. The primary is the delay of contract
  • 02:43:22
    and officer letter loads. Currently, that's set at
  • 02:43:25
    the one hundred and eighty day delay, and
  • 02:43:27
    that was covered in the earlier slide. And
  • 02:43:29
    if you'll recall, the experience that we've had
  • 02:43:34
    with that so far is around two twenty
  • 02:43:36
    days. So slightly more aggressive forecast for the
  • 02:43:39
    adjusted load forecast. We've adjusted that to a
  • 02:43:41
    three sixty five day delay, considering the number
  • 02:43:44
    of new officer letter loads that have been
  • 02:43:46
    generated between the 2024 forecast and the 2025
  • 02:43:49
    forecast. For the data centers, we use the
  • 02:43:52
    same load discount. It's at 49.8% both for
  • 02:43:56
    load and for energy. Of course, system administration
  • 02:43:59
    fee rate is set on energy, so I
  • 02:44:00
    just want to call that out. On the
  • 02:44:02
    officer letter loads, we discounted we took the
  • 02:44:05
    55.4% and we replaced that with a 20%
  • 02:44:08
    discount. When we look at the delta between
  • 02:44:11
    2024 and 2025, that still anticipates a 60%
  • 02:44:15
    increase in the number of officer letter loads
  • 02:44:18
    that translate from an officer letter to actual
  • 02:44:22
    energization. So it's still a significant increase between
  • 02:44:24
    the two years. And then I have a
  • 02:44:28
    graph just to show what this looks like
  • 02:44:30
    in practice and what our experience looks like
  • 02:44:32
    previously. So we have each of the forecasts
  • 02:44:36
    from 2019, the load 2023 forecast that we
  • 02:45:27
    had previously. So the 2025 system administration fee
  • 02:45:34
    rate forecast is still slightly more aggressive than
  • 02:45:36
    those previous forecasts. And to Woody's point earlier,
  • 02:45:39
    we weren't even looking at significant data center
  • 02:45:42
    loads as recently as 2023. If we had
  • 02:45:45
    used the 2025 adjusted load forecast that is
  • 02:45:49
    being used basis for our system administration fee
  • 02:45:56
    rate. Without the ability to perform regression analysis
  • 02:45:59
    on those numbers, we're going to hold that
  • 02:46:01
    for 2026 and 2027. And to Woody's point,
  • 02:46:04
    we will revisit that as we're approaching the
  • 02:46:06
    twenty twenty eight-twenty twenty nine budget cycle and
  • 02:46:10
    setting the fee rate for 2028 and 2029.
  • 02:46:15
    Any questions? Any questions for Richard? Okay, Richard,
  • 02:46:25
    thank you. The next agenda item is item
  • 02:46:29
    nine, which is an update on the Texas
  • 02:46:31
    economy. Our presenter today is Pia Ranegic, a
  • 02:46:35
    labor economist at the Federal Reserve Bank of
  • 02:46:37
    Dallas. She works on regional economic growth and
  • 02:46:40
    demographic change. She manages the regional and microeconomics
  • 02:46:44
    group at the Dallas Fed Research Department. And
  • 02:46:47
    she is also executive editor of the publication
  • 02:46:49
    Southwest Economy, and she co edited the 10
  • 02:46:53
    gallon economy sizing up economic growth in Texas
  • 02:46:56
    in 2015. Her academic research focuses on the
  • 02:47:00
    labor market impacts of immigration, unauthorized immigration and
  • 02:47:04
    US immigration policy. She is co author of
  • 02:47:07
    the book Beside the Golden Door, US immigration
  • 02:47:11
    reform in the new era of globalization in
  • 02:47:13
    2010. She is affiliated with several academic institutions,
  • 02:47:18
    a research fellow at the Tower Center for
  • 02:47:20
    Public Policy and International Affairs, and the Mission
  • 02:47:24
    Foods Texas Mexico Center at Southern Methodist University,
  • 02:47:28
    and at the IZA Institute of Labor and
  • 02:47:32
    Bond Germany as well as adjunct scholar of
  • 02:47:34
    the American Enterprise Institute. Arrhenius was a senior
  • 02:47:39
    economist on the Council of Economic Advisors and
  • 02:47:42
    the Executive Office of the President in 02/2004,
  • 02:47:46
    '2 thousand and '5 where she advised the
  • 02:47:47
    Bush administration on labor health and immigration issues.
  • 02:47:52
    She holds a PhD in economics from UCLA
  • 02:47:54
    and Bachelor's degree in economics and Spanish from
  • 02:47:57
    the University of Illinois at Urbana Champaign. So
  • 02:48:00
    thank you for joining us today Ms. Aranias
  • 02:48:02
    and the floor is yours. We look forward
  • 02:48:03
    to your Thank so much. You so much,
  • Item 9 - Update on Texas Economy
    02:48:06
    Chair. Well, I'm so happy to be here
  • 02:48:09
    and thank you for inviting me and I
  • 02:48:10
    thought we'd talk about how resilient is the
  • 02:48:14
    current outlook for growth in our region. So
  • 02:48:19
    of course, there's the first the disclaimer. These
  • 02:48:22
    views are certainly my own, I do not
  • 02:48:24
    speak for the Federal Reserve System. Alright. Let's
  • 02:48:27
    start with an overview. So the Texas economy
  • 02:48:32
    is likely slowing. Outlooks have recently turned pessimistic.
  • 02:48:37
    The labor market has been pretty robust so
  • 02:48:39
    far, though. Job growth has been robust so
  • 02:48:42
    far in 2025, but you know the caveat
  • 02:48:45
    there is that the employment data is only
  • 02:48:47
    through February. Real time service of Texas businesses
  • 02:48:50
    that we do at the Dallas Fed are
  • 02:48:51
    flashing some warning signs especially in March. So
  • 02:48:55
    growth is likely to slow further as far
  • 02:48:57
    as we can tell, and we're below trend
  • 02:49:00
    in 2025 and will probably slow further than
  • 02:49:03
    we're currently forecasting. The main reason is tariffs.
  • 02:49:06
    They're going to lead to higher prices. Consumption
  • 02:49:09
    and investment will slow and possibly decline. There
  • 02:49:12
    will be, we anticipate, additional negative growth effects
  • 02:49:16
    of lower immigration and government spending cuts, federal
  • 02:49:20
    government spending cuts. I think the Texas government
  • 02:49:23
    may be spending increasing. But tax cuts in
  • 02:49:28
    the second half of the year, if they
  • 02:49:30
    come about, may boost the economy. And of
  • 02:49:32
    course, if we get deregulation from the current
  • 02:49:35
    administration, that can also be a tailwind, especially
  • 02:49:37
    for certain industries like energy. So the Texas
  • 02:49:43
    business outlooks that we do at the Dallas
  • 02:49:44
    Fed that I mentioned on the overview slide
  • 02:49:46
    are showing that activity is slowing. We have
  • 02:49:49
    a service sector which is of course the
  • 02:49:51
    bulk of the economy that's here in green,
  • 02:49:53
    that's service sector revenue, and manufacturing production in
  • 02:49:56
    blue. And so these are diffusion indexes. If
  • 02:49:59
    they're in positive territory, that signifies growth. But
  • 02:50:03
    of course, the fact that they've turned down
  • 02:50:04
    in recent months suggests that this growth is
  • 02:50:06
    slowing. We also have more sentiment based indicators
  • 02:50:11
    from our surveys. So here I'm showing you
  • 02:50:14
    things like company outlook, which is a pretty
  • 02:50:19
    good predictor in our surveys for future activity
  • 02:50:22
    and other measures of future business activity, future
  • 02:50:25
    investment, and future output. And of course, many
  • 02:50:28
    of these survey indicators picked up after the
  • 02:50:31
    election. Many actually picked up after the Fed
  • 02:50:34
    cut rates last September. But as you can
  • 02:50:38
    see in recent months, they've turned down and
  • 02:50:41
    some have turned down to the point where,
  • 02:50:43
    for example, company outlook is in negative territory,
  • 02:50:45
    means that they're forcing a worsening outlook. On
  • 02:50:51
    the labor market, Texas job growth again, as
  • 02:50:54
    I mentioned earlier, this year is it's, you
  • 02:50:58
    know, still pretty robust at 1.9% through February,
  • 02:51:01
    that's February over December. That's better than last
  • 02:51:04
    year, which actually was quite slow. We only
  • 02:51:06
    grew 1.5% last year, which is very slow
  • 02:51:08
    for Texas. We typically grow on average at
  • 02:51:11
    2.1% growth rate. We also typically grow about
  • 02:51:16
    one percentage point faster than the nation, which
  • 02:51:18
    year to date that seems to be holding
  • 02:51:20
    true. The US is coming in at 1%,
  • 02:51:22
    we're at 1.9%. But last year, the Texas
  • 02:51:26
    growth premium was pretty small, and so that
  • 02:51:31
    bears watching. Of course, our data is benchmarked,
  • 02:51:35
    pre benchmarked as we call it, and The
  • 02:51:36
    US data is not fully benchmarked for last
  • 02:51:39
    year, so we expect that The US number
  • 02:51:41
    will probably be revised down. But we are
  • 02:51:44
    kind of watching that Texas growth premium because
  • 02:51:46
    we kind of put a lot of stock
  • 02:51:47
    into it. We're used to growing faster than
  • 02:51:49
    the nation. If you look by sector, you
  • 02:51:53
    can see that over the last year, here
  • 02:51:55
    in the lighter blue bars, that job growth
  • 02:51:57
    has been fastest but in our smaller sectors.
  • 02:52:01
    So in finance, construction, and energy, all of
  • 02:52:03
    them are pretty small as a share of
  • 02:52:04
    growth, as a share of employment, sorry. And
  • 02:52:07
    so that's where we've seen some of our
  • 02:52:09
    more robust growth. That's also where we might
  • 02:52:11
    very well see some slowing. Going forward, obviously,
  • 02:52:15
    financial sector is currently, you know there's a
  • 02:52:18
    lot of disruption in the financial sector at
  • 02:52:20
    the moment. You might see slowing job growth
  • 02:52:24
    in that sector even in our region as
  • 02:52:26
    a result. Construction, we expect that they'll be
  • 02:52:30
    contending with larger input costs for building as
  • 02:52:33
    a result of tariffs. And energy, we're seeing
  • 02:52:36
    oil prices sink. Of course, oil prices are
  • 02:52:39
    pretty volatile, but that can affect activity and
  • 02:52:43
    hiring going forward in the energy sector. Our
  • 02:52:46
    largest sectors are kind of the ones that
  • 02:52:48
    are listed toward the left of the chart.
  • 02:52:50
    Trade, transportation, and utilities has had very sluggish
  • 02:52:53
    growth, that's almost 20% of our employment. Professional
  • 02:52:56
    business services is where we get some of
  • 02:52:58
    our most high paying jobs, that's also really
  • 02:53:02
    slowed over the last, you know, the last
  • 02:53:03
    year it's only grown about 1%. So we're
  • 02:53:06
    kind of watching those. Those are large sectors
  • 02:53:08
    that we turn to, you know, those kind
  • 02:53:11
    of are real engines of consistent growth in
  • 02:53:15
    our region. Where do we see slowing? You
  • 02:53:19
    have to really look hard to see any
  • 02:53:23
    indicators that would point toward in the labor
  • 02:53:26
    market point to kind of bad news. Really,
  • 02:53:31
    the unemployment rate, the u three, the baseline
  • 02:53:34
    unemployment rate is not showing much worsening. It's
  • 02:53:36
    still at 4.1%. I think the March US
  • 02:53:39
    data is 4.2%. But again, that's pretty consistent
  • 02:53:45
    with full employment, so not a lot of
  • 02:53:47
    sign yet in the unemployment rate, you know,
  • 02:53:51
    of of excess capacity or or layoffs. But
  • 02:53:55
    if you look at kind of here, I've
  • 02:53:57
    also pictured and the the higher bars there
  • 02:53:59
    are the broader measure of unemployment, so the
  • 02:54:02
    u six, which takes into account discouraged workers,
  • 02:54:05
    and also those are the ones who are
  • 02:54:07
    looking were looking for a job but have
  • 02:54:10
    stopped doing so because they couldn't find one.
  • 02:54:12
    Also, we are including here workers who are
  • 02:54:14
    part time because they can't find a full
  • 02:54:17
    time job. So those are the marginally attached.
  • 02:54:20
    And you can see that now for the
  • 02:54:22
    nation that measure is almost up at 8%.
  • 02:54:25
    So we are watching broader measures. And of
  • 02:54:29
    course there are other measures of layoffs nationally,
  • 02:54:33
    like the Challenger Great Christmas. Those are up
  • 02:54:35
    quite a bit, obviously capturing some of those
  • 02:54:37
    federal government layoffs. In Texas, though, if you
  • 02:54:40
    look at warm layoffs and initial claims, you're
  • 02:54:42
    really not seeing much worsening yet. On migration,
  • 02:54:48
    I just wanted to talk a little bit.
  • 02:54:49
    You know, I mentioned the Texas growth premium.
  • 02:54:53
    We tend to grow a percentage point faster
  • 02:54:55
    in terms of employment growth. We tend to
  • 02:54:57
    grow a percentage point faster in terms of
  • 02:55:00
    GDP growth. I think migration is the main
  • 02:55:02
    reason that we're able to sustain this, growth
  • 02:55:06
    premium. And if you see, here, you'll see
  • 02:55:09
    that we've really had three record years of
  • 02:55:12
    migration to our state. And so these bars
  • 02:55:15
    are showing you net migration into the state.
  • 02:55:17
    They've been running over 400,000 for the last
  • 02:55:20
    three years. The bulk of that last year
  • 02:55:23
    was international migration. Before that, it was pretty
  • 02:55:27
    much half half domestic migration and international. So
  • 02:55:31
    domestic migration is migration from other states. International
  • 02:55:34
    is migration here from other countries. And so
  • 02:55:37
    we really saw these outsized migration trends here
  • 02:55:41
    in the last three years. And I think
  • 02:55:43
    you've read about the if you've opened any
  • 02:55:45
    newspaper or any kind of digital device, you
  • 02:55:49
    know that we had a border migration surge,
  • 02:55:52
    which is in the process of being reversed.
  • 02:55:55
    But we calculate that on we think that
  • 02:55:58
    about over the last three years that probably
  • 02:56:01
    led to about 550,000 extra international migrants to
  • 02:56:05
    Texas. That's about 10% of the total for
  • 02:56:08
    the nation as a whole. So that really
  • 02:56:11
    boosted population growth here. We did have a
  • 02:56:13
    record year of population growth last year, 1.8%.
  • 02:56:17
    So we don't expect this to continue. If
  • 02:56:20
    you look at the border migration, it's way
  • 02:56:22
    way down. Encounters at the border are, you
  • 02:56:25
    know, down 95 year on year. One consequence
  • 02:56:31
    of so much migration to our region, whether
  • 02:56:34
    it's from other states or other countries, is
  • 02:56:36
    that we consistently lead in labor force growth.
  • 02:56:38
    So here I'm comparing labor force growth rates
  • 02:56:42
    to other large states like Illinois, California, and
  • 02:56:45
    New York, and also to The US average,
  • 02:56:47
    and you can just see from the blue
  • 02:56:48
    bars there that Texas just consistently leads in
  • 02:56:51
    labor force growth. And again, this is what
  • 02:56:53
    enables us to have this outsized employment growth
  • 02:56:57
    and outsized economic growth. We've also in our
  • 02:57:03
    Texas business outlook surveys at the Dallas Fed
  • 02:57:06
    asked firms, are you relying on hiring people
  • 02:57:12
    who move here from other states or people
  • 02:57:13
    who move here from other countries? Last year
  • 02:57:16
    was interesting because the share of our firms
  • 02:57:19
    that respond to our surveys, and it's over
  • 02:57:21
    three fifty firms in every in any given
  • 02:57:24
    month, they told us that, you know, 24%
  • 02:57:27
    of them were relying on making those hires,
  • 02:57:30
    you know, of immigrants, and that was up
  • 02:57:33
    almost 10 points from the year prior. So
  • 02:57:35
    there's definitely immigration is feeding into the labor
  • 02:57:41
    market and Texas employers are depending on immigrants
  • 02:57:44
    for hiring. And so as immigration goes down,
  • 02:57:47
    we can expect that hiring will go down.
  • 02:57:52
    Okay. Let me talk a little bit about
  • 02:57:53
    the manufacturing construction boom that's been another major
  • 02:57:57
    major, theme here in the last few years
  • 02:57:59
    of the Texas economy. So we have a
  • 02:58:04
    construction boom in The United States that we
  • 02:58:07
    haven't seen the like of in, gosh, I
  • 02:58:10
    don't know, seventy years. We went back as
  • 02:58:12
    far as the data could take us. I'm
  • 02:58:13
    not showing you all that history here, but
  • 02:58:16
    what I'm showing you in the black line
  • 02:58:18
    is of this manufacturing construction boom in The
  • 02:58:22
    United States that we experienced here in the
  • 02:58:25
    post pandemic period, the black line shows you
  • 02:58:27
    what share of that construction spending was happening
  • 02:58:30
    in Texas. And so that's Texas's share of
  • 02:58:33
    US non residential building and non building. And
  • 02:58:36
    so it's been hovering, you know, at 15
  • 02:58:40
    between 15 to 20% over the last three
  • 02:58:43
    years. So that means that we're again about
  • 02:58:46
    9%, nine point five % of the economy.
  • 02:58:48
    So the fact that we're that's really outsized
  • 02:58:51
    growth in our region. I'm also showing you
  • 02:58:55
    the green sort of the green shaded bars
  • 02:58:58
    and the red shaded bars, and that tells
  • 02:59:00
    you kind of where the bulk of this
  • 02:59:02
    growth is coming from. One is really in
  • 02:59:04
    the power sector, and that's mostly LNG, so
  • 02:59:07
    LNG terminals like the Rio Grande Valley, LNG
  • 02:59:10
    terminal in Brownsville. Otherwise, manufacturing plants in green,
  • 02:59:16
    and that's really driven by chip spending and
  • 02:59:19
    so many, the beginning of the construction of
  • 02:59:21
    so many semiconductor plants of course. Samsung in
  • 02:59:25
    Taylor, Texas, and also TI in Sherman, Texas,
  • 02:59:29
    and and there's more. So it's just been
  • 02:59:32
    it's just been an a tremendous building boom.
  • 02:59:36
    Some of it is related to obviously like
  • 02:59:38
    the CHIPS Act. We have a federal CHIPS
  • 02:59:41
    Act. We have a state CHIPS Act that's
  • 02:59:43
    obviously incentivized some of the semiconductor spending here
  • 02:59:46
    in our state. But some of it and
  • 02:59:49
    some of it's related to the inflation reduction
  • 02:59:51
    act and the and the infrastructure act. But
  • 02:59:54
    I think the bulk of this, at least
  • 02:59:55
    in the power sector in terms of it
  • 02:59:57
    being LNG based, is really related more to
  • 03:00:00
    structural factors and the fact that we are
  • 03:00:02
    with with the shale boom, we produce you
  • 03:00:05
    know so much natural gas and there's so
  • 03:00:07
    much demand overseas and there's price for natural
  • 03:00:11
    gas is so much higher overseas that there's
  • 03:00:13
    just a huge incentive to build these LNG
  • 03:00:16
    terminals and export the natural gas. Here you
  • 03:00:20
    can see on a national basis really what
  • 03:00:23
    this construction spending in sectors as defined by
  • 03:00:27
    the Census Bureau, in this case, where they're
  • 03:00:29
    concentrated. And here you can see really from
  • 03:00:31
    the orange surge in the orange line there,
  • 03:00:35
    can see that so much of this was
  • 03:00:37
    really computer related. So that's the semiconductor spending.
  • 03:00:42
    The blue line is significant though. The chemical
  • 03:00:44
    spending, that's petrochemicals, and that's where Texas is
  • 03:00:48
    also a huge player so much. Again, because
  • 03:00:51
    of the low price of natural gas, we
  • 03:00:53
    can really compete internationally with our petrochemical products.
  • 03:00:58
    And so we're huge exporters of petrochemical products.
  • 03:01:01
    And so we continue to add to that
  • 03:01:03
    infrastructure along the Gulf Coast. And you know
  • 03:01:07
    again we'll talk about tariffs in a minute
  • 03:01:10
    but that's another area where I'm a little
  • 03:01:11
    bit concerned in terms of what happens to
  • 03:01:15
    again the the trading you know our competitiveness
  • 03:01:20
    in tariff environment. Lastly on you all mentioned
  • 03:01:25
    data centers earlier and I was really shocked
  • 03:01:27
    to see the load growth that's coming from
  • 03:01:29
    data centers. Of course, lot of spending. The
  • 03:01:32
    data center spending, as you can see here,
  • 03:01:34
    this is for Texas. We went project by
  • 03:01:36
    project in the construction spending data to try
  • 03:01:39
    to piece together how much of the projects
  • 03:01:42
    in Texas were data centers, how many were
  • 03:01:44
    semiconductors. And when you look at it really
  • 03:01:47
    before the pandemic, it was there for data
  • 03:01:51
    centers. There was very little, nothing really in
  • 03:01:53
    semiconductor manufacturing. But after the pandemic, so after
  • 03:01:57
    the again, the chips acts passed and so
  • 03:01:59
    forth in 2020, the earlier period 2020 to
  • 03:02:03
    2022 in the blue line and then or
  • 03:02:06
    in the blue bar, and then 2023 in
  • 03:02:08
    the red bar, can just see just amazing,
  • 03:02:11
    you know, 12,000,000,000 in semiconductors, 15,000,000,000 in 2023,
  • 03:02:16
    and then data centers also, you know, so
  • 03:02:20
    the investment there so sizable that it actually
  • 03:02:23
    rivals the chip spending, which I was also
  • 03:02:26
    surprised to see. On energy, I wanted to
  • 03:02:34
    just say a few remarks about oil production.
  • 03:02:37
    You're probably familiar. We are still at record
  • 03:02:40
    levels of oil production in the state, about
  • 03:02:43
    5,600,000 barrels per day. And that's really the
  • 03:02:47
    black line here and the most fascinating thing
  • 03:02:50
    about record oil production in Texas is that
  • 03:02:53
    the blue line is the rig count and
  • 03:02:54
    you know they moved they used to move
  • 03:02:56
    together and now they move in opposite directions
  • 03:02:58
    and that really is a fascinating phenomenon in
  • 03:03:00
    the sense that the efficiency and productivity enhancements
  • 03:03:04
    to drilling are so pronounced that over time
  • 03:03:07
    the blue line has just been trending down
  • 03:03:09
    as the black line trends up, which means
  • 03:03:12
    that, you know, we needed 900 rigs basically
  • 03:03:15
    to produce, you know, half of the oil
  • 03:03:18
    in 2014, not quite half, but now we
  • 03:03:22
    can do twice the oil with two fifty
  • 03:03:25
    four rigs. So it really is a tremendous
  • 03:03:27
    increase in productivity and efficiency in the oil
  • 03:03:30
    field in terms of in terms of what
  • 03:03:34
    we can do now with new new methodologies
  • 03:03:38
    and new and and the innovation. I guess
  • 03:03:42
    you'll notice that the black line, so the
  • 03:03:45
    Texas crude oil production has turned down a
  • 03:03:47
    little bit at the very end. We are,
  • 03:03:49
    know, it has it has come down here
  • 03:03:50
    and nationally as well, and so we'll we'll
  • 03:03:54
    see where that leads us. You know, the
  • 03:03:56
    biggest explanatory factor for crude oil production is
  • 03:04:00
    the price of oil, so I realized when
  • 03:04:04
    I put this chart together, which really only
  • 03:04:06
    is like one week old, but it's already
  • 03:04:08
    very outdated, so this is the Dallas Fed
  • 03:04:12
    Energy Survey. We ask respondents what are their
  • 03:04:14
    expectations for oil prices in six months, in
  • 03:04:17
    one year, in two years, and so forth.
  • 03:04:20
    And so at the time, oil prices were
  • 03:04:23
    around 70, and our respondents to our energy
  • 03:04:26
    survey were predicting they were going to remain
  • 03:04:28
    around 70 or right under that really in
  • 03:04:31
    the next six months, in the next year,
  • 03:04:32
    and so forth. Of course, in the meantime,
  • 03:04:35
    we've seen a big drop in oil price,
  • 03:04:38
    I think mostly due to expectations of lower
  • 03:04:42
    global oil demand as a result of slower
  • 03:04:45
    economic growth, perhaps due to the trade war
  • 03:04:51
    that's breaking out. And the significance of the
  • 03:04:55
    lower oil price is really in that little
  • 03:04:57
    text box. So we have a break even
  • 03:05:00
    price for oil, which means that in order
  • 03:05:04
    to drill a new well, oil producers need
  • 03:05:07
    a certain price. For large producers, that price
  • 03:05:10
    is $61, so that's where we are right
  • 03:05:13
    now today. But for small producers, they face
  • 03:05:17
    higher costs, their, breakeven price, so price they
  • 03:05:21
    need to profitably drill another well is $66
  • 03:05:26
    So we're below that now. So I think
  • 03:05:29
    it stands to reason if oil prices stay
  • 03:05:32
    where they are, and who knows if that's
  • 03:05:34
    going to be the case. But you'll see
  • 03:05:37
    less drilling this year. The Dallas Fed Energy
  • 03:05:43
    Survey also shows this is, again, before this
  • 03:05:47
    is data from a couple weeks ago. But
  • 03:05:50
    even if you look at business activity, capital
  • 03:05:52
    expenditures, company outlook, here you can see there
  • 03:05:54
    really hasn't happened much. Know, really in the
  • 03:05:58
    last couple of years, oil producers have been
  • 03:06:03
    pretty just steady as she goes there and
  • 03:06:06
    haven't seen a big pickup in investment, not
  • 03:06:09
    even with the change in administration. So they're
  • 03:06:11
    kind of seeing things remaining as they are
  • 03:06:13
    in terms of their investment activity. I think
  • 03:06:17
    one, if you read the comments which are
  • 03:06:20
    public from the energy survey on the Dallas
  • 03:06:22
    Fed website, you'll see that while they're optimistic
  • 03:06:26
    about the less burdensome regulation on their sector
  • 03:06:30
    going forward, they are concerned about the rising
  • 03:06:33
    input costs that again much of that from
  • 03:06:36
    for example steel and aluminum tariffs, steel in
  • 03:06:39
    particular, you need a lot of steel if
  • 03:06:41
    you're going to lay down the pipe for
  • 03:06:43
    oil. Okay, turning to electricity. So I just
  • 03:06:49
    wanted to show and you guys know this
  • 03:06:51
    so much better than I do I don't
  • 03:06:53
    really even know industry jargon, so you have
  • 03:06:55
    to forgive me. I'm kind of a novice
  • 03:06:57
    here at ERCOT. But so but I was
  • 03:07:00
    curious to see how much electricity demand and
  • 03:07:04
    consumption, if you will, has increased over time
  • 03:07:07
    in Texas compared to The US, and so
  • 03:07:10
    this is kind of just charting that, which
  • 03:07:12
    I think is very interesting. There's a number
  • 03:07:14
    of things, as you all know, just having
  • 03:07:18
    gone through your forecast exercise that this is
  • 03:07:20
    some of this is economic growth and population
  • 03:07:22
    growth certainly, but hot weather and then of
  • 03:07:26
    course electrification, not least in the oil field
  • 03:07:29
    we were just talking about. But I thought
  • 03:07:32
    the interesting thing was that I guess in
  • 03:07:34
    Texas we're kind of used electricity consumption growing
  • 03:07:37
    whereas in The US it's a big game
  • 03:07:39
    changer, right, because they didn't have much growth
  • 03:07:41
    in demand for for quite some time. We
  • 03:07:45
    did some research a couple years ago on
  • 03:07:48
    the summer of twenty twenty three when we
  • 03:07:50
    had extremely hot summer, if you remember, and
  • 03:07:52
    we wanted to know how do those hot
  • 03:07:55
    summers, how does that hot weather affect economic
  • 03:07:58
    activity here in Texas in our region versus
  • 03:08:02
    other places, and so these are kind of
  • 03:08:05
    the negative GDP effects of a rise of
  • 03:08:11
    one degree in average summer temperature has actually,
  • 03:08:16
    as you can see here, a point four
  • 03:08:19
    percentage point effect, a negative point four percentage
  • 03:08:24
    point effect on summer GDP in the state,
  • 03:08:27
    which is really interesting. It's about twice that
  • 03:08:29
    of the effect nationally, and so we do
  • 03:08:32
    suffer here in the summertime. Because we start
  • 03:08:35
    out with such high temperatures, the impact on
  • 03:08:38
    GDP of rising, you know, of consistently higher
  • 03:08:41
    temperatures in the summer actually depressed economic activity
  • 03:08:44
    much more so than elsewhere, which I thought
  • 03:08:47
    was interesting. The other thing that we learned
  • 03:08:50
    from the summer of twenty twenty three was
  • 03:08:52
    that when you have a hotter summer and
  • 03:08:54
    you have less activity in the summer, you
  • 03:08:57
    have more activity in the fall and spring.
  • 03:08:59
    So it's not just bad news, but I
  • 03:09:02
    don't know, you know, to what extent ERCOT
  • 03:09:04
    follows. We we talked about shoulder months earlier,
  • 03:09:06
    right? So that was interesting. So here you
  • 03:09:08
    can see that, you know, at least you
  • 03:09:11
    have that that spillover effect. So if you
  • 03:09:14
    have a very hot summer, those warmer temperatures
  • 03:09:17
    in fall and spring, if they manifest, they
  • 03:09:19
    will result in higher activity, higher economic activity
  • 03:09:23
    in those shoulder months versus the summer months.
  • 03:09:26
    So that was interesting. That works for industries
  • 03:09:29
    that can spread their activity to fall and
  • 03:09:33
    spring but you think of certain hospitality and
  • 03:09:38
    leisure industries that maybe are taking advantage of
  • 03:09:41
    kids' summer breaks, it's harder for them to
  • 03:09:43
    take advantage of warmer weather in the fall
  • 03:09:45
    and spring when the kids are in school.
  • 03:09:50
    All right. So let's talk a little bit
  • 03:09:54
    about international trade. So I will say that
  • 03:09:59
    we are just before we start out, I
  • 03:10:02
    mean presumably you know this, but we are
  • 03:10:04
    the biggest trading state in the nation, so
  • 03:10:07
    no state has more exports and imports than
  • 03:10:10
    Texas. So and really the difference is actually
  • 03:10:13
    quite large. Of course, a lot of our
  • 03:10:15
    trade is with Mexico, but we also have
  • 03:10:18
    significant trade with with other nations. So so
  • 03:10:22
    we are vulnerable to tariffs, I guess, is
  • 03:10:25
    what I would kind of my preamble on
  • 03:10:28
    this. In our Texas business outlook surveys, we
  • 03:10:32
    asked asked Texas businesses and this is, of
  • 03:10:36
    course, before we knew what these reciprocal tariffs
  • 03:10:41
    would look like. And so we were still
  • 03:10:44
    our respondents were still kind of operating in
  • 03:10:47
    the dark so we asked them, please comment
  • 03:10:49
    on how US trade policy uncertainty and tariffs
  • 03:10:52
    are impacting your business if at all. And
  • 03:10:54
    so, know, in terms of the comments, we
  • 03:10:57
    went through all the comments and we got
  • 03:10:58
    a lot of responses and about 38% of
  • 03:11:03
    those comments at the time, and again this
  • 03:11:05
    is before, you know, we saw what happened
  • 03:11:07
    last week, but 38% were negative, only 3%
  • 03:11:11
    were positive. So as you know, tariffs may
  • 03:11:13
    protect some industries, and so if you're purely,
  • 03:11:16
    you know a domestic producer, your supply chains
  • 03:11:18
    are domestic and you're not importing your inputs
  • 03:11:22
    then perhaps you will benefit. But 38% of
  • 03:11:26
    responses were negative, 3% were positive and of
  • 03:11:29
    course at the point at that point in
  • 03:11:30
    time a lot of people didn't know, you
  • 03:11:33
    know, how they were going to be impacted.
  • 03:11:35
    So we expect that on net this is
  • 03:11:38
    going to be a negative for Texas business.
  • 03:11:41
    When in their comments and we tried to
  • 03:11:43
    sort through the comments and tried to put
  • 03:11:47
    different comments from our business contacts, and you
  • 03:11:50
    can read all these comments on our website.
  • 03:11:52
    Anyway, we put them into buckets, and by
  • 03:11:54
    far, you know, the number one response was,
  • 03:11:57
    you know, in what way is this negative
  • 03:11:58
    for your business? And it's increasing costs, costs
  • 03:12:01
    which they'll have to pass on to their
  • 03:12:03
    customers. The uncertainty is making it hard to
  • 03:12:06
    plan. They're delaying projects. They're foreseeing lower demand
  • 03:12:12
    as a result of the higher prices you
  • 03:12:15
    know, and and so on, supply chain disruptions
  • 03:12:18
    and concerns about inflation and so forth. So
  • 03:12:20
    there's a number of worries here from our
  • 03:12:24
    survey respondents. We did a scenario analysis when
  • 03:12:29
    before the, you know, reciprocal tariffs were announced,
  • 03:12:34
    we were still operating under the scenario of
  • 03:12:37
    25% tariffs on Canada and Mexico. And so
  • 03:12:42
    we did kind of just sort of a
  • 03:12:44
    standard scenario analysis of what the impact would
  • 03:12:47
    those of those tariffs on Texas on the
  • 03:12:51
    Texas economy, and we found about a 1.5
  • 03:12:54
    percentage point decline in GDP. So that would
  • 03:12:56
    be cutting GDP growth in half about in
  • 03:12:59
    an average year, a decline in employment of
  • 03:13:03
    about 100,000 jobs, and an increase in the
  • 03:13:06
    unemployment rate of about point eight percentage points.
  • 03:13:10
    I'm also listing here the Pearman Group has
  • 03:13:13
    a similar estimate or similar scenario analysis, and
  • 03:13:16
    I'm listing their numbers there for your reference.
  • 03:13:18
    They have a larger employment impact and a
  • 03:13:20
    larger slightly larger GDP impact. We have not
  • 03:13:24
    been able to look in terms of the
  • 03:13:29
    effective tariff rate of what was announced last
  • 03:13:31
    week. We haven't yet run the numbers for
  • 03:13:34
    Texas. My sense is that, at least nationally,
  • 03:13:39
    it's not going to be very different from
  • 03:13:41
    what you see here. Nationally, if the reciprocal
  • 03:13:44
    tariffs stand, from what I understand, the effective
  • 03:13:48
    tariff rate has gone from a 3% tariff
  • 03:13:50
    rate to a 20% tariff rate, which according
  • 03:13:54
    to the investment bank newsletters, if you read
  • 03:13:56
    those, correspond to about a two percentage point
  • 03:14:00
    decline in GDP growth and about a two
  • 03:14:02
    percentage point increase in inflation. So that gives
  • 03:14:07
    you an idea of of what you know
  • 03:14:09
    people out there, the calculations that they are
  • 03:14:12
    running. Okay, in terms of the outlook, there's
  • 03:14:17
    certainly a lot of uncertainty right now. And
  • 03:14:21
    so obviously, this is affecting, again, firms' abilities
  • 03:14:27
    to plan for the future, especially, obviously, any
  • 03:14:31
    investment projects and so forth. In terms of
  • 03:14:34
    firms, what they're expecting for cost and price
  • 03:14:37
    inflation in 2025 here, just you know I
  • 03:14:40
    draw your attention to sort of the last
  • 03:14:42
    set of bars here on the on the
  • 03:14:44
    right end of the slide on selling prices.
  • 03:14:48
    If you look at selling prices last year,
  • 03:14:50
    actually firms are saying this year selling prices
  • 03:14:52
    are going to be rising more than they
  • 03:14:55
    did last year. So and this is before
  • 03:14:57
    again, the survey ran before the tariff announcement
  • 03:15:01
    last week. Again, before the tariff announcement last
  • 03:15:06
    week, we asked what are the biggest concerns,
  • 03:15:09
    you know, in terms of your outlook and
  • 03:15:11
    recession concerns really increased in March. So 50%
  • 03:15:17
    of respondents to our Texas Business Outlook survey
  • 03:15:20
    said that demand was their biggest concern, followed
  • 03:15:23
    by domestic policy uncertainty and inflation. Our employment
  • 03:15:29
    forecast for 2025 for the year, when the
  • 03:15:32
    year started out, was really 1.6%. That's below
  • 03:15:37
    trend. It's similar to last year. But I
  • 03:15:41
    think that really the risks to this forecast
  • 03:15:45
    are to the downside, again, for all the
  • 03:15:48
    reasons that I've been telling you. So let
  • 03:15:51
    me summarize. Business leader optimism has faded and
  • 03:15:55
    economists, have revised their forecasts down. Tariffs are
  • 03:15:59
    the main reason. Progress on inflation has slowed
  • 03:16:02
    and recession probability has risen. Inflation expectations have
  • 03:16:06
    also risen and consumer confidence has fallen. In
  • 03:16:10
    Texas, resilient growth is our baseline case, but
  • 03:16:14
    with risks tilted to the downside, The headwinds
  • 03:16:17
    again are tariffs, but also sharply slower immigration
  • 03:16:21
    and the rollback of federal government spending. Tailwinds
  • 03:16:25
    again, we haven't seen those yet, but if
  • 03:16:27
    they materialize here in the second half of
  • 03:16:29
    the year or in 2026, that would be
  • 03:16:32
    things like deregulation perhaps, tax cuts, and of
  • 03:16:36
    course here in Texas we're fortunate in that,
  • 03:16:40
    know, for our state's robust business climate which
  • 03:16:43
    continues to be an asset in good times
  • 03:16:45
    and bad, and our budget surplus, which hopefully
  • 03:16:49
    the legislature will spend on us here shortly.
  • 03:16:53
    Thank you, sir. Thank you, Bea. Let me
  • 03:16:58
    start with questions if I can. So for
  • 03:17:02
    headwinds we've got tariffs. For a potential tailwind
  • 03:17:05
    we've got the extension of the tax cuts
  • 03:17:08
    from 2017. We've got deregulations potential tailwind. And
  • 03:17:12
    then here in Texas lower energy prices are
  • 03:17:15
    both a tailwind and a headwind. So if
  • 03:17:18
    you were to mash all that together assume
  • 03:17:20
    all those came true, what's the net impact
  • 03:17:24
    on the economy in your from your perspective?
  • 03:17:29
    Well from what I think it's a net
  • 03:17:33
    negative in terms of the outlook so because
  • 03:17:36
    we are the world's largest energy producer you
  • 03:17:39
    know in The United States and a big
  • 03:17:40
    part of that is Texas actually lower energy
  • 03:17:43
    prices are net net bad for us so
  • 03:17:49
    yeah because we're energy exporters on net so
  • 03:17:53
    you know if energy oil prices natural gas
  • 03:17:56
    prices are lower that that hurts us on
  • 03:18:01
    average in the state. And given that we
  • 03:18:04
    haven't seen the impact yet of deregulation, and
  • 03:18:09
    if we assume that the tax cuts are
  • 03:18:12
    priced in to expectations because everyone's kind of
  • 03:18:15
    been expecting even if, you know sort of
  • 03:18:17
    the other side would have won the election
  • 03:18:19
    we were they also said they were going
  • 03:18:20
    to have tack both you know extend the
  • 03:18:22
    TCJA. So if that's priced in and deregulation
  • 03:18:28
    you know probably will not have a big
  • 03:18:31
    enough impact to kind of tip the scale,
  • 03:18:34
    then I think you know on net this
  • 03:18:36
    is a negative outlook. Okay, thanks. I think
  • 03:18:40
    you mentioned a post tariff inflation estimate but
  • 03:18:45
    I missed it. What was about three slides
  • 03:18:48
    back did you? Oh yeah, it wasn't on
  • 03:18:51
    the slide. I'm just kind of citing the
  • 03:18:54
    sort of the investment bank newsletters. This is
  • 03:18:56
    not any kind of Fed intelligentsia. But if
  • 03:19:00
    you just look at sort of the investment
  • 03:19:02
    bank newsletters, they estimate that if you go
  • 03:19:06
    from an effective tariff rate of 3% to
  • 03:19:09
    20%, which we estimate with the reciprocal tariffs
  • 03:19:13
    we're going to be at a 20% tariff
  • 03:19:17
    rate, then the impact of that on GDP
  • 03:19:21
    growth is possibly to as much as two
  • 03:19:24
    percent two percentage point decline in GDP growth.
  • 03:19:28
    That would so if we're growing at 2%
  • 03:19:30
    now, that takes you to zero. And to
  • 03:19:34
    you know, as much as a two percentage
  • 03:19:35
    point increase in inflation. So so that but
  • 03:19:41
    of course yeah those are the ballparks and
  • 03:19:43
    there's big ranges around those and there's big
  • 03:19:45
    question marks about those that's just kind of
  • 03:19:47
    the scenario analysis that that I've been reading
  • 03:19:50
    you know sort of outside. Thanks. One more
  • 03:19:53
    question. There's been a lot of debate about
  • 03:19:55
    the impact of tariffs on U. S. Manufacturing
  • 03:19:59
    jobs is looking on a U. S. Basis
  • 03:20:03
    is that the Fed had a chance to
  • 03:20:05
    look at what the impact of its estimates
  • 03:20:08
    of the impact of tariffs on manufacturing jobs
  • 03:20:15
    nationwide? So we haven't done anything forward looking
  • 03:20:19
    on that. We are actually on Thursday, and
  • 03:20:22
    you're welcome to come, having a conference at
  • 03:20:25
    the Dallas Fed where actually one of the
  • 03:20:28
    economists is bringing a research paper where he
  • 03:20:30
    looked at the effect of the twenty eighteen
  • 03:20:32
    tariffs on US manufacturing jobs in the first
  • 03:20:36
    Trump administration. But I think what they find
  • 03:20:39
    is that whereas there were some gains, they
  • 03:20:44
    were outweighed by losses among manufacturers that depend
  • 03:20:48
    on foreign inputs. And in that case, it
  • 03:20:51
    was Chinese inputs that were, you know, subject
  • 03:20:53
    to the 20% tariffs. So the problem is
  • 03:20:56
    that we are so our manufacturing industry and
  • 03:20:59
    our supply chains are so entrenched in the
  • 03:21:02
    global economy that so many businesses reply, you
  • 03:21:07
    know, depend and rely on foreign inputs that,
  • 03:21:11
    you know, the tariff whereas in the long
  • 03:21:14
    run it might benefit, you know, domestic production.
  • 03:21:18
    But in the short to medium run you're
  • 03:21:20
    going to have a lot of disruption just
  • 03:21:22
    because we're so reliant on foreign supply chains.
  • 03:21:25
    Okay, thanks. That's helpful. Okay. Questions from the
  • 03:21:29
    rest of the board or management? Any questions?
  • 03:21:34
    Okay. Well, you. That was very informative. We
  • 03:21:37
    appreciate your time here at ERCOT today and
  • 03:21:40
    look forward to having you come back and
  • 03:21:42
    give us an update soon. Great. Thank you,
  • 03:21:45
    sir. Thank you. With that, we'll move on
  • 03:21:48
    to agenda item 10, which is a reliability
  • 03:21:52
    market update. Brandon Gleason is presenting. Brandon, would
  • 03:21:55
    you walk us through this? Thank you, Bill.
  • Item 10 - Reliability Monitor Update
    03:22:07
    Good morning, ERCOT Board of Directors. We wanted
  • 03:22:10
    to provide you a brief update regarding a
  • 03:22:14
    important but less known role that ERCOT has,
  • 03:22:17
    that is serving as the reliability monitor. And
  • 03:22:21
    three key takeaways today. First, we've seen an
  • 03:22:24
    increase in volume of the incident reviews that
  • 03:22:26
    we've analyzed. We've also seen an increase in
  • 03:22:29
    volume of the matters we've referred to the
  • 03:22:31
    PUC for enforcement. And also I just want
  • 03:22:33
    to highlight that we're considering based on the
  • 03:22:36
    case volume that we have instituting a streamlined
  • 03:22:38
    review process that we think will help cut
  • 03:22:41
    down on the backlog of cases that we're
  • 03:22:43
    developing. So as a background here, ERCOT was
  • 03:22:48
    designated as the reliability monitor in November of
  • 03:22:51
    'twenty two. And before that, there was a
  • 03:22:54
    dual effort between the PUC and ERCOT to
  • 03:22:57
    analyze various reliability issues at the state level
  • 03:23:00
    concerning both ERCOT and market participants. Prior to
  • 03:23:03
    that, of course, it was Texas RE that
  • 03:23:05
    handled the responsibility. And so our core function
  • 03:23:08
    as the reliability monitor with respect to ERCOT
  • 03:23:10
    is analyzing state reliability compliance issues. And that
  • 03:23:15
    applies to both ERCOT market participants and ERCOT
  • 03:23:18
    Inc. And so once we complete this analysis,
  • 03:23:21
    we essentially forward these cases to the PUC
  • 03:23:24
    for enforcement. And of course, during the enforcement
  • 03:23:26
    process, we serve in a support role providing
  • 03:23:29
    data, additional analysis. And in the event an
  • 03:23:33
    enforcement matter was contested and went on, we
  • 03:23:36
    would also provide support there. And just as
  • 03:23:41
    far as what the process is for the
  • 03:23:43
    case intake, again, this is just state reliability
  • 03:23:47
    requirements. Market aspects go to IMM and of
  • 03:23:50
    course there's the NERC, the Federal Reliability Framework
  • 03:23:53
    that's handled by Texas RE and NERC. And
  • 03:23:55
    so here at ERCOT, essentially there's an email
  • 03:23:58
    address ermircot dot com where market participants can
  • 03:24:02
    self report. If ERCOT folks see potential compliance
  • 03:24:05
    issues, they can forward potential incident reviews. And
  • 03:24:09
    then also there's just routine monitoring and analysis
  • 03:24:11
    that ERCOT's doing that results in potential non
  • 03:24:15
    compliance analysis as well. And so you'll see
  • 03:24:18
    here on this chart that ERCOT receives this
  • 03:24:21
    information from various sources. And then there's an
  • 03:24:24
    initial determination whether the matter is indeed reliability
  • 03:24:27
    related. If it's not and it's not market
  • 03:24:30
    related, then this gets funneled to the ERCOT
  • 03:24:32
    legal department and these violations traditionally appear in
  • 03:24:36
    a quarterly report to the PUC identifying ERCOT
  • 03:24:40
    Inc. Compliance violations. And if they are indeed,
  • 03:24:43
    if the incidents are in fact reliability related,
  • 03:24:47
    they are triaged to the department in ERCOT.
  • 03:24:50
    They're assigned value, and they go through the
  • 03:24:52
    incident review processes. It's important to note that
  • 03:24:56
    every ERCOT employee that participates in the signs
  • 03:25:00
    a code of conduct agreeing to be independent
  • 03:25:04
    and be cognizant, of course, of potential conflicts
  • 03:25:06
    of interest. Okay. Last April, we came to
  • 03:25:11
    you and identified how many cases incident reviews
  • 03:25:15
    had been forwarded to the PUC. Since last
  • 03:25:18
    April, our case volume has increased at just
  • 03:25:22
    less than 12 referrals per month. And then
  • 03:25:26
    we've referred 75 analyses to the PUC for
  • 03:25:31
    enforcement since last April. And one thing that
  • 03:25:34
    I want to highlight on this slide is
  • 03:25:36
    that you can see that our intake is
  • 03:25:38
    almost 12 matters per month and our disposal
  • 03:25:42
    is less than five. And so we're actively
  • 03:25:45
    increasing the backlog of incident reviews that ERCOT
  • 03:25:48
    is in the process of evaluating. And one
  • 03:25:52
    of the plans that we have in order
  • 03:25:54
    to help ease that backlog, and we've been
  • 03:25:56
    working with the PUC on this, is developing
  • 03:25:58
    a more streamlined process for lower risk issues
  • 03:26:02
    that will, in theory, hope them move through
  • 03:26:05
    the process sooner in order to get that
  • 03:26:07
    backlog down and resolve these matters. Now of
  • 03:26:11
    course, now that we've been doing this for
  • 03:26:13
    about two and a half years, we've started
  • 03:26:15
    to see what the results of ERCOT's analysis
  • 03:26:18
    and the PUC enforcement is. And this is
  • 03:26:20
    a summary of the types of matters that
  • 03:26:23
    have been settled ultimately and the settlement amounts
  • 03:26:27
    there on the right column. So you can
  • 03:26:28
    see by the date of these matters when
  • 03:26:30
    they came in 2022, '20 '20 '3 and
  • 03:26:33
    as they cycle through the process you see
  • 03:26:34
    the ultimate resolution here. So those are PUC
  • 03:26:37
    finalized settlements. And then these are pending settlements,
  • 03:26:41
    settlements that are still in the pipeline in
  • 03:26:43
    the process of being evaluated. Okay. And then
  • 03:26:47
    turning to the budget. Last year, we had
  • 03:26:50
    a budget of approximately $1,800,000 It's increased slightly
  • 03:26:53
    for calendar year 2024 and the primary driver
  • 03:26:57
    there is an increase in headcount. There's another
  • 03:27:01
    employee on the compliance side that accounts for
  • 03:27:04
    that increase there. Okay. And before we finish
  • 03:27:10
    up here, I just want to highlight take
  • 03:27:11
    this opportunity to highlight all of the guests,
  • 03:27:13
    members, market participants that we may maintain a
  • 03:27:16
    robust reliability monitor web page here. And of
  • 03:27:20
    course, the key here is ercot.com. We invite
  • 03:27:24
    folks to submit self reports. If you see
  • 03:27:27
    something about compliance regarding a market participant regarding
  • 03:27:31
    ERCOT, please do report it to that email
  • 03:27:33
    address and we'll get it triaged and handled.
  • 03:27:36
    And with that, I'd be happy to answer
  • 03:27:37
    any questions. Julie? Brandon, I have a question.
  • 03:27:42
    If we go back to your slide where
  • 03:27:44
    you're talking about the number of incidences in
  • 03:27:45
    the last year, how can you help us
  • 03:27:48
    put that in perspective? If we were looking
  • 03:27:50
    at parts per million defects on the grid,
  • 03:27:53
    is were there a thousand chances to have
  • 03:27:56
    these reliability investigations? Put it in perspective? That's
  • 03:28:02
    a good question. I think that the biggest
  • 03:28:04
    perspective is if you think about how many
  • 03:28:06
    market participants there are, how many sections of
  • 03:28:09
    the protocols there are, PUC substantive rules, other
  • 03:28:12
    binding documents, a tremendous amount of participants and
  • 03:28:16
    potential violations. And so I think that does
  • 03:28:19
    put it in perspective here. You know, we're
  • 03:28:21
    dealing with 12 a month out of, you
  • 03:28:24
    know, guess thousands and thousands of requirements, of
  • 03:28:27
    course. And so hopefully that adds a little
  • 03:28:29
    bit of perspective there. Well, think that's important
  • 03:28:32
    that we understand the size of the denominator
  • 03:28:38
    in this equation. So overall, the grid is
  • 03:28:42
    operating extremely well. I think that's fair, yes,
  • 03:28:45
    absolutely, given the amount of requirements and market
  • 03:28:48
    participants. Any other questions, Brandon? Okay. Thank you.
  • 03:28:58
    We'll move on now to agenda item 11,
  • 03:29:01
    which is the Lancium patent license agreement disclosure.
  • 03:29:05
    Chad Sealy is going to present. Chad? All
  • Item 11 - ERCOT Lancium Patent License Agreement Disclosure
    03:29:15
    right. Good morning. Two lawyers in a row.
  • 03:29:18
    Jeez, it is National Be Nice to Lawyers
  • 03:29:23
    Day. You can look it up, it's a
  • 03:29:26
    real thing. Every April is National Be Nice
  • 03:29:31
    to Lawyers Day. So that's why you get
  • 03:29:32
    two lawyers in a row. I move we
  • 03:29:34
    dispense with that one. It's been around for
  • 03:29:38
    a while, Bill, sorry. It's established. All right,
  • 03:29:42
    I'll make this pretty quick. So I really
  • 03:29:45
    want to take an opportunity to come and
  • 03:29:48
    disclose to the Board that we're going to
  • 03:29:51
    enter into an agreement with a more participant,
  • 03:29:53
    Lancium. This is a long standing issue that's
  • 03:29:56
    been kind of playing around the surface in
  • 03:29:59
    the stakeholder process for a couple of years
  • 03:30:01
    dealing with our controllable load resource program. And
  • 03:30:06
    it's a result of Lancium having a portfolio
  • 03:30:09
    of patents that could implicate that CLR program.
  • 03:30:13
    And stakeholders have been talking about this again
  • 03:30:15
    for about two years. It started in the
  • 03:30:17
    large load task force. ERCOT was asked to
  • 03:30:20
    look at it. There's been disputes around the
  • 03:30:23
    patents. There's been arguments around the patents that's
  • 03:30:26
    been going on with the stakeholders. ERCOT has
  • 03:30:28
    been engaged with Lanciam for quite some time
  • 03:30:31
    trying to understand the impact of what those
  • 03:30:34
    patents could mean to our CLR program. And
  • 03:30:37
    I'm here today to talk about an amicable
  • 03:30:40
    resolution that results in a no cost outcome
  • 03:30:44
    for ERCOT to have a license in which
  • 03:30:46
    we can then sublicense to any participant that
  • 03:30:49
    wants to participate as a CLR or a
  • 03:30:51
    load resource in our program. And it's important
  • 03:30:54
    to disclose that Lanciam is a mark participant.
  • 03:30:59
    They are a queasy load serving entity and
  • 03:31:02
    resource entity. Of course, making this disclosure with
  • 03:31:04
    the Board is important because we normally don't
  • 03:31:07
    enter into contracts with participants except for our
  • 03:31:10
    standard form agreements that they are actively participating
  • 03:31:14
    in the ERCOT market. But here this is
  • 03:31:16
    a good outcome in which we can resolve
  • 03:31:19
    this issue for the ERCOT region. And so
  • 03:31:22
    I do want to thank Michael McNamara, who's
  • 03:31:24
    CEO of Lancium and his team along with
  • 03:31:27
    Eric Goff that served as a consultant with
  • 03:31:30
    Lancium for all the discussions that we've had
  • 03:31:32
    over the last several months to come to
  • 03:31:34
    an amicable resolution. So what does this mean
  • 03:31:37
    at the end of the day? There was
  • 03:31:38
    this patent four thirty three patent and a
  • 03:31:42
    series of patents underneath that, a family of
  • 03:31:45
    patents that was alleged to implicate load resources
  • 03:31:50
    that wanted to participate in CLR in which
  • 03:31:53
    they would dynamically respond to a dispatch instruction
  • 03:31:56
    by ERCOT. It doesn't impact any type of
  • 03:31:59
    load resource. It has to be a load
  • 03:32:01
    resource that would be acting under this program
  • 03:32:04
    that would implicate the patents that Lancium had.
  • 03:32:09
    We obviously want to continue to see more
  • 03:32:11
    and more participation in the CLR program and
  • 03:32:15
    our understanding from our participants that this was
  • 03:32:17
    acting as a barrier for them to register
  • 03:32:21
    as a CLR and then be dispatched by
  • 03:32:23
    SCED ultimately. There is also a Nodal Protocol
  • 03:32:31
    Revision Request NPRR1262 that's pending at
  • 03:32:34
    PRS in which one participant filed to try
  • 03:32:38
    to write around the patent to resolve that
  • 03:32:41
    issue in a way. And so for a
  • 03:32:43
    couple of months, we've been engaged with the
  • 03:32:44
    stakeholders at the PRS committee, tabling that revision
  • 03:32:49
    request to see if we could come to
  • 03:32:50
    an amicable resolution on the Lancian patent issue.
  • 03:32:55
    So that NPRR is still sitting at PRS
  • 03:32:58
    and we will be talking to PRS, I
  • 03:33:00
    believe that's tomorrow about the same matter to
  • 03:33:02
    see if we can get that dismissed. So
  • 03:33:07
    working with Lancium, Lancium has offered up a
  • 03:33:10
    no cost license to ERCOT to resolve this
  • 03:33:13
    issue. We entered into a terms sheet with
  • 03:33:18
    Lanium back in February. And ultimately this is
  • 03:33:23
    just for the ERCOT region to resolve this
  • 03:33:26
    potential barrier to entry concern for market participants
  • 03:33:30
    to participate in the CLR program or as
  • 03:33:32
    a load resource offering ancillary services. We've notified
  • 03:33:39
    PRS through comments filed with Lancium and ERCOT
  • 03:33:42
    that we'd enter into this term sheet and
  • 03:33:44
    that we were going to work on a
  • 03:33:46
    license agreement. On this slide are the high
  • 03:33:51
    level terms of the license agreement. You also
  • 03:33:53
    have the actual license agreement as an attachment
  • 03:33:55
    to this presentation. But in short, this license
  • 03:34:00
    applies to ERCOT and any mark discipline that
  • 03:34:03
    we will sublicense that registers within the ERCOT
  • 03:34:05
    region to participate as a CLR as a
  • 03:34:08
    load resource for ancillary services. So this will
  • 03:34:12
    this is just for the ERCOT region. Lantium
  • 03:34:16
    maintains full control of its licenses outside the
  • 03:34:19
    ERCOT region. But for the ERCOT region, ERCOT
  • 03:34:22
    will be able to execute a no cost
  • 03:34:24
    license agreement to resolve this issue. Our expectation
  • 03:34:29
    is that we'll execute this agreement this week
  • 03:34:31
    after we talk to PRS and give any
  • 03:34:33
    final comments, then we'll issue a market notice
  • 03:34:37
    and post the executed license agreement on the
  • 03:34:41
    ERCOT website. And that should resolve this issue.
  • 03:34:44
    Of course, it's unknown whether we'll see more
  • 03:34:47
    load resources come into the CLR program, but
  • 03:34:50
    this will not be a narrative on why
  • 03:34:52
    this could serve as a barrier to entry
  • 03:34:54
    for those entities to come into the ERCOT
  • 03:34:56
    market. So with that, I'm happy to answer
  • 03:34:59
    any questions. Any questions for Chad? I assume
  • 03:35:06
    the answer is no, but is there any
  • 03:35:09
    information captured by the software license that could
  • 03:35:13
    flow back to Lanxiom and could be competitive
  • 03:35:16
    advantage by any chance? No, not from an
  • 03:35:18
    ERCOT region standpoint. So the license is broad
  • 03:35:22
    enough that it captures any prospective licenses going
  • 03:35:26
    forward, any prospective patents that revolve around the
  • 03:35:30
    design of our CLR program and how load
  • 03:35:34
    resources participate. So I don't anticipate this being
  • 03:35:37
    an issue for Atlassian or for more participants
  • 03:35:39
    in the ERCOT region going forward. Okay. Any
  • 03:35:45
    other questions? Okay. I think this is definitely
  • 03:35:48
    a good thing for the growth of the
  • 03:35:50
    Texas market when it comes to CLRs. With
  • Item 12 - TAC Report
    03:35:58
    that, we'll move on to agenda item 12,
  • 03:36:02
    the TAC report. We're going to invite our
  • 03:36:04
    third attorney in a row to come up
  • Item 12.1.1 - NPRR1190, High Dispatch Limit Override Provision for Increased Load Serving Entity Costs
    03:36:06
    to the podium, The TAC recently approved on
  • 03:36:13
    a non unanimous basis to revision request or
  • 03:36:17
    recommended to the board to revision request on
  • 03:36:19
    a non unanimous basis to vote on a
  • 03:36:22
    gen item 12.1.1 which is NPRR1190,
  • 03:36:27
    high dispatch limit override provision for increased load
  • 03:36:31
    serving entity cost and agenda item 12.1.2 NPRR
  • 03:36:36
    1269 real time co opt utilization
  • 03:36:39
    plus batteries, three parameters policy issues. NPRR1269
  • 03:36:44
    is an urgent revision request. Caitlin
  • 03:36:48
    is going to walk us through '11 '90
  • 03:36:51
    first. We'll have a vote on that and
  • 03:36:53
    then we will dig into NPRR1269. So Kaitlyn, why don't you walk us
  • 03:36:57
    through your report and then eleven ninety. Okay.
  • 03:36:59
    Thanks, Bill. And bear with me, my throat
  • 03:37:02
    is a little scratchy today. And I thought
  • 03:37:04
    we were going to get a break before
  • 03:37:07
    my report. So, good morning or I think
  • 03:37:08
    (item:12.1:Non-Unanimous and Other Selected Revision Requests Recommended by TAC for Approval)close to afternoon. I'm Caitlin Smith, Chair of
  • 03:37:11
    the Technical Advisory Committee. As Chairman Flores said,
  • 03:37:14
    I will be walking you through the tech
  • 03:37:18
    report and in particular the revision request with
  • 03:37:20
    opposing votes. So, as we do at each
  • 03:37:24
    board meeting, I'll be presenting a summary of
  • 03:37:33
    the TAC meetings that have occurred since last
  • 03:37:35
    board meeting, which were our February and March
  • 03:37:37
    TAC meetings. At the February and March meetings,
  • 03:37:40
    we recommended approval of 14 revision requests. Two
  • 03:37:44
    of those had opposing votes. As the Chairman
  • 03:37:48
    mentioned, those were $11.9 and $12.69 We also
  • 03:37:50
    approved our twenty twenty five tax strategic objectives.
  • 03:37:54
    These used to be called goals, but we
  • 03:38:00
    rebranded. So, here is the list of the
  • 03:38:02
    12 unanimous revision requests. I will draw your
  • 03:38:06
    attention to two on this page that are
  • 03:38:11
    particularly relevant to conversations we've been having today.
  • 03:38:14
    Those are NPRR1234 and PGRR115. These were unopposed. They did have a
  • 03:38:18
    couple of abstentions each. Twelvethirty four is interconnection
  • 03:38:22
    requirements for large loads and modeling standards for
  • 03:38:25
    loads 25 megawatts or greater. PGRR115 is
  • 03:38:30
    requirements for large loads and modeling standards for
  • 03:38:33
    loads 25 megawatts or greater. PGRR115 is
  • 03:38:39
    the related planning guide revision request. I think
  • 03:38:44
    so I know Rebecca has these on her
  • 03:38:45
    presentation, but this is sort of the first
  • 03:38:48
    big delivery of work from the large flexible
  • 03:38:51
    load task force that reports to TAC currently.
  • 03:38:54
    I think it's monumental for two reasons. One,
  • 03:38:59
    passing these revision requests I think is a
  • 03:39:01
    testament to the good work ERCOT stakeholders
  • 03:39:03
    are doing through the kind of discussions we've
  • 03:39:05
    had today. I think you would notice and
  • 03:39:08
    assume that some of these large loads are
  • 03:39:11
    new stakeholders, new people to new businesses to
  • 03:39:14
    the ERCOT process. And I think we've done
  • 03:39:16
    a really good job of incorporating their expertise
  • 03:39:20
    and working with them on this. And then
  • 03:39:22
    two, I think this is kind of a
  • 03:39:23
    turning point from here on out. I think
  • 03:39:26
    we'll be focusing more on the operational issues
  • 03:39:30
    as we've kind of wrapped up some of
  • 03:39:31
    these interconnection issues. We will be also rebranding
  • 03:39:35
    large flexible load task force. It will be
  • 03:39:37
    just large load, probably working group and adding
  • 03:39:41
    a hyperscaler or data center subgroup. So we
  • 03:39:44
    could really focus on the expertise of those
  • 03:39:47
    operations. So here are the two with opposing
  • 03:39:53
    votes. And here are our strategic objectives. I
  • 03:40:00
    think we they're not 2025. I think they're
  • 03:40:03
    evergreen because I believe I lost the argument
  • 03:40:06
    to put 2025 in the name. So essentially
  • 03:40:09
    coming into this year, we had goals and
  • 03:40:11
    it was a long three page list. Some
  • 03:40:14
    were kind of broad and not really actionable,
  • 03:40:16
    some were very specific, but they weren't cohesive
  • 03:40:19
    or consistent. It was kind of everybody was
  • 03:40:22
    adding goals and then we were approving them.
  • 03:40:25
    And we didn't have a good way of
  • 03:40:27
    keeping ourselves accountable. So we did two things.
  • 03:40:30
    We sort of rebranded what was formerly known
  • 03:40:33
    as goals to be strategic objectives. These are
  • 03:40:37
    thought to be more evergreen and really kind
  • 03:40:39
    of the standards that we as TAC will
  • 03:40:42
    hold ourselves to. And they pretty closely parallel
  • 03:40:45
    the ERCOT strategic objectives in the plan that's
  • 03:40:49
    set every few years. The second thing we
  • 03:40:51
    are doing is starting to focus more on
  • 03:40:54
    our action items list. That's not in front
  • 03:40:56
    of you, but that is the actionable items.
  • 03:41:00
    They could be proactive, they could be in
  • 03:41:02
    response to an event or issue, but sort
  • 03:41:04
    of a hot topic and something we want
  • 03:41:06
    to investigate that maybe doesn't have a revision
  • 03:41:09
    request. A good example would be RUX. I
  • 03:41:13
    know you guys heard about RUX yesterday and
  • 03:41:15
    the increase we're having. So maybe somebody says
  • 03:41:18
    we want to take a look at that
  • 03:41:19
    and there's no associated revision request. That's a
  • 03:41:22
    good example of an action item. And so
  • 03:41:25
    here, with all that said, here are the
  • 03:41:27
    new strategic objectives. I'll point out a couple
  • 03:41:30
    of them. One, work with ERCOT staff to
  • 03:41:33
    efficiently execute the board strategic objectives for ERCOT
  • 03:41:37
    and align TAC and subcommittee goals accordingly. I
  • 03:41:41
    think the important word here is efficiency. We
  • 03:41:43
    are trying to be very mindful of ERCOT
  • 03:41:46
    staff time and a little bit more deliberate
  • 03:41:49
    on how we assign things in the process.
  • 03:41:51
    We have a lot of working groups and
  • 03:41:53
    subcommittees. So trying to get rid of some
  • 03:41:56
    of the maybe redundancies there when we send
  • 03:41:59
    a revision request through consideration. Four, I think
  • 03:42:03
    is probably the most important one through the
  • 03:42:05
    stakeholder process provide technical and policy perspectives on
  • 03:42:09
    issues pertinent to ERCOT members. I think that's
  • 03:42:12
    what we're really bringing to the process, right,
  • 03:42:15
    our perspectives on the technical and on the
  • 03:42:18
    policy, so that we can share that with
  • 03:42:20
    the rest of the group. And then five,
  • 03:42:23
    engage with ERCOT Board to provide ERCOT member
  • 03:42:26
    perspectives on ERCOT related initiatives and their impacts.
  • 03:42:30
    I think we'll talk briefly about this later,
  • 03:42:32
    but the Board stakeholder engagement we're really happy
  • 03:42:36
    with and I know in June, will be
  • 03:42:38
    coming to talk about sort of a hot
  • 03:42:40
    topic and share stakeholder education and perspective with
  • 03:42:43
    the board. So highlights, non revision request highlights,
  • 03:42:51
    real time co optimization, you will see the
  • 03:42:54
    revision request there. I'll just give a quick
  • 03:42:58
    shout out in our pre meeting with Chairman
  • 03:43:01
    Flores, I did, but for benefit of everybody,
  • 03:43:04
    Matt Marinus has done a great job on
  • 03:43:06
    this at ERCOT. If I ever needed a
  • 03:43:09
    project manager again in my life, I would
  • 03:43:11
    call Matt. So he's done a good job
  • 03:43:13
    of keeping stakeholders kind of on time. There's
  • 03:43:16
    a lot of things here. There's market trials,
  • 03:43:18
    there's policy decisions, And he is very good
  • 03:43:22
    at telling us when we need to make
  • 03:43:24
    a decision. And he and ERCOT have been
  • 03:43:27
    very open, right. If there is something stakeholders
  • 03:43:29
    say, or the IMM says, let's go back
  • 03:43:32
    and look at this or this isn't how
  • 03:43:34
    it's working in practice. I think ERCOT has
  • 03:43:36
    been very good and very open on that
  • 03:43:38
    and keeping the project on time as well.
  • 03:43:42
    As I just mentioned, ERCOT Board stakeholder engagement,
  • 03:43:47
    we are preparing for June. We are hoping
  • 03:43:50
    to provide stakeholder perspective. And so our proposal
  • 03:43:55
    is that we would have three different segments
  • 03:43:58
    present their perspective on transmission issues for this
  • 03:44:02
    meeting in particular. The three segments would be
  • 03:44:05
    the IOUs, so the ones doing the transmission
  • 03:44:08
    planning. Second, the inverter based resources, they can
  • 03:44:13
    talk about how transmission and transmission plans affect
  • 03:44:16
    their sighting, things like generic transmission constraints. And
  • 03:44:21
    then the third one, I think we are
  • 03:44:22
    looking for a large or industrial consumer because
  • 03:44:26
    those are the ones paying for transmission. And
  • 03:44:29
    so I think those three perspectives will really
  • 03:44:31
    give you a full picture, right. So you
  • 03:44:34
    can ask what's keeping you up at night
  • 03:44:36
    to all three and they can tell you,
  • 03:44:39
    I wake up and I do this. And
  • 03:44:41
    so it's not advocacy, but it's perspective. Segment
  • 03:44:46
    membership revisions to current segment membership structure that
  • 03:44:51
    the impetus for this was really again the
  • 03:44:54
    large loads that the definition of industrial maybe
  • 03:44:59
    did not was not totally inclusive of data
  • 03:45:02
    centers and cryptocurrency load. So the proposal there
  • 03:45:05
    is to expand that term to include computing
  • 03:45:08
    processes, including virtual currency mining as defined by
  • 03:45:12
    state law. We did take that opportunity to
  • 03:45:15
    discuss other aspects we may want changed. There's
  • 03:45:18
    a proposal to formally split the seats in
  • 03:45:22
    the inverter based resource and thermal generation resources,
  • 03:45:27
    there's a proposal to change the definition of
  • 03:45:30
    transmission and distribution entity, so that affiliate of
  • 03:45:36
    a transmission entity could participate in other segments.
  • 03:45:39
    And so I think the next steps here
  • 03:45:41
    is that the Corporate Secretary would submit these.
  • 03:45:44
    But I think if stakeholders get to some
  • 03:45:46
    consensus, there would be an impact there. And
  • 03:45:49
    of course, a member can always propose an
  • 03:45:52
    amendment as well. Market design framework, I don't
  • 03:45:56
    have a lot to say here. We are
  • 03:45:58
    continuing our discussions with ERCOT. We had a
  • 03:46:01
    long discussion in January. I think we will
  • 03:46:04
    have a workshop in April. Large load issues,
  • 03:46:09
    I mentioned this. Every month at TAC, we
  • 03:46:11
    review the update to the large load interconnection
  • 03:46:14
    status and we are in process of revising
  • 03:46:18
    the scope of that group. So it would
  • 03:46:20
    be not large flexible load, but just large
  • 03:46:22
    load and probably be a working group instead
  • 03:46:26
    of a task force that the significance there
  • 03:46:28
    being, it would be more permanent. And then
  • 03:46:31
    again, probably having a subgroup for hyperscalers or
  • 03:46:35
    data centers to really focus on the expertise
  • 03:46:38
    on those operational issues. Outage coordination, outage capacity
  • 03:46:45
    calculation, this is the MDR POC that Woody
  • 03:46:50
    cannot remember the acronym and I won't even
  • 03:46:52
    attempt, but I think the last word was
  • 03:46:54
    capacity. The issue here is that the methodology
  • 03:46:59
    for calculating how much outage planned outage you
  • 03:47:04
    can have and the load forecast is an
  • 03:47:07
    input to this. And so that has presented
  • 03:47:10
    a challenge. And so ERCOT is working on
  • 03:47:14
    an updated methodology and stakeholders who are very
  • 03:47:17
    interested are working on updated methodology as well,
  • 03:47:21
    I believe. Any questions on any of that
  • 03:47:27
    before I get to the revision requests? Okay.
  • 03:47:34
    NPRR1190, this is the high dispatch
  • 03:47:38
    limit override provision for increased load serving entity
  • 03:47:42
    costs. This adds a provision for recovery of
  • 03:47:49
    demonstrable financial loss arising from a manual high
  • 03:47:52
    dispatch limit override to reduce real power output
  • 03:47:56
    in the case when that output is intended
  • 03:47:58
    to meet QSC load obligations. So there is
  • 03:48:01
    existing policy here. This first expanded it to
  • 03:48:05
    NOEs and then sort of expanded it again
  • 03:48:08
    to all reps. This initially came to the
  • 03:48:11
    August board and was remanded back to TAC
  • 03:48:14
    at the October board. Again, sort of a
  • 03:48:18
    long history behind this starting in 2013 with
  • 03:48:22
    a contested case and '14 with the NPRR
  • 03:48:27
    that was initially voted down and then appealed.
  • 03:48:31
    So we're sort of seeing that kind of
  • 03:48:33
    controversy over the policy again. Where we landed
  • 03:48:39
    is TAC is on a compromise where we
  • 03:48:43
    would still have this policy, but basically a
  • 03:48:46
    trigger when payments reach $10,000,000 annually. We would
  • 03:48:51
    review the operational and settlement aspects of this.
  • 03:48:55
    ERCOT came back and proposed $3,500,000 The historical
  • 03:49:01
    data we had used to get to the
  • 03:49:03
    $10,000,000 included Yuri and included times where we
  • 03:49:06
    had a $9,000 price cap instead of $5,000
  • 03:49:09
    So we lowered it. At the time, I
  • 03:49:13
    believe ERCOT was supportive of it. I believe
  • 03:49:15
    they are now taking no opinion on revision
  • 03:49:20
    requests having to do with cost allocation. But
  • 03:49:24
    the sort of opinion within the no opinion
  • 03:49:26
    was that the number made more sense due
  • 03:49:29
    to the historical circumstances with Yuri and the
  • 03:49:33
    price cap changing. So we did have a
  • 03:49:36
    slight change this past hack again when it
  • 03:49:39
    came to the first time without the compromise,
  • 03:49:42
    which is the trigger. It had all six
  • 03:49:44
    consumer votes opposing. It now has four consumer
  • 03:49:48
    votes opposing. And the consumer votes who still
  • 03:49:52
    voted no pointed us back to their October
  • 03:49:55
    comments. Basically, thinking these payment override payments are
  • 03:50:01
    unnecessary will force consumers to subsidize market participants
  • 03:50:06
    when grid conditions require curtailment and sort of
  • 03:50:10
    just the policy of paying for the override.
  • 03:50:18
    Is there any questions here? Any questions on
  • Item 12.1.1 - NPRR1190, High Dispatch Limit Override Provision for Increased Load Serving Entity Costs
    03:50:21
    NPRR1190? Okay. With that I'll entertain
  • 03:50:27
    a motion to if there's no other discussion
  • 03:50:29
    on eleven ninety, I'll entertain a motion to
  • 03:50:32
    approve it as recommended by PAC by TAC.
  • 03:50:36
    Okay. Second. Okay. So we've had a motion
  • 03:50:44
    by Peggy, a second by Julie. All in
  • 03:50:46
    favor? Aye. Any opposed? Any abstentions? Okay, NPRR?
  • 03:50:51
    We have one opposing from No. Okay. A
  • 03:50:56
    no vote from Benjamin. All right. With that,
  • 03:51:00
    it's approved with one no vote. We'll move
  • 03:51:03
    on now to NPRR1269. Again,
  • 03:51:07
    that is RTC+B, three parameters policy
  • 03:51:10
    issues and this is an urgent matter. We
  • 03:51:15
    will have Caitlin present tax recommendation and then
  • 03:51:20
    we'll give an opportunity for other commenters to
  • 03:51:24
    express their opinions on this particular NPRR. Caitlin?
  • 03:51:28
    Right. So exactly correct, NPRR1269,
  • 03:51:35
    the three parameters. This one did get quite
  • 03:51:38
    contentious and the area of disagreement was basically
  • 03:51:43
    so first there was proposed a ASDC floor
  • 03:51:50
    and rock and the two notes here is
  • 03:51:52
    I think this is technically not a floor,
  • 03:51:55
    it's a $15 per megawatt curve. And then
  • 03:51:58
    two, I say everybody got okay with it.
  • 03:52:00
    I think not everybody was supportive of the
  • 03:52:02
    floor and RUC, but kind of got comfortable
  • 03:52:05
    with it. And so then we extended that
  • 03:52:08
    proposal supported by ERCOT and the generators to
  • 03:52:12
    extend that ancillary service demand curve, 15 per
  • 03:52:17
    megawatt curve or floor as we're calling it
  • 03:52:19
    to real time and to day ahead. And
  • 03:52:23
    what that was intended to remedy is in
  • 03:52:26
    ERCOT as you know, we set our volumes
  • 03:52:28
    of ancillary services pretty far in advance. We
  • 03:52:31
    set them the year before through the ancillary
  • 03:52:33
    service methodology that you approve and the commission
  • 03:52:36
    approves. And we have set those quite high
  • 03:52:40
    since Yuri since we've been in the conservative
  • 03:52:43
    operations posture. So the way we have set
  • 03:52:46
    the ancillary service demand curves in December, which
  • 03:52:50
    was unanimously approved today is the tail of
  • 03:52:53
    the required procurement would be valued at zero.
  • 03:52:57
    So on the one hand, we're saying you're
  • 03:52:59
    required to procure these, but on the other
  • 03:53:01
    hand, we're saying you can't procure these because
  • 03:53:04
    they have a zero value. And so that's
  • 03:53:07
    how we get got to sort of having
  • 03:53:09
    a higher than zero floor. ERCOT analysis showed
  • 03:53:12
    that the $15 floor would ensure procurement of
  • 03:53:15
    that full ancillary service requirement more often and
  • 03:53:19
    would increase reliability. This was approved by TAC.
  • 03:53:23
    We had five votes against or seven votes
  • 03:53:27
    against. We had the entire consumer segment and
  • 03:53:31
    then one from the IRAP segment. And I
  • 03:53:35
    would say, the concern is one with the
  • 03:53:39
    high level of reserves, when shown not to
  • 03:53:42
    be needed. So there's that discrepancy there saying
  • 03:53:45
    they're required, but also we can't fulfill that
  • 03:53:48
    requirement. And then I think there was a
  • 03:53:52
    they were against a floor, especially when there's
  • 03:53:56
    not an extenuating circumstance. So I think the
  • 03:53:58
    principle is we should not really have a
  • 03:54:00
    floor unless there's data that shows why and
  • 03:54:05
    which specific floor. I will leave it at
  • 03:54:10
    that unless there's any questions for me on
  • 03:54:12
    the tax discussion or decision. Okay. Any questions
  • 03:54:16
    for Caitlin on December? Caitlin, thank you for
  • 03:54:21
    your report and for TAC's hard work on
  • 03:54:23
    both these issues well as the items on
  • 03:54:26
    the consent agenda. We are going to ask
  • 03:54:34
    Keith is going to come up and present
  • 03:54:36
    ERCOT's position on NPRR1269 and
  • 03:54:41
    then we'll I think we've got some joint
  • Item 12.1.2.1 - ERCOT Comments on NPRR1269
    03:54:43
    commenters. Alright. Thank you. I'm here to present
  • 03:55:05
    on NPRR1269, the ERCOT position,
  • 03:55:09
    and we'll cover discussion on two items. I
  • 03:55:13
    know Matt presented yesterday. He said there were
  • 03:55:16
    three parameters, And one of them he noted
  • 03:55:19
    was with regards to ramping that was not
  • 03:55:21
    contentious. But there were two other items, one
  • 03:55:25
    around the ancillary service demand curve floor and
  • 03:55:30
    the second item around what is also called
  • 03:55:32
    a proxy curve floor. So I will touch
  • 03:55:34
    on that and discuss our views on that.
  • 03:55:38
    And some of the key takeaways here is
  • 03:55:40
    that we do feel that there is a
  • 03:55:42
    legitimate concern that the day ahead and real
  • 03:55:45
    time pricing may not be sufficient at times
  • 03:55:49
    to incentivize self commitment and ultimately could lead
  • 03:55:54
    to those increased reconstructions. That the $15 floor
  • 03:56:00
    is effectively fairly limited overall. When it does
  • 03:56:05
    occur, it does provide appropriate signals. But overall,
  • 03:56:09
    the price impact is fairly low. We note
  • 03:56:12
    it's $0.34 per megawatt hour. And the floors
  • 03:56:20
    will lessen shortages that could occur for the
  • 03:56:25
    ancillary services, which ultimately could lead to those
  • 03:56:30
    rux. And the proxy offer floor floor is
  • 03:56:34
    a compromise and was used within the ASDC
  • 03:56:40
    studies and we did not see anything from
  • 03:56:43
    an outcome perspective that we would consider unreasonable
  • 03:56:47
    or warranting further action or concern. So starting
  • 03:56:53
    first with the ancillary service demand curve floor,
  • 03:56:57
    I think we are concerned that there will
  • 03:57:00
    be an increased instance of the reliability unit
  • 03:57:04
    commitments that concur as a result of this.
  • 03:57:08
    We did extensively study the $15 per megawatt
  • 03:57:13
    hour ASTC floor in the RUC. And so
  • 03:57:16
    just to be clear, I know there was
  • 03:57:18
    potentially some confusion that, hey, you didn't study
  • 03:57:20
    that. Actually, did, and we studied it to
  • 03:57:23
    identify at what level of of a floor
  • 03:57:26
    within that RUC process would would be effective
  • 03:57:30
    in in creating the solution where those resources
  • 03:57:35
    were being committed through the RUC rather than
  • 03:57:40
    leaving us short and having the operators have
  • 03:57:43
    to take action. We do anticipate that extending
  • 03:57:48
    the $15 per megawatt per hour floor and
  • 03:57:52
    curve to the day ahead in real time
  • 03:57:54
    should help promote self commitment. Our analysis showed
  • 03:57:59
    that hitting the ASDC floor was relatively infrequent
  • 03:58:03
    at 1.4% of intervals that we did analyze.
  • 03:58:08
    And by intervals, we did look at several,
  • 03:58:10
    like 12,000. So we are talking about a
  • 03:58:13
    pretty significant amount of data that we looked
  • 03:58:15
    through when we did this analysis. And the
  • 03:58:18
    price impact was overall very limited, but important
  • 03:58:23
    when it did when it was there, it
  • 03:58:24
    was important, but overall not as significant. We
  • 03:58:30
    do see it important to compensate resources to
  • 03:58:34
    meet the reserve requirement that would be valued
  • 03:58:37
    at zero or at pennies otherwise. And so
  • 03:58:40
    it's important that if you're ultimately rucking resources
  • 03:58:46
    that there's value to that. And ultimately, what
  • 03:58:51
    we see under the current if the floor
  • 03:58:54
    were to be at zero you wouldn't be
  • 03:58:57
    valuing those resources. As Caitlin noted, this is
  • 03:59:00
    not a price floor. We are not adding
  • 03:59:03
    $15 to prices. What it does is it
  • 03:59:07
    increases the level at which you will evaluate
  • 03:59:10
    offers to set the price. And and so
  • 03:59:15
    it is not necessarily a price floor. It's
  • 03:59:18
    it's not a price floor. It is an
  • 03:59:19
    evaluation floor. And so the the importance of
  • 03:59:26
    this is extending it from the RUC to
  • 03:59:30
    the to the day ahead in the real
  • 03:59:33
    time. I did allude to this a little
  • 03:59:34
    bit yesterday in my comments about the about
  • 03:59:39
    the winter winter weather, we saw a chart
  • 03:59:42
    that showed that the when the price signals
  • 03:59:47
    in the day ahead were robust, we saw
  • 03:59:50
    a reduced instance of of rux on those
  • 03:59:54
    days. And on those days where the prices
  • 03:59:56
    were were less less robust, a higher instance
  • 04:00:01
    of of of reliable unit commitments. And so
  • 04:00:04
    that that same concept here applies that we
  • 04:00:09
    we are dependent on price signals to help
  • 04:00:12
    promote reliable reliable outcomes. I I will make
  • 04:00:16
    one correction from from what was stated yesterday
  • 04:00:19
    is that it does while this does enhance
  • 04:00:23
    reliability, in in the short run, the operators
  • 04:00:28
    have the ability to to take a RUC
  • 04:00:30
    action. And so they will they will achieve
  • 04:00:33
    that reliable outcome regardless. And so by including
  • 04:00:39
    the floors not only in that RUC process,
  • 04:00:42
    but in the market process, you begin to
  • 04:00:44
    move those operator actions into the market itself.
  • 04:00:48
    So the market is is is working to
  • 04:00:50
    mimic what ERCOT operators are going to be
  • 04:00:54
    doing otherwise. And in doing so, we can
  • 04:00:58
    also send the price signals into the market
  • 04:01:01
    to allow for that to occur. And and
  • 04:01:04
    in so doing, it can help to enhance
  • 04:01:07
    longer term price signals by having those floors
  • 04:01:12
    and helping ensure that those self commitments are
  • 04:01:17
    occurring. We can always fine tune the floor
  • 04:01:22
    later as needed. I think that's something that
  • 04:01:27
    is always a possibility. I think would had
  • 04:01:32
    we had the luxury of time to be
  • 04:01:35
    able to do an extent of an exhaustive
  • 04:01:38
    approach to evaluating which specific price in the
  • 04:01:42
    day ahead in real time could could identify
  • 04:01:44
    it. We identified 15 extensively in the RUC.
  • 04:01:48
    And so we felt that extending it to
  • 04:01:50
    the other markets was also appropriate. Now I
  • 04:01:55
    do want to make one other note that's
  • 04:01:58
    important. I'm going to switch over to Matt's
  • 04:02:01
    presentation from yesterday. Folks may not have have
  • 04:02:06
    picked up on this, but on slide 30,
  • 04:02:09
    we did highlight some analysis that we had
  • 04:02:12
    done. I think it's important to recognize that
  • 04:02:14
    RUC does RUC has its own costs as
  • 04:02:16
    well. RUC is not free. So if you're
  • 04:02:19
    rucking a resource, you have to there are
  • 04:02:22
    some costs associated with that. And so we
  • 04:02:24
    were able to, at the request of commission
  • 04:02:27
    staff, to evaluate what those commitment costs are
  • 04:02:31
    and what the potential outcomes would be. And
  • 04:02:34
    so we we had obviously, case one is
  • 04:02:37
    our baseline, which doesn't, which is, there are
  • 04:02:42
    no floors in in the baseline, but we
  • 04:02:44
    do have the rut commitment costs. And for
  • 04:02:47
    a resource, we saw on roughly that it
  • 04:02:49
    was 92 megawatts on average that we could
  • 04:02:54
    avoid rutting. And so the we estimated what
  • 04:02:58
    a resource of of that size would be
  • 04:03:00
    for commitment costs, and we estimated those were
  • 04:03:02
    about a little over $3,000,000 in terms of
  • 04:03:05
    ruck commitment costs. And then we applied that
  • 04:03:08
    to two different cases. And case two is
  • 04:03:10
    an is a more extreme case, high end
  • 04:03:13
    estimate. And, case three is lower end, but
  • 04:03:19
    probably closer to the estimations that we would
  • 04:03:22
    anticipate that would occur, in the market. And
  • 04:03:24
    so what we see is in extreme cases,
  • 04:03:28
    the 47,700,000 is a representation of it would
  • 04:03:33
    cost more with the floors. However, in case
  • 04:03:37
    three, which we consider to be more representative
  • 04:03:40
    of the outcomes we expect, it actually results
  • 04:03:43
    in negative 1,900,000.0, which is actually a reduction
  • 04:03:47
    in costs once you factor in the commitment
  • 04:03:49
    costs. So it actually could result in cheaper
  • 04:03:52
    outcomes relative to the a no floor approach.
  • 04:03:58
    So I think this is an important concept.
  • 04:04:01
    And and again, we appreciate that it's it's
  • 04:04:03
    sort of late breaking information, but again, it
  • 04:04:05
    was based on some questions we received late
  • 04:04:07
    from commission staff that were definitely very thoughtful
  • 04:04:11
    questions and something that we we tried to
  • 04:04:13
    to do as as quickly as we could
  • 04:04:15
    and and we're able to include in this
  • 04:04:17
    this deck. So I'll just switch back to
  • 04:04:21
    my presentation and see, at least for this
  • 04:04:24
    first item on the ASDC floors, if the
  • 04:04:27
    Board has any questions on these. Any questions
  • 04:04:34
    for Keith? Okay. Okay. All right. And so
  • 04:04:39
    I'll move to the second item, which is
  • 04:04:42
    the proxy offer curve floor. And based on
  • 04:04:46
    some follow-up conversations, I realized there may be
  • 04:04:48
    some confusion that I'll try to switch back
  • 04:04:51
    to Matt's presentation from yesterday to help help
  • 04:04:54
    clarify. So ultimately, a proxy offer floor is
  • 04:04:58
    is needed when there is no offer included.
  • 04:05:02
    And and that can happen for, it could
  • 04:05:04
    be human or technical area, technical issues. We
  • 04:05:07
    had some discussion on on TAC on how
  • 04:05:09
    that could arise. A discussion around a potential
  • 04:05:13
    communications technical glitch that could occur, which could
  • 04:05:17
    result in, the loss of information being properly
  • 04:05:21
    transferred to the ERCOT systems. The question was
  • 04:05:24
    also raised at TAC if the IMM, had
  • 04:05:27
    had noticed this is a systematic problem. And
  • 04:05:30
    as as was noted, this is generally not
  • 04:05:33
    a historical issue, and, the IMM had agreed
  • 04:05:38
    to to present further information had had had
  • 04:05:41
    to the extent this this raises as as
  • 04:05:44
    an issue. The proposal in December is a
  • 04:05:49
    compromise that strikes the balance between concerns. The
  • 04:05:55
    original ERCOT proposal was 0, dollars per megawatt
  • 04:06:00
    per hour. The the participant counter proposal was
  • 04:06:04
    $2,000 per megawatt per hour. And ultimately, a
  • 04:06:08
    compromise was was developed, which is it's the
  • 04:06:13
    lesser of $2,000 per megawatt per hour or
  • 04:06:19
    and this is where it gets complicated and
  • 04:06:21
    I'll show in the graph in a second.
  • 04:06:23
    The point on the ancillary service demand curve
  • 04:06:26
    for the ancillary service that intersects with a
  • 04:06:29
    quantity that is 95% of the ancillary service
  • 04:06:32
    plan for the ancillary service. So let me
  • 04:06:35
    switch and show what that is because it
  • 04:06:38
    is not entirely intuitive what that means. So
  • 04:06:41
    let me go up. Alright. It's actually up
  • 04:06:45
    a little bit. Alright. Okay. So in Matt's
  • 04:06:54
    slide deck, he presented essentially, you can see
  • 04:06:58
    the NPRR1269 as approved. And
  • 04:07:02
    so this chart down here represents ancillary service
  • 04:07:09
    demand curves that are in the unanimous
  • 04:07:13
    NPRR1268. And so what what would likely
  • 04:07:17
    represent 95? What's the ninety fifth percentile? And
  • 04:07:22
    so when you look at this is regulation
  • 04:07:25
    service here. Ninety fifth percentile roughly in our
  • 04:07:28
    analysis turned out to be about fifteen fifteen
  • 04:07:32
    hundred. When you look at RRS in the
  • 04:07:38
    orange, the ninety fifth percentile was, did my
  • 04:07:43
    notes, around 400 to 700. So it's around
  • 04:07:49
    here on the curve. For ECRS, it resulted
  • 04:07:56
    in about $17 to $240, so in this
  • 04:08:00
    range. And then for a non spin, it
  • 04:08:03
    was in the $15 to $60 range, which
  • 04:08:05
    is, you know, somewhere around here on the
  • 04:08:07
    curve. So that represents around here, here, there,
  • 04:08:13
    and about there, the value we saw in
  • 04:08:17
    our studies. Right? So we ran several instances
  • 04:08:22
    of this, and that's what we found. I
  • 04:08:23
    will also note that in all the runs
  • 04:08:25
    we did, in no case did we hit
  • 04:08:28
    the $2,000 floor. Okay? So it was all
  • 04:08:33
    hitting at some other part. It was hitting
  • 04:08:35
    that ninety fifth percentile of those curves. So
  • 04:08:41
    I'll pause and see if there's any question
  • 04:08:42
    on the compromise curve itself. Okay? I just
  • 04:08:50
    want to thank Keith for explaining the operating
  • 04:08:54
    point as that you'd thank you. Yes, absolutely.
  • 04:09:01
    All right. Then Okay. Yep. Here we go.
  • 04:09:11
    Alright. So why the need to compromise? There's
  • 04:09:17
    sort of a balance of points to be
  • 04:09:20
    considered here. On one hand, as I said
  • 04:09:25
    earlier on, we need a curve, a complete
  • 04:09:28
    curve so that we can address any inappropriate
  • 04:09:32
    scarcity that could occur, and the concern to
  • 04:09:37
    also address any any strategic withholding behavior a
  • 04:09:42
    participant participant may be doing. And so this
  • 04:09:47
    is something that can be done by a
  • 04:09:49
    participant in the in an attempt to raise
  • 04:09:53
    prices is to create a false scarcity by
  • 04:10:00
    intentionally not submitting offers, and that would be
  • 04:10:03
    a problem. And so a low offer curve
  • 04:10:06
    of $0 per megawatt per hour can address
  • 04:10:08
    those issues. So you can ensure that you
  • 04:10:11
    can address an appropriate scarcity and that'll be
  • 04:10:13
    there. And if somebody is attempting to do
  • 04:10:15
    a form of strategic withholding, you can also
  • 04:10:18
    address that. The high offer curve of 2,000
  • 04:10:24
    is less likely to address the strategic behavior
  • 04:10:27
    issue. But what it does better than the
  • 04:10:31
    $0 is to the extent that I have
  • 04:10:34
    costs that I incur, those costs will it
  • 04:10:40
    can cover a range of potential costs in
  • 04:10:43
    in producing those reserves. And so as an
  • 04:10:45
    example, I may be a storage resource, and
  • 04:10:50
    I charge in the middle of the day
  • 04:10:53
    for $50, and I'm hoping to catch a
  • 04:10:57
    ramping period later in the day. And and
  • 04:11:00
    so I submit an offer that would would
  • 04:11:02
    reflect that that that cost. If I'm submitting
  • 04:11:05
    zero in for those resources, then then I'm
  • 04:11:10
    the the likelihood that I'm going to be
  • 04:11:12
    taken during those periods is very high. So
  • 04:11:14
    my costs are not going to be recognized
  • 04:11:16
    in that process. And so a 2,000 proxy
  • 04:11:20
    offer would would definitely ensure you would cover
  • 04:11:23
    that in in in most cases, almost almost
  • 04:11:26
    all cases. And so it's trying to find
  • 04:11:29
    a compromise that balances these two forces. Right?
  • 04:11:33
    Is it strategic withholding? Are we able to
  • 04:11:35
    cover costs? And so ultimately, that's the nature
  • 04:11:39
    behind the compromise that we we did for
  • 04:11:43
    the proxy offer floor is to try to
  • 04:11:45
    balance those two concerns and ultimately is something
  • 04:11:49
    that is brought to you today. So I'm
  • 04:11:54
    going to pause and see if there are
  • 04:11:56
    any questions here with regards to proxy offer
  • 04:11:58
    floor. Any questions for Keith? So Keith, did
  • 04:12:05
    the compromise result in parties changing their position
  • 04:12:10
    on whether or they were for or against
  • 04:12:12
    this? I think there was there were still
  • 04:12:16
    concerns raised at attack and there was an
  • 04:12:19
    alternative approach in some of the comments. But
  • 04:12:21
    no, this the compromise did not change as
  • 04:12:24
    as far as I know any any positions
  • 04:12:27
    on this. And part of it too is
  • 04:12:28
    this group with the other the other item
  • 04:12:30
    as well. So so no, I don't I
  • 04:12:32
    don't think so. Okay. Let's keep going, I
  • 04:12:39
    guess. All right. Thank you. All righty. Thanks,
  • 04:12:44
    Keith. And I don't think the board had
  • 04:12:47
    any other questions. The IMM submitted comments that
  • 04:12:51
    are included in your board packet on pages
  • 04:12:54
    two twenty seven through two thirty four. And
  • 04:12:56
    then also there were comments submitted on this
  • 04:12:58
    NPRR this past Friday by a group of
  • 04:13:00
    consumers called the joint consumers. This group includes
  • 04:13:05
    the residential consumer segment, the Office of Public
  • 04:13:07
    Utility Council, the Texas Industrial Energy Consumers, which
  • 04:13:11
    is TIAC for short, the City of Eastland,
  • 04:13:14
    the City of Dallas and ERCOT steel mills.
  • 04:13:18
    Their comments are included in two thirty five
  • 04:13:21
    to two seventy three and it's my understanding
  • 04:13:23
    nobody wants to comment in person. Is that
  • 04:13:25
    correct, Chad? Okay. So that all so I
  • 04:13:29
    think we've heard all the 300. That's for
  • 04:13:32
    the joint consumers. I don't know if Jeff
  • 04:13:34
    wants to say anything as on behalf of
  • 04:13:36
    the IMO. Okay. Go ahead and grab the
  • 04:13:40
    podium. And Benjamin, I think you might have
  • 04:13:42
    something as well. What's that? Just briefly when
  • Item 12.1.2.2 - Other Comments on NPRR1269, if any
    04:13:46
    it's comment. Thank you. Jeff McDonald, Director of
  • 04:13:59
    IMM. So, I'd like to talk about two
  • 04:14:03
    of the three components of NPRR1269
  • 04:14:06
    and follow-up a little bit on what Keith
  • 04:14:08
    has just talked about. So with respect to
  • 04:14:11
    the shortage pricing or ORDC ASDC curve, the $15
  • 04:14:18
    floor there, so we actually grappled with that
  • 04:14:21
    for quite a bit. On the surface, it
  • 04:14:24
    appeared to be an administrative price floor to
  • 04:14:28
    achieve an objective that wasn't stated or mandated.
  • 04:14:33
    And potentially and done within RUC, we had
  • 04:14:37
    less of an issue with it when the
  • 04:14:39
    proposal was put forward to move that floor
  • 04:14:43
    to real time and day ahead. We took
  • 04:14:46
    exception with it. The real time market and
  • 04:14:48
    day ahead market are not required to procure
  • 04:14:51
    the entire AS plan. And that's actually the
  • 04:14:55
    function that the shortage pricing mechanism, the ORDC
  • 04:14:59
    or ASDC curves perform as they price the
  • 04:15:02
    shortage. So we were originally concerned that in
  • 04:15:08
    moving that type of reliability instrument into the
  • 04:15:13
    day ahead in real time market, you were
  • 04:15:16
    achieving two goals that might not have been
  • 04:15:19
    optimal. And in a sense suppressing especially the
  • 04:15:26
    real time prices' ability market's ability to effectively
  • 04:15:30
    price shortages. So that shortage pricing curve in
  • 04:15:34
    real time is there to measure shortages to
  • 04:15:37
    provide a dynamic, not necessarily just this interval,
  • 04:15:42
    but a dynamic over time signal, and I
  • 04:15:44
    talked a little bit about this yesterday, in
  • 04:15:47
    order to induce self commitment from resources that
  • 04:15:51
    are available to come online and provide energy
  • 04:15:54
    and reserves because of higher prices. So and
  • 04:15:57
    I think Keith had mentioned this, everybody understands
  • 04:16:02
    the potentially price suppressing effect of any kind
  • 04:16:06
    of RUC activity. But this is another means
  • 04:16:11
    of getting additional commitment in RUC without the
  • 04:16:14
    operator actually doing it. So you're getting additional
  • 04:16:17
    commitment in RUC with this $15 floor that
  • 04:16:21
    will wind up pushing additional capacity into the
  • 04:16:24
    real time market and will result in, in
  • 04:16:27
    some instances, muting of shortage signals through the
  • 04:16:31
    shortage pricing mechanism. I can't emphasize enough there's
  • 04:16:35
    a dynamic effect to that. So it's not
  • 04:16:37
    just about this hour, it's about generators' expectations
  • 04:16:41
    over time as to what kind of signals
  • 04:16:43
    they're getting from the real time market and
  • 04:16:45
    how they would want to position themselves to
  • 04:16:47
    take advantage of that. So that's where we
  • 04:16:50
    started. A lot of conversation on the operating
  • 04:16:55
    reserve demand curve floor. And through that conversation,
  • 04:16:59
    we realized that at the heart of our
  • 04:17:03
    objection was really a mismatch between how the
  • 04:17:07
    shortage pricing mechanism priced shortages and the quantity
  • 04:17:12
    of reserve procurement And so you can effectively
  • 04:17:18
    think of this issue as there is no
  • 04:17:21
    value to incremental or decremental reserve procurement at
  • 04:17:26
    the quantity that ERCOT is procuring reserves. That
  • 04:17:31
    would signal to you that there might be
  • 04:17:33
    an over procurement of reserves. There isn't a
  • 04:17:36
    value, that's the nature of the problem. That's
  • 04:17:38
    why this floor or ceiling, I've heard it
  • 04:17:42
    described both ways, That's why that's being introduced
  • 04:17:47
    into RUC is that with our current valuation
  • 04:17:51
    or our current procurement level, there isn't a
  • 04:17:54
    need for more. However, there isn't even a
  • 04:17:58
    need to fully procure from an economic perspective.
  • 04:18:02
    So that indicates a mismatch. We still object
  • 04:18:07
    to the $15 floor ceiling, But we are
  • 04:18:14
    hopeful that through the AS methodology practice or
  • 04:18:19
    process that will take place starting soon for
  • 04:18:23
    the 2026 period that some of that methodology
  • 04:18:29
    of the methodology adopted will take a more
  • 04:18:31
    stochastic approach and a more marginal reliability approach
  • 04:18:37
    to determining the quantity that's procured. And when
  • 04:18:41
    that happens, we might see this issue go
  • 04:18:44
    away. Another way to address this issue that
  • 04:18:48
    I think is probably important is not just
  • 04:18:51
    on the procurement side, but the ORDC or
  • 04:18:55
    the shortage pricing mechanism has been altered over
  • 04:18:58
    time to produce more revenue. That actually also
  • 04:19:04
    ties in with some of the things I
  • 04:19:05
    spoke with yesterday. And so these two things
  • 04:19:07
    are quite literally hand in hand and very
  • 04:19:10
    directly related. And so reevaluating the ORDC curve
  • 04:19:15
    or NRTC, the ancillary service demand curve, reevaluating
  • 04:19:20
    that from a stochastic marginal reliability perspective and
  • 04:19:25
    choosing rolling in that analysis from the AS
  • 04:19:29
    methodology process into establishing the shortage pricing curve
  • 04:19:35
    will actually solve this problem. It will link
  • 04:19:40
    the two very directly and you will get
  • 04:19:43
    a very real and accurate marginal value of
  • 04:19:47
    reserves whether you are looking to procure a
  • 04:19:50
    little bit more or a little bit less,
  • 04:19:52
    the value that will be provided from that
  • 04:19:54
    will be much more accurate and much better
  • 04:19:56
    reflect ERCOT's needs as determined through the methodology
  • 04:20:01
    process. So I've mentioned two things. One is
  • 04:20:05
    we look at whether or not these types
  • 04:20:07
    of policies will mute shortage signals that exist,
  • 04:20:13
    and they do that's the whole purpose of
  • 04:20:16
    the $15 floor is to avert a shortage
  • 04:20:19
    in RUC. So muting shortage signals is not
  • 04:20:24
    good in terms of eliciting additional response when
  • 04:20:27
    you need it from generators And then having
  • 04:20:30
    a more direct linkage between a reliability based
  • 04:20:34
    marginal reliability based ancillary service procurement method and
  • 04:20:38
    how you construct your operating demand curve your
  • 04:20:40
    operating reserve demand curves is absolutely critical in
  • 04:20:43
    valuation also and all of those roll into
  • 04:20:46
    real time pricing and price signals. So we
  • 04:20:49
    are not in favor of this. I will
  • 04:20:51
    recognize, as Keith noted, it is it reflects
  • 04:20:55
    a small incremental cost because of the infrequency
  • 04:20:59
    with which it triggers. But in principle, we
  • 04:21:03
    do not support it and would like to
  • 04:21:04
    see these other aspects addressed, which I believe
  • 04:21:08
    will be over the next year or two.
  • 04:21:11
    So that addresses that one component. The other
  • 04:21:14
    component is a little different and Keith wrapped
  • 04:21:17
    up his discussion talking about the proxy offer
  • 04:21:22
    price for resources. And he noted one thing
  • 04:21:26
    in particular, which is there are different reasons
  • 04:21:28
    why ERCOT might not have a complete offer
  • 04:21:33
    from some of these resources. So one of
  • 04:21:37
    them is understandable which is there was a
  • 04:21:41
    communication glitch, potentially an electronic communication glitch. So
  • 04:21:45
    the participant submitted information legitimately but it wasn't
  • 04:21:50
    received and couldn't be used by ERCOT and
  • 04:21:52
    so some proxy value need to be used.
  • 04:21:54
    I don't know what proportion of the time
  • 04:21:57
    that happens. But in the other case where
  • 04:22:01
    the participant simply did not submit a complete
  • 04:22:04
    offer, a complete valid offer, In our work
  • 04:22:09
    on that particular aspect, we didn't find an
  • 04:22:13
    explicit offer requirement in the protocols, but the
  • 04:22:17
    offer requirement is there and it's implicit in
  • 04:22:20
    the fact that ERCOT submits a proxy offer
  • 04:22:22
    for you. So in my view, a better
  • 04:22:26
    way of dealing with this issue and I'll
  • 04:22:30
    get to the specifics of the proposal in
  • 04:22:32
    a second but a better way of dealing
  • 04:22:33
    with this is to make the offer requirement
  • 04:22:36
    explicit so that it is explicit that a
  • 04:22:40
    participant is required to submit a valid offer
  • 04:22:44
    and then have a penalty structure, fine or
  • 04:22:49
    some sort in cases where they don't. And
  • 04:22:53
    in that case, you should get you should
  • 04:22:55
    see much better compliance. In my view, this
  • 04:22:58
    entire discussion was a little weird because I
  • 04:23:02
    couldn't understand why we were dealing with having
  • 04:23:05
    to submit proxy offers for resources. Why didn't
  • 04:23:08
    we make that their responsibility in a way
  • 04:23:11
    where they would actually adhere to it? So
  • 04:23:14
    having said that, I think that's a better
  • 04:23:16
    approach. Having said that, the proposal when I
  • 04:23:21
    think of from a price formation perspective, when
  • 04:23:24
    I think of if I have to come
  • 04:23:27
    up with a value to substitute into an
  • 04:23:31
    auction, I want to come up with a
  • 04:23:33
    value that is least obtrusive to competitive price
  • 04:23:39
    formation. And the proposal as it stands and
  • 04:23:44
    Keith noted that in the instances that they
  • 04:23:48
    simulated or reran, the $2,000 never hit, but
  • 04:23:53
    he did cover some of the ranges of
  • 04:23:55
    the ninety fifth percentile on the different service
  • 04:23:59
    curves. I think the ninety fifth percentile is
  • 04:24:02
    an arbitrary number. There is little to no
  • 04:24:07
    indication that when participants don't submit valid offers
  • 04:24:12
    that, that would cause a shortage condition that
  • 04:24:15
    coincides with the ninety fifth percentile. But those
  • 04:24:18
    ranges were very high. We went back and
  • 04:24:20
    looked at the pool of units that most
  • 04:24:23
    frequently had proxy offers submitted for them. And
  • 04:24:26
    when they submitted valid offers, the center of
  • 04:24:29
    mass in price around the offers that they
  • 04:24:32
    submitted were about $15 That was at the
  • 04:24:35
    that was, I think, quite literally the lower
  • 04:24:38
    bound on the range that Keith identified for
  • 04:24:40
    the different services. I view this proposal as
  • 04:24:45
    one, not addressing an obligation that clearly participants
  • 04:24:48
    have by making it their responsibility to do
  • 04:24:52
    it and two, injecting what is probably obtrusive
  • 04:24:57
    and uncompetitive prices into the price formation process
  • 04:25:02
    unnecessarily. So when we were talking through the
  • 04:25:06
    stakeholder process on this matter, we proposed $15
  • 04:25:11
    that's what our analysis indicated would be a
  • 04:25:14
    better guess at a competitive offer for this
  • 04:25:16
    pool of units. Disappointed to see that it
  • 04:25:20
    could be as high as it is. I
  • 04:25:21
    know it's not going to be $2,000 often,
  • 04:25:23
    if at all. But even in the $200
  • 04:25:26
    3 hundred dollars 4 hundred dollars range, we're
  • 04:25:29
    seeing competitive offers from this pool of resources
  • 04:25:31
    in the $15 range. So I view this
  • 04:25:33
    as an injection of uncompetitive potential outcomes into
  • 04:25:37
    the market and oppose it for that reason.
  • 04:25:41
    And I'm happy to answer any questions. Okay.
  • 04:25:44
    Any questions for Jeff? Pablo? I was just
  • 04:25:48
    going to offer after you more focused on
  • 04:25:51
    the comments to the first issue that I
  • 04:25:53
    really appreciated the way you separated kind of
  • 04:25:55
    the issues as you see within the related
  • 04:26:00
    to the ancillary service demand curve and the
  • 04:26:03
    minimum price consideration that the better solution long
  • 04:26:07
    term is some of these kind of evolutions
  • 04:26:08
    that are likely going to emerge as we
  • 04:26:11
    see the changes to the ancillary service procurement
  • 04:26:14
    methodology, which is going to be more probabilistically
  • 04:26:16
    based. It's going to reflect better real time
  • 04:26:22
    expectations on the risks associated with the operating
  • 04:26:25
    period. And as such, the natural result of
  • 04:26:29
    that would be ancillary service demand offers that
  • 04:26:32
    are going to be more reflective of those
  • 04:26:33
    risks, those real risks. That being said, until
  • 04:26:37
    we get to that point, there is a
  • 04:26:40
    need, from the operator point of view to
  • 04:26:43
    fill out the procurement. And even though the
  • 04:26:46
    signal may be zero, we still have to
  • 04:26:48
    get that procurement. And I think the point
  • 04:26:50
    that the ERCOT team, is putting forth is
  • 04:26:53
    that it would be better to have a
  • 04:26:56
    administrative market process provide that versus a RUC
  • 04:27:01
    process. And under some circumstances, Keith pointed out,
  • 04:27:05
    there's different kind of scenarios. It might actually
  • 04:27:08
    be cost advantageous to consumers to do it
  • 04:27:11
    with that administrative floor versus doing it with
  • 04:27:13
    the RUC. And so I I think the
  • 04:27:15
    bigger I think you raised the bigger issue,
  • 04:27:18
    which is how to solve this without an
  • 04:27:20
    administrative solution. I do think we're going to
  • 04:27:23
    get there. And I think just I think
  • 04:27:25
    the clarity you provided on that perspective was
  • 04:27:27
    helpful to the discussion. So thank you. Yeah.
  • 04:27:30
    Thank you, Pablo. Any other questions for Jeff
  • 04:27:35
    or any comments? Peggy? Just I want to
  • 04:27:37
    echo what Pablo said, was very helpful. Just
  • 04:27:41
    a minor point in that discussion, why isn't
  • 04:27:45
    it clear that they have to submit the
  • 04:27:46
    offers? Keith? So I'll just note that that
  • 04:27:56
    Jeff's characterization is is accurate. That the it
  • 04:28:00
    is a indirect, the the requirement is indirect
  • 04:28:05
    through the creation of the proxy. The proxies.
  • 04:28:08
    Could could language be introduced to require it?
  • 04:28:11
    Yes. It that's just not the the path
  • 04:28:15
    that's we've gone down. But you haven't seen
  • 04:28:17
    evidence of people gaming? I'd point to Jeff.
  • 04:28:22
    I think he discussed this at the time.
  • 04:28:24
    Yeah, we haven't. I mean, it's to be
  • 04:28:27
    fair, it's a very small issue. Okay. Yeah.
  • 04:28:30
    Thank you. Going back to Jeff's and Pablo's
  • 04:28:34
    comments, can you a year from now we'll
  • 04:28:36
    be discussing probabilistic ASDC curves? So we're talking
  • 04:28:40
    about living with this for twelve months perhaps?
  • 04:28:45
    Even sooner perhaps, Dan. Yes. Actually, we're work
  • 04:28:48
    with although I think the recommendation was put
  • 04:28:51
    that in place by '20 for the calendar
  • 04:28:53
    year 2027. We're working toward getting it in
  • 04:28:56
    for calendar year 2026. And so in the
  • 04:28:59
    October board meeting, we'll probably be bringing you
  • 04:29:02
    the AS methodology for '26 that will include
  • 04:29:06
    that. Now the other piece that Jeff mentioned,
  • 04:29:09
    is kind of more dynamically adjusting the or
  • 04:29:12
    stochastically adjusting the ancillary service demand curve so
  • 04:29:17
    that they do meet that requirement, if the
  • 04:29:20
    sum of those requirements are higher than what
  • 04:29:23
    the current ORDC limit is, that's not in
  • 04:29:26
    progress at this point. Okay. Do you have
  • 04:29:35
    another question? Okay. Yes. Does the IMM have
  • 04:29:39
    a view on what how this affects reliability?
  • 04:29:47
    On how it affects reliability. So that's the
  • 04:29:52
    $15 floor, not the proxy offer matter. And
  • 04:29:58
    yes, So, perception through the work that we
  • 04:30:03
    did on the AS study last year indicated
  • 04:30:07
    that ERCOT is procuring an excess amount of
  • 04:30:11
    reserves relative to what would be needed to
  • 04:30:15
    run a reliable system. So we get that
  • 04:30:18
    through probabilistic models through actually evaluating and rerunning
  • 04:30:24
    prior years' real time markets. So from my
  • 04:30:29
    perspective and it was probably I probably hinted
  • 04:30:33
    at it in my earlier discussion, but from
  • 04:30:39
    my perspective, it looks like we're over procuring
  • 04:30:42
    out of a, I guess, a sense of
  • 04:30:49
    wanting to have additional insurance for reliability. I'm
  • 04:30:53
    not a grid operator. I have never been
  • 04:30:55
    a grid operator. I've worked with them and
  • 04:30:57
    other RTOs very closely. I don't have a
  • 04:31:01
    finely tuned sense of what the exact right
  • 04:31:04
    number is, but 9,000 megawatts for reserve procurement
  • 04:31:07
    seems on the high end for the system
  • 04:31:10
    given what we've seen looking at prior year's
  • 04:31:14
    data. I understand that Yuri was a very
  • 04:31:17
    unique and very painful experience. And so those
  • 04:31:21
    tail events are what I think are driving
  • 04:31:26
    a desire to buy additional reliability insurance through
  • 04:31:31
    higher reserve requirements. So you would say that
  • 04:31:37
    and I don't want to mischaracterize what you're
  • 04:31:39
    saying, but you would say that implementing this
  • 04:31:42
    to some extent improves reliability? Implementing what's proposed?
  • 04:31:48
    So there's a short term effect and a
  • 04:31:51
    medium term effect in this. So in the
  • 04:31:53
    short term for this next hour or some
  • 04:31:57
    hour today, implementing the $15 price floor will
  • 04:32:02
    push you into real time in RUC and
  • 04:32:05
    having that price floor in the real time
  • 04:32:07
    market will help ensure that you are more
  • 04:32:11
    likely to meet your 9,000 megawatt reserve requirement.
  • 04:32:17
    At some point, one additional megawatt of reserve
  • 04:32:19
    does not improve reliability today. And so what
  • 04:32:24
    I'm saying is I think we're already at
  • 04:32:26
    that point where no additional an additional megawatt
  • 04:32:30
    of reserve does not improve reliability. I think
  • 04:32:33
    that's where we are in our procurement. This
  • 04:32:36
    helps ensure that we're right at that maybe
  • 04:32:38
    not right at that point, we might even
  • 04:32:39
    be beyond that point, but this helps ensure
  • 04:32:42
    that ERCOT in real time operations does not
  • 04:32:46
    slip too far short of that point. So,
  • 04:32:49
    that was I apologize, that was not a
  • 04:32:52
    brief answer. The brief answer is in some
  • 04:32:56
    hour today, this is reliability improving. Over the
  • 04:32:59
    medium term, if this winds up muting real
  • 04:33:02
    time price signals for additional self commitment and
  • 04:33:06
    commercial response to shortage signals, it's not reliably
  • 04:33:10
    improving. Okay. Any other questions or comments for
  • 04:33:16
    Just real quick. So Jeff, but we'll address
  • 04:33:20
    the amount of the procurement later, right? So
  • 04:33:23
    setting that aside, you would agree that reducing
  • 04:33:26
    instances of RUC is a good thing, yes?
  • 04:33:29
    Yes, I absolutely agree with that. Do you
  • 04:33:31
    believe that extending the $15 per megawatt floor
  • 04:33:38
    into the day ahead and real time market
  • 04:33:40
    will reduce RUC? I think regarding the day
  • 04:33:49
    ahead market, I think the days where you're
  • 04:33:51
    going to see tighter supply conditions and higher
  • 04:33:54
    prices will solve that without this price floor.
  • 04:33:58
    I think the days where that's needed, where
  • 04:34:00
    that additional I don't know what we're talking
  • 04:34:03
    about in terms of marginal procurement by putting
  • 04:34:06
    the $15 in the day ahead, I think
  • 04:34:10
    system conditions will solve that problem on the
  • 04:34:12
    days where it's needed. In the real time,
  • 04:34:15
    if it pushes prices up a little bit
  • 04:34:17
    and that persists for longer, then you'll see
  • 04:34:20
    a response. You'll see a self commitment response.
  • 04:34:23
    And both of those things without the price
  • 04:34:25
    floor in the day ahead, I think it's
  • 04:34:27
    not a problem. With the price floor in
  • 04:34:29
    the real time, over time, I believe you'll
  • 04:34:31
    see a response because participants will be expecting
  • 04:34:35
    higher prices in real time. So I do
  • 04:34:37
    think that will get a response that will
  • 04:34:40
    get a positive response as opposed to rucking,
  • 04:34:42
    which would suppress prices, which would give you
  • 04:34:44
    a negative response. Having said that, I still
  • 04:34:47
    think the better solution, which Pablo highlighted we're
  • 04:34:51
    moving to, is having a better synchrony between
  • 04:34:56
    a sensible AS procurement that's marginal reliability based
  • 04:35:00
    and having that AS procurement and those marginal
  • 04:35:02
    reliabilities reflected in the shortage pricing. And then
  • 04:35:06
    you take that problem out of an administrative
  • 04:35:08
    ruck solution that needs to be extended to
  • 04:35:10
    the other two markets. Yes. And I don't
  • 04:35:12
    know that you're hearing disagreement with that. I
  • 04:35:14
    think and you and I have had these
  • 04:35:16
    conversations before. What getting to what we think
  • 04:35:20
    is optimal, sometimes we need a bridge to
  • 04:35:23
    deal with an issue. And I think what
  • 04:35:25
    we're discussing here is what ERCOT views as
  • 04:35:27
    a bridge to reduce RUC, which I know
  • 04:35:30
    is something that we've all tried to do
  • 04:35:32
    is important to the legislature as well. So
  • 04:35:34
    I think we're just maybe solving for different
  • 04:35:37
    things that with an understanding we're moving towards
  • 04:35:40
    what is more optimal finding a way to
  • 04:35:41
    bridge that gap right now. Anything else for
  • 04:35:51
    this part of the discussion with the IMM?
  • 04:35:55
    Jeff, thanks for your feedback and your input.
  • 04:35:57
    Thank you. OPEC was part of the joint
  • 04:36:00
    consumers group that commented and I think Benjamin
  • 04:36:03
    Barkley would like to make a couple of
  • 04:36:05
    comments on December. Just briefly, I think setting
  • 04:36:09
    the ASDC demand floor at $15 without having
  • 04:36:13
    any information from the real time optimization market
  • 04:36:16
    is premature and our proposal had been to
  • 04:36:19
    set it at $0 just to see how
  • 04:36:22
    the market would respond in that circumstance. I
  • 04:36:25
    know that's not the direction that the Board
  • 04:36:27
    is moving, but I did want to highlight
  • 04:36:28
    that because I don't think Keith brought it
  • 04:36:29
    up. Okay, thanks Benjamin. Any other comments or
  • 04:36:36
    questions? And as again Chad reconfirmed no one
  • 04:36:40
    else from the joint consumers group wants to
  • 04:36:42
    make comment, is that correct? Okay. With no
  • Item 12.1.2 - NPRR1269, RTC+B Three Parameters Policy Issues – URGENT
    04:36:46
    other discussion, I'll entertain a motion that the
  • 04:36:49
    board recommend approval of NPRR1269
  • 04:36:53
    RTC+B three parameters policy issues urgent
  • 04:36:56
    as recommended by TAC. So moved. Thank you,
  • 04:37:01
    Peggy. Is there a second? Second. Thank you,
  • 04:37:04
    Julie. All in favor say aye. Aye. Any
  • 04:37:08
    opposed? No. I'm Benjamin. I'll book as an
  • 04:37:11
    o. Any abstentions? Okay, this passes with one
  • 04:37:16
    no vote. At this point in time, before
  • 04:37:20
    we move on to agenda item 13, I'm
  • 04:37:23
    going to give the board a couple of
  • 04:37:24
    options. We can stop and take a fifteen
  • 04:37:26
    minute lunch break. I think if we drive
  • 04:37:29
    to the executive session, it'll take thirty to
  • 04:37:31
    forty five minutes, but I can go either
  • 04:37:33
    way. So what's your sense of what the
  • 04:37:36
    board would like to do? What's that? Drive
  • 04:37:40
    Drive Okay. Any other? I'm opposed. What's that?
  • 04:37:44
    Yeah. I mean, we've been here since 10:00.
  • 04:37:47
    If you don't want to take a break,
  • 04:37:48
    that's fine, but it's unusual. Okay. Anybody else?
  • 04:37:52
    All right. Okay. I think we're going to
  • 04:37:58
    drive through this, if that's okay. All right,
  • 04:38:02
    agenda item 13, high impact policy discussion and
  • 04:38:06
    stakeholder process. Rebecca and Ann Born are presenting.
  • 04:38:10
    Rebecca and Ann, if you would take the
  • 04:38:12
    podium. Let him go quick because people want
  • 04:38:14
    to drive fast now. Well, we don't have
  • 04:38:25
    presenters for that. Oh, there you are. Okay.
  • 04:38:32
    So you'll say we're going to be forced
  • 04:38:33
    to take a break. Thank you. This is
  • Item 13 - High-Impact Policy Discussions in the Stakeholder Process
    04:38:48
    the first time this presentation has been at
  • 04:38:50
    the full board. It's something that moved over
  • 04:38:52
    from R and M. The goal is to
  • 04:38:55
    provide kind of a holistic overview of things
  • 04:38:57
    in the stakeholder process as they develop and
  • 04:39:01
    reach the full board. So the first issue
  • 04:39:11
    we've heard a lot about over the last
  • 04:39:13
    two days is RTC. Those first three policy
  • 04:39:18
    parameter and ASTC issues were up for consideration
  • 04:39:21
    this month and moved forward. We are expecting
  • 04:39:25
    another revision request to be filed in late
  • 04:39:28
    April after another RTC+B task force
  • 04:39:31
    meeting. It'll be looking at state of charge,
  • 04:39:37
    which was separated out from the parameters in
  • 04:39:40
    PGRR and duration requirements for ancillary services. One
  • 04:39:47
    of the things I did want to highlight
  • 04:39:48
    with RTC+B, as we expect that
  • 04:39:52
    last NPRR to be at the Board in
  • 04:39:54
    June, we're also going to be going back
  • 04:39:56
    through several years of RTC related revision request
  • 04:40:00
    and evaluating the gray box language in anticipation
  • 04:40:03
    of that December 5 go live date. For
  • 04:40:12
    DRRS, we did have a workshop in February
  • 04:40:17
    that was really focused on real time issues
  • 04:40:20
    and considerations and looking at the statutory requirements
  • 04:40:23
    and constraints for DRS as a standalone AS.
  • 04:40:27
    We're expecting to have workshops throughout this year
  • 04:40:30
    to start focusing on design options and those
  • 04:40:33
    discussions will be at the future workshops. We're
  • 04:40:36
    looking at kind of the guidance provided by
  • 04:40:38
    the PUC in December through that ancillary service
  • 04:40:40
    study to focus on a primarily ancillary service
  • 04:40:45
    for operational risks and then also flexibility for
  • 04:40:49
    a mechanism as a resource adequacy tool. Any
  • 04:40:57
    questions for Rebecca? Okay. Okay. With large loads,
  • 04:41:03
    again, had the two NPRR1234
  • 04:41:06
    and PGRR115 that helped define large load
  • 04:41:10
    and establish maximum single contingency thresholds at the
  • 04:41:14
    Board this month. Caitlin highlighted the additional market
  • 04:41:19
    sponsored large load related NPRRs and the work
  • 04:41:21
    on those. We expect that to continue through
  • 04:41:24
    this year. There's a lot of interest in
  • 04:41:26
    the stakeholder process and policy issues at consideration
  • 04:41:29
    of the ledge. Angie mentioned the task force
  • 04:41:33
    moving from large flexible load to a potential
  • 04:41:35
    large load working group and that hyperscaler working
  • 04:41:38
    group or subgroup anticipated forming soon. So, this
  • 04:41:48
    is a new issue, the firm fuel supply
  • 04:41:51
    service. In January, ERCOT asked the PUC for
  • 04:41:57
    guidance on the expansion of firm fuel supply
  • 04:41:59
    service, given the survey results. We did file
  • 04:42:05
    NPRR1275, looking expanding participation of
  • 04:42:10
    eligibility to include the qualifying pipeline definition that
  • 04:42:14
    was originally adopted by TAC under NPRR1169
  • 04:42:17
    that has passed PRS first vote
  • 04:42:21
    and is waiting for an impact analysis. Commission
  • 04:42:24
    staff recently filed a memo asking for guidance
  • 04:42:27
    on some additional questions that have arised out
  • 04:42:30
    of that process. Mainly, is there a need
  • 04:42:36
    to look at procurement quantities, procurement mechanisms and
  • 04:42:40
    a desired level of reliability given the risk
  • 04:42:44
    of off-site versus on-site storage for firm fuel?
  • 04:42:48
    So there was a robust conversation at last
  • 04:42:50
    week's open meeting. The commission needed more time
  • 04:42:53
    to think through the impacts of expansion. We
  • 04:42:56
    expect future discussion in an open meeting and
  • 04:42:59
    guidance on this issue. I think the one
  • 04:43:01
    key takeaway is that NPRR1275
  • 04:43:05
    wouldn't go into effect and even if it
  • 04:43:07
    moved forward it could be gray boxed without
  • 04:43:09
    kind of that future guidance on those decisions.
  • 04:43:22
    And then, the last new issue is I
  • 04:43:25
    have it titled as the Renewable Energy Credit
  • 04:43:27
    Program. This has a long history. ERCOT has
  • 04:43:32
    been the rec program administrator since SB seven.
  • 04:43:36
    Last session, HB 1,500 required ERCOT to maintain
  • 04:43:41
    the program on a voluntary basis versus a
  • 04:43:43
    required basis. Twelveeighteen codified that regulatory change, and
  • 04:43:49
    the Commission also adopted rules under twenty fiveone
  • 04:43:51
    hundred seventy three. During that rulemaking, the Commission
  • 04:43:55
    decided that ERCOT had the option to assign
  • 04:43:58
    additional attributes to RECs, but creating new types
  • 04:44:02
    of credits or authorizing ERCOT to do so
  • 04:44:04
    was beyond the scope of that rule. We
  • 04:44:07
    now have NPRR1264, which is
  • 04:44:10
    looking to create a new energy attribute certificate
  • 04:44:13
    program, and this would put REX as a
  • 04:44:17
    sub of the EAC program and allow additional
  • 04:44:20
    fuel type or generator attributes to be added
  • 04:44:24
    to that certificate. ERCOT did something a little
  • 04:44:29
    bit unique, and that's the NPRR has passed
  • 04:44:32
    out of WMS, where it was referred from
  • 04:44:36
    PRS. But ERCOT filed before they work on
  • 04:44:39
    an impact analysis considering the scope and size
  • 04:44:41
    of this program. They asked policy questions and
  • 04:44:47
    we had four responses last week. So the
  • 04:44:49
    policy questions were looking at what the public
  • 04:44:51
    policy purposes would be served by required ERCOT
  • 04:44:54
    to develop this program And what are ERCOT's
  • 04:44:58
    core regulatory functions under PURA thirty nine thousand
  • 04:45:01
    one fifty one related to this NPRR? So
  • 04:45:08
    we anticipate spending the next month or two
  • 04:45:11
    looking at those responses, having additional conversations through
  • 04:45:14
    the stakeholder process before moving forward with an
  • 04:45:17
    IA. Okay. Anything else, Rebecca? Okay. Any questions
  • 04:45:26
    for Rebecca on the stakeholder items that she
  • 04:45:29
    discussed? Okay. I got a question about DRRS.
  • 04:45:35
    Okay. When are you expecting for it to
  • 04:45:38
    reach the board? I know Keith might want
  • 04:45:43
    to weigh in, but we do anticipate DRS,
  • 04:45:46
    those workshops, going through this year before we
  • 04:45:49
    have a new proposal. So I think the
  • 04:45:50
    timeline would be looking at new language by
  • 04:45:52
    the end of the year. Okay, thank you,
  • 04:45:58
    Rebecca. Next we're going to move on to
  • Item 14 - System Planning and Operations
    04:46:00
    agenda item 14 and as a reminder there
  • 04:46:03
    were three sub items under this yesterday, but
  • 04:46:05
    we covered fourteen point two and fourteen point
  • 04:46:07
    three. Now we're going to come back to
  • 04:46:10
    agenda item 14.1, the exit strategy for reliability
  • 04:46:14
    must run on the brunting units and or
  • 04:46:16
    lifecycle power agreements. Christie Hobbs is presenting. Christie?
  • Item 14.1 - Exit Strategy for Reliability Must Run (RMR
    04:46:20
    of Braunig Unit(s) and/or Life Cycle Power Agreements) All right, good afternoon board members. So a
  • 04:46:21
    little bit of a recap from what we
  • 04:46:23
    discussed during your special board meeting when we
  • 04:46:25
    were looking at starting to look at exit
  • 04:46:28
    strategies for going out of the contract that
  • 04:46:32
    was executed for the RMR agreement with the
  • 04:46:34
    brawning unit. Per protocol, we are required to
  • 04:46:37
    study and look at options that may be
  • 04:46:39
    feasible and be more cost effective than continuing
  • 04:46:42
    to stay in those RMR agreements over time.
  • 04:46:46
    As we discussed, one of the options that
  • 04:46:48
    we were starting to look at was looking
  • 04:46:51
    at the acceleration of the San Antonio South
  • 04:46:53
    Reliability two project. We've been in active conversations
  • 04:46:57
    with the involved TSPs, are CPS, AEP, and
  • 04:47:01
    STEC. This was a project that you approved
  • 04:47:04
    about a year ago in that South San
  • 04:47:07
    Antonio area. What they specifically went out and
  • 04:47:10
    looked at is rebuilding the line from Spruce
  • 04:47:14
    to Pawnee and Pawnee to Tango. By doing
  • 04:47:18
    the upgrades of this, they can move in
  • 04:47:20
    the timelines from the first, circuit being rebuilt
  • 04:47:24
    from December of twenty eight to September of
  • 04:47:27
    twenty twenty six and then the ending date
  • 04:47:30
    from May 2029 to January of twenty twenty
  • 04:47:33
    seven. So, we took a look at that
  • 04:47:35
    in our analysis and compared that to how
  • 04:47:39
    it reduced the need for what we saw
  • 04:47:42
    when the brawning units were retiring, and what
  • 04:47:44
    that was replacing, and did benefit analysis. Also,
  • 04:47:49
    as a reminder, this is an important project
  • 04:47:51
    because it's also one of the key elements
  • 04:47:53
    for being able to exit the generic transmission
  • 04:47:57
    constraint for that region. So, again, it would
  • 04:47:59
    bring that timeline in for getting out of
  • 04:48:02
    that constraint as well into the 2027 timeframe
  • 04:48:06
    versus 2029. At the time that this was
  • 04:48:11
    put together, we were still in that analysis,
  • 04:48:13
    but on Friday, we put out a market
  • 04:48:15
    notice that our analysis was complete. That information
  • 04:48:18
    is shared by protocol because of the sensitivity
  • 04:48:21
    of the information in our MIS Secure area,
  • 04:48:24
    And we'll work with Rebecca to be able
  • 04:48:26
    to share that report with board members as
  • 04:48:28
    well, so you can take a look at
  • 04:48:29
    the details of what we found. But to
  • 04:48:32
    cut to the chase, what we found is
  • 04:48:34
    very beneficial by accelerating that project, just by
  • 04:48:37
    getting the first circuit in, so not even
  • 04:48:39
    getting the second circuit in, we would be
  • 04:48:42
    able, to potentially exit both the Browning III
  • 04:48:46
    as well as the lifecycle agreements, as early
  • 04:48:49
    as September of twenty twenty six when that
  • 04:48:51
    line first circuit goes into service because of
  • 04:48:54
    the additional benefits. And what we found is
  • 04:48:58
    that line, by upgrading it, provides additional benefit
  • 04:49:01
    to the system above and beyond what both
  • 04:49:04
    the brawning and the LCP units would provide.
  • 04:49:07
    So it is definitely a project worth moving
  • 04:49:09
    forward with, accelerating. We'll continue to work with
  • 04:49:13
    the transmission service providers and keep you updated
  • 04:49:16
    on the status of that acceleration project. Are
  • 04:49:20
    there any questions? That was definitely good news.
  • 04:49:24
    Any questions for Christy on this issue? Just
  • 04:49:28
    a quick one. Christy, last time you had
  • 04:49:31
    a rough idea of the cost of the
  • 04:49:34
    acceleration plan? Do you have a better idea
  • 04:49:37
    now? We might could share that with you
  • 04:49:39
    in executive session. I know that CPS has
  • 04:49:43
    been in that cycle, they have not signed
  • 04:49:45
    their contracts yet. So I wouldn't like to
  • 04:49:48
    publicly share that information. But what I can
  • 04:49:51
    tell you is based off of what the
  • 04:49:53
    increased cost for the acceleration compared to the
  • 04:49:56
    benefits that are going to be provided, the
  • 04:49:58
    benefits more than exceed the acceleration cost. That's
  • 04:50:02
    fine. Thank you. Okay. Any other questions for
  • 04:50:07
    Christy on this particular subject? Thank you, Christy.
  • 04:50:11
    We're now going to move to agenda. Oh,
  • 04:50:13
    I'm sorry, Kathleen. My bad. I was just
  • 04:50:20
    gonna ask if we you know, we had
  • 04:50:22
    two circuits here. Is the thought here Can
  • 04:50:25
    you pull that closer? So is this all
  • 04:50:27
    here not to move forward with the second
  • 04:50:29
    circuit? Only the first circuit. They will continue
  • 04:50:31
    moving forward with both. So the First Circuit
  • 04:50:33
    helps us to get out of the RMR
  • 04:50:36
    for the brawning unit as well as the
  • 04:50:39
    LCP mobile generation units. By getting that Second
  • 04:50:43
    Circuit in, it provides additional benefit that helps
  • 04:50:46
    us with that overall constraint in the area
  • 04:50:49
    for the South Texas GTC. Okay. Thank you.
  • 04:50:59
    All right. Let's move on to Agenda Item
  • 04:51:00
    15, update on segment definitions and the bylaws
  • 04:51:03
    Chad Sealy is presenting. Chad? Yes. I'm going
  • 04:51:06
    do this here and try to drive fast.
  • Item 15 - Update on Segment Definitions in the Bylaws
    04:51:10
    So Caitlin already kind of give an overview
  • 04:51:12
    under her TAC report on some of the
  • 04:51:15
    discussions going on in TAC, but also with
  • 04:51:17
    our corporate members and interested stakeholders around the
  • 04:51:21
    segment definitions that are in the bylaws. So
  • 04:51:27
    there's an opportunity to potentially change the bylaws
  • 04:51:30
    and better align the segment definitions with today's
  • 04:51:33
    world of participants. These definitions have been in
  • 04:51:36
    there for probably twenty years or so. And
  • 04:51:39
    we obviously have a lot of new and
  • 04:51:41
    different participants participating in our stakeholder process. On
  • 04:51:45
    the next slide kind of gives you a
  • 04:51:47
    background on how this came up last year
  • 04:51:49
    and at the end of Q3, Q4. For
  • 04:51:52
    the last couple of years, we've been seeing
  • 04:51:54
    more data center and crypto facility participation in
  • 04:51:58
    the stakeholder process. And what we noticed over
  • 04:52:01
    the last couple of years is that they
  • 04:52:03
    had been designating themselves in either the industrial
  • 04:52:06
    consumer segment or the large commercial consumer segment.
  • 04:52:10
    And it didn't make sense that you would
  • 04:52:12
    be having a diversity of those type of
  • 04:52:16
    members in two different segments. So through the
  • 04:52:21
    current review of the segment definitions, ERCOT Legal
  • 04:52:25
    made a call that we believed data centers
  • 04:52:27
    and cryptocurrency miners should be in the industrial
  • 04:52:31
    segment. We did talk to representatives of the
  • 04:52:34
    industrial segment and the large consumer segment before
  • 04:52:37
    we made that decision. But this year if
  • 04:52:39
    you went and pulled up the membership list,
  • 04:52:42
    you would see that those type of corporate
  • 04:52:44
    members are now in the industrial consumer segment.
  • 04:52:48
    But with that we also indicated to TAC
  • 04:52:50
    and the corporate members that we wanted to
  • 04:52:51
    go ahead and talk about if there was
  • 04:52:54
    any proposed changes to that specific segment definition
  • 04:52:58
    or if members had any other ideas. And
  • 04:53:01
    what has transpired over the last couple of
  • 04:53:03
    months is a workshop along with three proposals
  • 04:53:06
    that Caitlin already highlighted. On the next slide,
  • 04:53:09
    you'll see really the next slide, sorry, Nicole,
  • 04:53:13
    you'll see that we've got three proposals that
  • 04:53:16
    touch different segment definitions, TIEC, the ERCOT Steel
  • 04:53:20
    Mills and the Texas Blockchain Council are modifying
  • 04:53:25
    the definition of industrial segment, really kind of
  • 04:53:29
    modernizing and expanding it to incorporate data centers
  • 04:53:33
    and cryptocurrency miners. There's already a definition in
  • 04:53:38
    PURA around virtual currency. They've incorporated that into
  • 04:53:41
    the proposed bylaws as well. Calpine, Constellation and
  • 04:53:46
    Vistra have offered up a proposal to really
  • 04:53:50
    bifurcate the independent generator segment into thermal sub
  • 04:53:54
    segment and into an IRR sub segment as
  • 04:53:59
    well. Neither one of these changes would change
  • 04:54:03
    the voting rights within those segments. They would
  • 04:54:07
    all still be weighted the same even though
  • 04:54:09
    they would be adding an additional representative to
  • 04:54:13
    the industrial consumer segment at the end of
  • 04:54:16
    the day. So it doesn't change any of
  • 04:54:18
    the overall voting structure within the stakeholder process.
  • 04:54:22
    And then the last one is Lone Star
  • 04:54:23
    Transmission and NextEra moving forward with changes the
  • 04:54:27
    definition of the transmission and distribution entity segment
  • 04:54:31
    really because NextEra wants the ability not to
  • 04:54:34
    be aligned in the IOU segment under this
  • 04:54:38
    definition. They want to be able to participate
  • 04:54:40
    and vote in the independent generator segment. So
  • 04:54:43
    these three proposals have been proposed to the
  • 04:54:47
    stakeholders. There's a April 18 deadline for any
  • 04:54:51
    responses so that we can continue the dialogue
  • 04:54:54
    with the stakeholders to see if anybody else
  • 04:54:56
    has any other ideas or concerns around these
  • 04:54:58
    proposals. If not, there's an opportunity to move
  • 04:55:02
    forward and invoke the process on the next
  • 04:55:05
    slide, which kind of lays out what we
  • 04:55:07
    did in 2022. As far as the process
  • 04:55:10
    that's in the ERCOT bylaws, so we may
  • 04:55:13
    be coming to the June HRNG Board with
  • 04:55:17
    an official red line to change these segment
  • 04:55:20
    definitions. There are other changes that are proposed
  • 04:55:22
    on tax procedures that would be cascaded as
  • 04:55:25
    a result of any changes to the bylaws.
  • 04:55:27
    I think the goal would be if the
  • 04:55:30
    Board wants to move forward with bylaw changes
  • 04:55:32
    to try to get this wrapped up in
  • 04:55:34
    time for the 2026 record date, which would
  • 04:55:38
    allow this alignment to move forward in that
  • 04:55:41
    year. So on the last slide, you'll see
  • 04:55:46
    again April 18 responses are due on the
  • 04:55:48
    three proposals. We haven't heard any other proposals
  • 04:55:51
    that have been officially filed. We'll continue to
  • 04:55:54
    work with the members and the interested parties
  • 04:55:57
    to kind of see if we can put
  • 04:55:58
    together a consolidated red and then talk about
  • 04:56:01
    what the opportunity is to move forward with
  • 04:56:04
    those bylaw changes at the June HR and
  • 04:56:06
    G Committee meeting. Okay. Any questions for Chad
  • 04:56:12
    on the segment changes? Okay. All right, with
  • Item 16 - Board Committee Reports
    04:56:17
    that, we'll move on to agenda item 16,
  • 04:56:20
    the committee reports. I served as a presiding
  • 04:56:24
    chair of finance and audit yesterday after following
  • 04:56:28
    Carlos Aguilar's resignation from the board. I will
  • 04:56:31
    zip through these things as quickly as I
  • 04:56:33
    can. We did three primary things. We received
  • Item 16.1.1 - Acceptance of ERCOT Consolidated Financial Statements Audit Report
    04:56:38
    the audited financial statements from the company's auditor
  • 04:56:41
    and from the CFO. The ERCOT received clean
  • 04:56:46
    or unmodified opinions for ERCOT consolidated for a
  • 04:56:50
    special purpose entity M and special purpose entity
  • Item 16.1 - Finance and Audit (F&A
    04:56:54
    Committee) N. On behalf of the Finance and Audit
  • 04:56:56
    Committee, I move that the board accept the
  • 04:56:58
    2024 financial statements audit reports for ERCOT Consolidated
  • 04:57:04
    TMFSM and TEMFN as presented by Baker Tilly.
  • 04:57:12
    I have a second. Okay, John, thank you.
  • 04:57:15
    All in favor? Aye. Any opposed? Any abstentions?
  • 04:57:19
    Okay, the financial statements are approved. In addition
  • 04:57:23
    to that, we received the normal committee briefs
  • 04:57:25
    on financial reporting investments and debt. The company
  • 04:57:28
    is in compliance with all of the policies
  • 04:57:30
    related in those areas. The most important thing
  • 04:57:35
    that the committee did yesterday was to begin
  • 04:57:38
    the first review of the proposed twenty twenty
  • 04:57:41
    six, twenty twenty seven budget. Total authorized spend
  • 04:57:45
    is $474,000,000 in 2026 and $557,000,000 in 2027.
  • 04:57:53
    The bulk of the increase for 2027 is
  • 04:57:56
    due to the start of the data center
  • 04:58:00
    six refresh project, which happens every few years.
  • 04:58:06
    When you look at that map with that
  • 04:58:09
    spend mapped against the proposed electric market growth
  • 04:58:13
    in Texas. The initial budget proposes a decrease
  • 04:58:17
    in the system administration fee from $0.63 per
  • 04:58:21
    megawatt hour to $0.61 per megawatt hour beginning
  • 04:58:25
    January first of twenty twenty six. The committee
  • 04:58:28
    will be reviewing this again in June for
  • 04:58:31
    formal approval. And there are several uncertainties that
  • 04:58:35
    the committee asked management to consider to bake
  • 04:58:38
    into their budget planning process, including tariffs, trade
  • 04:58:42
    disruptions. And if we have an economic downturn,
  • 04:58:46
    if there's a projected economic downturn, the impact
  • 04:58:49
    on electric demand. So that was the bulk
  • 04:58:52
    of the Finance and Audit Committee activity yesterday.
  • 04:58:57
    With that we'll move to HR&G
  • 04:58:59
    and I'm going to ask Peggy to make
  • 04:59:02
    her present the committee activities. Thank you, Bill.
  • Item 16.2 - Human Resources and Governance (HR&G
    04:59:08
    Committee) We had one voting item in Human Resources
  • 04:59:11
    Governance Committee and we're required by the charter
  • 04:59:14
    to do an annual review of the board
  • 04:59:17
    policies and procedures and there were no recommended
  • 04:59:20
    changes. And so Human Resources Governance Committee voted
  • 04:59:27
    to recommend that the Board approve those, the
  • 04:59:30
    current policy or affirm the current policies and
  • 04:59:33
    procedures. I'll make the motion when I get
  • 04:59:34
    done with my report. We did have several
  • 04:59:39
    informational items in the Human Resources and Governance
  • 04:59:42
    Committee. We received and discussed the Human Resources
  • 04:59:47
    Operations report, the annual status report from the
  • 04:59:51
    Retirement Plan Committee and the annual status report
  • 04:59:54
    on health and welfare activities. In addition, in
  • 04:59:58
    the materials you'll see, from the Human Resources
  • 05:00:02
    and Governors Committee, this is really for the
  • 05:00:04
    public's information, the twenty twenty four objectives and
  • 05:00:08
    key results and the twenty twenty five OKRs
  • 05:00:13
    which they're included in materials, the committee and
  • 05:00:16
    the board have discussed those on numerous occasions.
  • 05:00:20
    So that's just really for the public's information
  • 05:00:22
    in the HR&G committee materials. So
  • 05:00:28
    that concludes my report out, but I will
  • Item 16.2.1 - Reaffirmation of the Board Policies and Procedures
    05:00:30
    move that the Board reaffirm the Board policies
  • 05:00:33
    and procedures are set forth in items 16.1.3
  • 05:00:38
    of the board materials. Thank you, Peggy. We
  • 05:00:41
    have a motion. Do we have a second?
  • 05:00:44
    Julie second. All in favor? Aye. Any opposed?
  • 05:00:48
    Any abstentions? Okay. The policies and procedures have
  • 05:00:53
    been reaffirmed by the board. So next we'll
  • 05:00:55
    move to John Swainson to give the Technology
  • Item 16.3 - Technology and Security (T&S
    05:00:58
    Committee) and Security Committee report. Mr. Chairman, I think
  • 05:01:02
    most of the members of the board were
  • 05:01:03
    in the Technology Security Committee, so I have
  • 05:01:05
    no further report. Okay, thank you, John. I
  • 05:01:08
    like that one. Okay, the last item before
  • 05:01:12
    we move to executive session is other business.
  • Item 17 - Other Business
    05:01:14
    Is there any other business that any board
  • 05:01:16
    member wishes to raise in general session? Okay,
  • 05:01:21
    I'm not hearing any. With that, we will
  • 05:01:26
    take a fifteen minute break to grab our
  • 05:01:31
    lunch. We'll come back in here after you
  • 05:01:35
    grab that and we'll go into executive session.
  • 05:01:39
    So this meeting is hereby recessed until 12:13
  • 05:01:43
    twenty two rather. Okay. Chairman Gleeson. Meeting of
  • 05:01:48
    the Public Utility Commission of Texas will stand
  • 05:01:50
    in recess. Acknowledged who was going to do
  • 05:01:58
    the motion and the second. We're good? Yep.
  • 05:02:03
    Okay. Hello, I'm Bill Flores, ERCOT Board Chair.
  • 05:02:07
    I hereby reconvene the meeting of the ERCOT
  • 05:02:09
    Board of Directors. I've confirmed that a quorum
  • Item 18 - Vote on Matters from Executive Session
    05:02:11
    is present in person. We have three voting
  • 05:02:14
    items from executive session. I will entertain a
  • 05:02:17
    motion to approve the selection of Baker Tilly
  • 05:02:19
    as the independent financial auditor to perform the
  • 05:02:21
    following for the year ended 12/31/2025 is discussed
  • 05:02:26
    in agenda item ES 2.2.1. First of all,
  • 05:02:30
    the financial statements audit servicer certificate and Form
  • 05:02:33
    nine ninety review for ERCOT Inc. Second, the
  • 05:02:36
    financial statements audit and consolidation procedures for Texas
  • 05:02:39
    Electric Market Stabilization Funding M1 LLC and third,
  • 05:02:43
    the financial statements audit and consolidation procedures for
  • 05:02:46
    Texas Electric Market Stabilization Funding N. I make
  • 05:02:50
    that motion. Thank you, Steve. Do we have
  • 05:02:52
    a second and second from Benjamin. All in
  • 05:02:54
    favor? Aye. Any opposed? Any abstentions? Okay. That
  • 05:02:59
    motion is unanimously approved. Thank you. This meeting
  • Item 19 - Adjournment
    05:03:04
    of the ERCOT Board of Directors is now
  • 05:03:06
    adjourned and the webcast will be concluded.
1 - Call General Session to Order
Starts at 00:00:29
2 - Notice of Public Comment, if Any
Starts at 00:02:20
3 - Dissolve Establishment and Appointment of Reliability and Markets (R&M) Committee
Starts at 00:02:43
4 - February 3, 2025 Reliability and Markets Committee General Session Meeting Minutes
Starts at 00:03:28
5 - Commercial Markets
Starts at 00:03:55
5.1 - Recommendation regarding Real-Time Market Price Correction – Incorrect Resource Telemetry MW Values When QSE Sends Suspect Quality Telemetry
Starts at 00:04:28
5.2 - Independent Market Monitor (IMM) Report
Starts at 00:16:38
5.3 - Commercial Markets Update
Starts at 00:39:44
5.3.1 - Real-Time Co-optimization Update
Starts at 00:55:51
14.3 - System Operations Update
Starts at 01:17:24
14.2 - System Planning and Weatherization Update
Starts at 01:29:27
6 - Consent Agenda
Starts at 01:55:12
6.1 - Unopposed Revision Requests Recommended by TAC for Approval
Starts at 01:55:27
7 - General Session Meeting Minutes
Starts at 01:57:03
7.1 - February 4, 2025 General Session Meeting Minutes
Starts at 01:57:06
7.2 - February 25, 2025 General Session Special Meeting Minutes
Starts at 01:57:11
8 - CEO Update
Starts at 01:57:56
8.1 - Long-Term Load Forecast Update (2025–2031) and Methodology Changes
Starts at 02:19:52
9 - Update on Texas Economy
Starts at 02:48:06
10 - Reliability Monitor Update
Starts at 03:22:07
11 - ERCOT Lancium Patent License Agreement Disclosure
Starts at 03:29:15
12 - TAC Report
Starts at 03:35:58
12.1 - Non-Unanimous and Other Selected Revision Requests Recommended by TAC for Approval
Starts at 03:37:08
12.1.1 - NPRR1190, High Dispatch Limit Override Provision for Increased Load Serving Entity Costs
Starts at 03:50:21
12.1.2.1 - ERCOT Comments on NPRR1269
Starts at 03:54:43
12.1.2.2 - Other Comments on NPRR1269, if any
Starts at 04:13:46
12.1.2 - NPRR1269, RTC+B Three Parameters Policy Issues – URGENT
Starts at 04:36:46
13 - High-Impact Policy Discussions in the Stakeholder Process
Starts at 04:38:48
14 - System Planning and Operations
Starts at 04:46:00
14.1 - Exit Strategy for Reliability Must Run (RMR) of Braunig Unit(s) and/or Life Cycle Power Agreements
Starts at 04:46:20
15 - Update on Segment Definitions in the Bylaws
Starts at 04:51:10
16 - Board Committee Reports
Starts at 04:56:17
16.1.1 - Acceptance of ERCOT Consolidated Financial Statements Audit Report
Starts at 04:56:38
16.1 - Finance and Audit (F&A) Committee
Starts at 04:56:54
16.2 - Human Resources and Governance (HR&G) Committee
Starts at 04:59:08
16.2.1 - Reaffirmation of the Board Policies and Procedures
Starts at 05:00:30
16.3 - Technology and Security (T&S) Committee
Starts at 05:00:58
17 - Other Business
Starts at 05:01:14
18 - Vote on Matters from Executive Session
Starts at 05:02:11
19 - Adjournment
Starts at 05:03:04