GridMonitor

04/29/2025 09:30 AM

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00:00:00
We do have a full agenda today.

My name is Robert Golan.

Hopefully, everybody on the web, can see the the the presentation.

We did do an audio check earlier.

We do have a full agenda as you could see on the screen.
00:00:17
We'll start with the antitrust and miscellaneous updates as we always do.

We have a number of EIR status updates.

We have the combined Oncor Delaware Basin stage 5 project and the WETT Delaware Basin stage 5 alternative project.

We have the heart ring to Upland 138-kv line and Benidam auto transformer edition project, the Baytown area load edition, Texas A&M University system campus reliability project.

The Aransas passed to Rhinecone 69-kv line rebuild project, the Roscoe area upgrades.
00:00:54
At that point, we'll transition to the project overview for the Southern DFW boat interconnection and general grid strengthening project.

Oncor will be presenting that.

ERCOT will follow that up with the scope for the project.

Then we'll transition to the Brazos Hamilton County conversion project overview, again, followed by the scope for that project.

We do have an update on financial assumptions for ERCOT economic planning criteria.
00:01:26
And then last but not least, the long term, load forecast presentation.

Are there any questions or comments with the agenda as posted?

K.

Seeing none.

Couple housekeeping items.
00:01:45
If you are speaking, please state your full name and the organization that you are representing.

If you do have any questions or comments, please enter them, either in the chat or just, make it known that you have a a comment or question in the chat, and then we will get you into the queue.

And then we will, address comments after each presentation.

So we do again, we do have a lengthy agenda today.

So without any, delay, we'll we'll dive right into it.
Item 1 - Antitrust Admonition - 9:30 a.m.
00:02:21
On the screen right now, we have the antitrust admonition.

I'll pause for a moment, allow everybody, to read that.

Okay.

Moving on to the next item, miscellaneous updates.
Item 2 - Miscellaneous Updates
00:02:47
Does anybody have any miscellaneous updates they would like to provide to the group?
00:02:56
Okay.

Seeing nothing in the room and, no no questions in the queue.

This will move us on to the first presentation that we have for today.

This is the EIR status update for the Delaware Basin stage 5 project.

Tanzilla from ERCOT will be presenting.
00:03:15
So whenever you are ready, Tanzilla, the floor is yours.

Thank you, Robert.
Item 3 - EIR Status Update – Combined Oncor Delaware Basin Stage 5 Project & WETT Delaware Basin Stage 5 Project Alternative
00:03:19
Good morning, everybody.

My name is Tanzilla Ahmed, senior transmission planning engineer with regional planning, at ERCOT.

I'm here to present the combined Delaware Basin stage 5 project and alternative, ERCOT independent review study status update.
00:03:38
So just to recap, Oncor has submitted the Delaware Basin stage 5 project for RPG review, back in May 2024.

This was a tier one project estimated cost at $744,600,000.

This project did require a CCN filing.

It does require CCN filing.

An estimated in service date is, December of 2029.
00:04:05
This project need is to address the reliability, issues, both thermal overloads and voltage violations, in the, Delaware, Delaware Basin due to the significant load growth, in the far far west weather zone.

The project need and the solution was identified in the 2029, ERCOT, Delaware Basin load integration study.

WETTT has submitted an alternative option for RPG review, back in June of 2024.

WETT's portion of this option is estimated to cost at $3.00 $305,500,000.

WETT ex estimates a total cost savings of up to approximately $67,000,000.
00:04:56
This option also require, will require CCN filing.

Expected in service date is December 2028 for WETT's portion of this project, option.

So ERCOT is currently conducting a single ERCOT independent review by combining both of these projects, together.

Oncor and WETT has presented a project overview, and ERCOT has presented a scope overview for this EIR in September of 2024 at the RPG meeting.

Since then, ERCOTd has presented status update at the January 2025, RPG meetings.
00:05:43
So this is a I will not go over this.

This is the details of Oncor's proposed project.

One thing to note, the green, highlighted fonts, that is, to show the, commonality between the Oncor and WETTs option.

Any, font that are in green is, common in both of the options.

So this is a map of the Oncor's project.
00:06:10
So drill hole update drill hole, and create a new, 345-kV line from, drill hole to, Clearfork and also, update the existing upgrade the existing, Lamesa substation and convert it into a 345 to 138-kV trans substation, by adding to transformer at Lamesa, 345 to 138-kV, and also remove the, 138-kV to 69-kV transformer to, Welch tap, which will be called pivot, and converting that Welch tap to, 138-kV to 69-kV transformer and upgrading the 69-kV, to 138-kV going from Lamesa to Welch Tap.

Once the Lamesa is done, then, also do a, build a new, 345-kV double circuit from Clearfork to Lamesa, and then Lamesa to Faraday.

And, also, Faraday will be upgraded, for the new, 345-kV double circuit connection and also tying the existing long draw to Scurry, into Faraday Substation.

So this is a, again, the recap of the WETT detailed proposed project, and this is the map of it.

The difference between the two, option is, the double circuit 345-kV line going from Clearfork to directly to Faraday bypassing the Lamesa.
00:07:55
However, WETT is proposing a new 138-kV line going from Longdrone to Lamesa.

And then Oncor will still be, doing the upgrade at the, Welch tab, remove removing the, 69-kV to Welch tab and upgrading the 69-kV line, and also upgrading the Lamesa to for the new 138-kV, line.

So recap of the preliminary results shows, both of the options to have no reliability, violations per NERC and ERCOT criteria.

Recap of the long term load serving capability.

It shows Oncor and web to have approximately similar, long term load serving capability into Lamesa.
00:08:51
Also preliminary, recap of the preliminary results for the plan maintenance outage also shows both options to have no violations, issues with the maintenance, outage analysis.

So status updates since the last RPG meeting, updated cost estimate and feasibility assessment was provided by the TSP.

Additional analysis and assessment was done, such as, generation addition sensitivity analysis, load scaling sensitivity analysis, and also, SSR assessment.

So updated cost and feasibility assessment for the options, TSPs has provided, the feasibility assessment and, provided final cost estimate for both of the options with the new, cost estimate, Oncor, cost, for the Oncor's project is $855,300,000.

It still requires a CCN of 220 miles.
00:09:54
It is feasible by both entities.

Oncor expects, their portion to be done by December 2029, and WETT's portion will be done by December 2028.

For the WETT, estimated cost is $871,000,000 CCN requirement is for 232 miles.

It is also feasible by both entity, and the same ISD, for this option as well.

So updated cost comparison for both options.
00:10:28
Both option meets the project, need in the area.

Both option meets, NERC and ERCOT, reliability criteria and provides long term load serving capability.

CCN mileage, Oncor has 12 miles less than WETT's option.

Expected final expected ISD for both of this option is December of 2029.

Again, estimated cost for Oncor's option is $855,300,000 and for WETT's option is $871,000,000 and then both options are feasible by both entity.
00:11:07
So Oncor's option is the least cost option and requires less amount of, CCN mileage.

So, on, ERCOT preferred option, option Oncor's option was selected as the, ERCOT's preferred option because it addresses the project made in the Delaware Basin, and it also meets the, ERCOT and NERC reliability criteria.

It improves long term load serving capability for the future load growth in the area, requires the least amount of CCN mileage among the two option, and is, the least, cost option.

So additional analysis, were done.

Congestion analysis was performed to, for the preferred option using the 2024 RTP 2029 economic case.
00:12:01
The preferred option did not result in any new congestion within the study area.

Generations, addition sensitivity analysis, was conducted per planning guide section 3.1.34a, archived perform day generation addition sensitivity by adding new generation listed in appendix, B2 of this presentation, To the, preferred option case, the additional resource were modeled following the 2024 RTP methodology.

ERCOT determined, relevant generation did not impact the preferred option.

Load scaling sensitivity analysis, per planning guide section three point one point three four b, ERCOT performed a load scaling sensitivity and conducted that the load scaling did not have any material impact on the, project need.

SSR assessment was also conducted for the preferred option par nodal protocol section three point 20 two point one point three.
00:13:09
ERCOT found no adverse SSR impact to the existing and planned generation resources at the time of the study.

So ERCOT, recommends Oncor's option, which is estimated to cost approximately $855,300,000.

Expected ISD for a project is December of 2029.

Keep in mind, the expected ISD is tentative and are subject to change based on the requirements for the various approvals, right of ways, acquisition, and or construction progress.

CCN filing will be required, to construct a new drill hole to Clearfork 345-kV double circuit transmission line on a new, right of way approximately this is approximately hundred and five miles long.
00:14:02
Constructing the new, Clearfork to Lamesa 345-kV double circuit transmission line on new right of way, this line is approximately 77, miles long.

And finally, reconstructing the new Lamesa two Faraday 345-kV double circuit transmission line on a new right of way, and this, portion, is approximately 38 miles long.

So this is again, recapping the project recommendation and also the map.

So next step, intensively timeline.

EIR report, to be posted in, on MIS, in May of 2025.
00:14:46
EIR recommendation going to, TAC in May 2025.

And, finally, seek board of directors endorsement in June, board meeting.

That concludes my presentation.

I thank you for your time and open up the floor for question.

It looks like we have a question in the room.
00:15:14
Hi, Tanzila.

This is Yang from WETT.

Hi, Yang.

Yeah.

Hi there.
00:15:19
First of all, I wanna appreciate my, your efforts for this project.

I think Erica did a excellent job because these two options, they're very close.

As you can see from the results, you know, two options there, you know, performance wise, cost wise, system wise, you know, from each individual, criteria, they are very close.

So it's not a easy job to tell which one is a better option, but Erica did a great job, doing this and put everything, clearly on the on the slides.

I really appreciate, Tanzila, your your efforts.
00:15:53
And then I have, some follow-up questions regarding the, decision making process.

Can you go to slides 14?

And in this slide, it summarize, why Oncor's option was selected, by ERCOT, because first, it addressed the the product needs in Delaware Basin area and meet all the and reliability, criteria.

And the second, improves long term load serving capability for future load, growth in Lamesa area.

And, also, the season amount, of Oncor's option is slightly less than west option.
00:16:43
And then the last one is the least cost option.

Okay?

I wanna I wanna dig into each one by one.

First, address the, Delaware Basin load need and meet all the ERCOT and, criteria, both options meet meet this.

There's no question.
00:17:03
And and the second one, improve the long term load some capability in Lamesa area.

These options are very close, but, WETT has a slightly better loads of reconvenability.

It's a 400 megawatt versus three eighty.

Right?

And then requires the least amount of CCN.
00:17:23
So I I think the CCN requirement is you cannot just tell which one is better, which one is worse based on the number itself.

What really matters about CCN number about CCN is not a number.

It's actually how many land owners impacted.

Because the cost the longer the CCN doesn't mean the the the higher the cost.

Cost already embedded in the cost estimate.
00:17:52
Right?

So two thirty two CCN versus two 20 CCN, you cannot just say two thirty two is definitely worse than two 20.

So where what really matter is the landowner being impacted.

So routing 345-kV lines, double sectors into Lamesa area, which is a very populated area, means it impacted many more land owners than just to build a single circuit, 130-kV from Landwall to Lamesa.

And, based on our database, there are at least 30 more land owners in packet if you're routing through a 345-kV double circles through Lamesa area.
00:18:34
That's what really matters in terms of CCN.

Right?

For the last, the least cost option, I agree, Oncor's cost is less, but by how much?

If you check the load serving capability, we have more than 5% higher load serving capability in Lambda area, and we only have 2% higher cost.

How does ERCOT compare this difference?
00:19:02
Right?

So reliability and the low swimming capability is priority criteria for this project, if I'm not mistaken.

Because the whole purpose of routing through Lamesa with that 345-kV double circuit is to serve the load and solve the reliability concerns in Lamin's area.

And wise option has better capability in that area.

Right?
00:19:26
How does ERCOT compare this benefits versus this minimal higher cost?

Right?

So and another reason another factors I think we need to consider is the reliability need in Luminess area is already observed in 2027, 2028 this year.

And our proposal can serve the liabilities need in that area much faster.

You don't have to wait for the three four kV lines to to be constructed to serve Lemnitza area, which takes much longer time.
00:20:05
You can see in the slides, Oncor's option will be in service by end of 2029, but ours option can serve that area through one single one straight kV line to solve that reliability concern in Lamesa area.

Right?

So you can decouple the construction of 13 kV from the three four kV, which give us more flexibility and the faster in surface state.

So all of these factors, I don't think is considered in this comparison, which I would like our call to give more guidance or explanation how this decision being made and how those factors being considered.

Thank you.
00:20:51
Oh, thank thank you for that.

This is Robert Golan from ERCOT.

I guess one one thing to know, I I think the the listing of these, decisions would need to be reorganized, because for every project, first and foremost, does it address the need that the project, identified?

Does it meet the ERCOT and NERC reliability criteria?

That's that's first and foremost for any project that we review.
00:21:21
Second major consideration is cost of the project.

As stated in the protocols, you know, we will be looking for the most economic solution possible to address the need that was identified in these projects.

As stated with the the cost estimates, or or, Oncor's option was about $16,000,000 cheaper, than the the WETT proposed option.

As far as it goes into the long term load serving capability, They they were very close about 20 megawatt difference.

We did, you know, take a quick look at the the sensitivities, that we ran, and we believe that with that, you know, additional $16,000,000, if the cost was exactly equal, you would be able to improve Oncor's long term load serving capability into the Lamesa area.
00:22:21
Again, the the main priorities for these projects would be, does it meet the reliability needs and which one is the most economic solution?

Those are the main main priorities.

If those two are completely equal or relatively equal, you know, within a million dollars or two of each other, additional considerations, will be looked into to see if one option outperforms the other option.

So if there was a significant, you know, a thousand megawatt difference in long term load serving capability, that would take a a, you know, a bigger consideration.

But because the two options are almost identical with the long term load serving, there there wasn't a huge consideration that, you know, one one option well outperformed the other option.
00:23:09
And the same thing with the CCN mileage, you know, it isn't a, you know, a decision, a main decision factor.

It is just an additional point of reference when comparing these two options.

Obviously, the CCN mileages could change during the process, but what was identified in the option discovery was that, you know, Oncor did have, you know, less overall CCN mileage.

Maybe not total square, square miles, of CCN, but the length of the CCN, was less in Oncor's option.

As far as getting, the project into the Lamesa area, we were looking at, again, the 2029, need.
00:23:55
We were addressing, you know, 28 or 27 need for this project.

The the project was identified and studied for 2029, which this full project would be completed at that time.

So though those those are our comments.

Thanks, Robert.

I appreciate your explanation.
00:24:19
I have a follow-up question regarding your comments.

So sounds to me that, the the the new breaker here is the cost.

Right?

Because, the the long term loss rate capability is in and the reliability performance is the same, and then the real deal breaker is, the cost.

And then, does our card have, criteria, like, how much or how big the cost difference is so that it become the deal breaker?
00:24:51
So, for example, if the cost between these two options is, like, $2,000,000, in that scenario, how does ERCOT pick between two options?

I mean, I I need some, clarification or, some guidance so that, you know, for our future planning job, we can, dig more into the cost, to so that we can propose, more cost effective options here.

Thanks.

No.

That that's, you know, def definitely warranted the the comment and appreciate the comments.
00:25:31
Yes.

If if the cost is, you know, almost identical between the options, that's when we really start focusing on additional benefits of of the other options.

We might do additional sensitivities that are not, you know, our normal, study process to help determine which which project is the the best overall option.

I know this has been a question.

We don't have a cost per megawatt for long term load serving capability, because, obviously, you know, if you have to upgrade 345 to get additional capability into that area or upgrade 69-kV to get additional serving capability into the areas, they the cost per megawatt number is, you know, completely different between those those types of upgrades.
00:26:20
So we do consider it, but, again, it's not the main driving factor.

It's does it meet the reliability need and which one is the most economic?

If, again, the costs are identical, that's when we would really start diving deep into the the additional analyses to determine and even go so far as, you know, looking at congestion for both, you know, economic savings for both options if those costs were almost identical.

Thank you, Robert.

Again, I wanna appreciate ERCOT for the office, in this project.
00:26:59
And I'm glad this project move forward because we really need transparent upgrades in the area to support all the loads and the reliability issues.

Thanks.

Thank you.

Are there any more questions in the room?

It looks like the queue is empty.
00:27:18
So thank you very much, Tanzilla, for that presentation.

That does move us on to the next EIR status update.

This is for the Oncor and LCRA heart ring to Upland, 138-kV line edition, and the Benidam auto transformer edition.

Tanzilla will also be presenting this presentation, so the floor is yours.

Thank you, Robert.
Item 4 - EIR Status Update – Hartring to Upland 138-kV Line and Benedum Autotransformer Addition Project
00:27:44
Again, good morning, everybody.

Here to present the, Oncor and LCRA heart ring to upland 138-kV line and Benedum auto, addition project EIR status update.

So recap, Oncor and LCRA TSE submitted the, heart ring to upland 138-kV line, and Benadam auto transformer edition project for RPG review, in August of 2024.

This is a tier two project with the estimated cost of $94,000,000.

This project does will require a filing of CCN.
00:28:22
Expected in service date for Oncor's portion is summer of 2025.

And for LCRA, for the this project was June 2026, which is coincides with the completion of the, 22RPG010 Bearkat to North McKinney and Sand Lake 345-kV transmission line addition project.

This, project addresses post contingency thermal violations, and voltage violations due to significant oil and gas load growth in the area.

ERCOT is currently conducting an ERCOT independent review for this project.

ERCOT and LCRA TSE, presented in project overview, and ERCOT has presented a EIR scope for this project, at the October.
00:29:13
ERCOT since provided a status update at the March RPG meeting, March of 2025.

So recap of the preliminary, results for the reliability assessment project need, shows there's, thermal violations under, N-1.

There's two thermal violations under N-1 and, 10 voltage violations, also under N-1, which is P1, P2 one, and P7.

Recap of the project map, with violations seen by ERCOT.

Motor man to crane 138-kV line overloaded and also Benedum to Alfred 138-kV line overloading.
00:30:01
The, also, voltage violation seen at Lonesome Draw, Benedum, Upton, Upland, and Centralia.

So recap of the preliminary results, the project sorry.

Options evaluation shows option one, three, and four with no violations, but option two has one, two X-1 plus N-1, thermal violation.

So for, moving forward, option one, three, and four were selected as the shortlisted option for further evaluation.

So recap of the option the shortlisted option, option one, proposes to build a new 345-kV Benedum substation adjacent to the existing 138-kV Benedum substation.
00:30:54
We're adding to, auto transformer at the new station connecting, and then also cutting into the North McKinney to Bearkat 345-kV line.

Only one circuit.

And also upgrading Benadam to Alford on 138-kV line, upgrading the, Ringo substation, adding new breaker configuration, and also, constructing a new upland to Hartring 138-kV double circuit transmission line.

Option 3 is, upgrading, Motorman to crane 138-kV line, upgrading Benadam to Alford 138-kV line, upgrading the Ringo substation similar to option one, and also building the, Upland to Heart ring, double circuit, 138-kV line.

And option four has the new Benedum, 345-kV substation built, next to the, existing, Benedum substation, adding the true transformer and cutting into the, the new North McKinney to Bearkat, sir one of the circuit, and then also proposing to build a new double circuit, kV line from Upland to, Wolfcamp.
00:32:20
So status update, since the last RPG meeting, based on feedback from TSP, we evaluated a new option, option five, which is basically a upgraded option four based on the, TSP feedback.

We also conducted long term load serving capability assessment, planned maintenance outage, evaluation, and also, TSPs has provided cost estimate and feasibility assessment.

ERCOT also selected the preferred option and conduct a conducted a, congestion analysis.

So option five is basically, the Benedum Substation station stays, that portion stays as is from option four.

The only difference is, rebuilding the new, 138-kV double circuit line from Upland to Santa Rita instead of Wolfcamp, because, Santa Rita is already a breaker station.
00:33:22
So we, ERCOT has reconducted the option evaluations for our reliability assessment, and option, five as a, thermal violation under X-1 N-1.

Long term load serving capability assessment was conducted on the three shortlisted option and the new option five, where option one, has 1,056, approximately 1,056 megawatt of incremental load serving capability into the study area.

Option 3 has 600, 65.

Option four has 265, and option five has four sixty six.

So option show one has the highest incremental load serving capability into the, study area.
00:34:12
Planned maintenance outage evaluation was also conducted.

Load level in the Far West weather zone was, scaled down to 96%, of the summer peak load case in the study based on ERCOT load forecast, historical road, and ratio of the residential commercial load from TSP in, and in order to mimic the non summer peak load case condition.

N minus two contingencies were tested, as proxy to N-1-1 and then, tested the applicable by, violating contingencies with system adjustment.

The transmission elements in the study area were monitored for this evaluation.

For this evaluation, the results shows option one have no reliability issue, while option 3, 4, and 5 to have voltage or, thermal violations.
00:35:11
Cost estimate and feasibility, assessment was conducted, on the, shortlist option and option five by the TSPs.

One has an estimated cost of, $97,700,000 It does require a, new CCN for, nine miles.

It is feasible by, both entities, all entities, and, estimated in service date for portion is November of 2025, and, LCRS portion is May of 2028.

Option 3, which has the lowest cost option, is a 74.7, million dollar.

It has the similar, mileage as option one of nine miles, and has the same ISD as option one.
00:36:00
Option four and five has the highest cost estimate, of approximately hundred and 14.3 for option four, and a hundred and 17 for an Option 3.

And CCN mileage is, for option four, 14.4.

And for option five, it's 15.5.

For this option, the expected in service for both of this option, the expected in service date for Oncor's portion is December of 2028, and for ALCRS portion is May 2028.

So cost compares so comparison of the shortlisted options or all the remaining options.
00:36:42
Option one addresses the project need in the area, along with option, or all options actually meet, addresses the project need in in the area.

However, only option one meets DNRG and, ERCOT reliability criteria.

All of the options have long term load serving capability.

However, option one has the highest, long provides the highest long term incremental long term load serving capability.

CCN miles for option one and three is nine miles.
00:37:17
And for option four, it's 14.4, and option five, it's 15.4.

Expected ISD for option one and three is, for Oncor's portion, November 2025.

LCRA's portion is May 2028.

And for option four and five, it's, December 2028 and May 2028.

Estimated cost on Oncor sorry.
00:37:42
Option one is 97 point, 7.

Option 3 is 74.7.

Option four is, $1.14.3, and option five is hundred and $17,300,000.

And all of these options are feasible by the TSPs.

So our option one was selected as Oncor, ERCOT's preferred option because it addresses the project need.
00:38:12
Sorry.

Not the Delaware Basin.

It's in the, forest in the project area.

Meets ERCOT and NERC reliability criteria, improves long term load serving capability, and requires the least amount of, CCN mileage.

Congestion analysis was also performed, using the 2024 ITP 2029 economic case, and the preferred option did not result in any congestion within the study area.
00:38:44
So ERCOT recommends option one, with an estimated cost of $97,700,000.

It has two expected ISD for Oncor's portion.

It's November 2025.

And, for LCRA, it's May 2028.

CCN filing will be required to construct the new Upland to Hartgreen, 138-kV double circuit line, which is approximately nine miles long.
00:39:11
This is a description of the project option, and this is the map of the, proposed ERCOT recommended option, which, again, building a new, Bennet m 345-kVs, station by adding to 800, MVA transformer at the new substation and also cutting into the one of the circuit, with the new North McKinney to Bearkat 345-kV line, upgrading the Ringo substation, and then also adding the, constructing the Upland to Hartring 138-kv double circuit transmission line.

So tentative timeline or, EIR report is to be posted on MIS, May of 2025.

That concludes my presentation.

Thank you for your time, and I open up the floor for question.

Well, it doesn't look like there's any questions in the room, and the queue is empty.
00:40:15
So thank you very much, Tanzila, for that presentation.

That brings us into the, third EIR status update.

This is for the Baytown area load addition project.

Ben from ERCOT will be presenting to the group.

So when you're ready, Ben, the floor is yours.
00:41:48
We're not hearing any audio?

Yeah.

We'll be going the the.

Okay.

Can you hear him now?
00:42:00
Okay.
Item 5 - EIR Status Update – Baytown Area Load Addition Project
00:42:00
My name is Ben Richardson, with ERCOT, and, I'm doing the, status update for the, CNP Baytown area load edition.

Okay.

So just to recap, we've done, this this project was submitted by CNP back in September.

It's a tier one, a project, that estimated cost one point or a hundred and 41,000,000.
00:42:25
Estimated in service day of, January 2028, it's addressed thermal and voltage violations caused by the, new, 500 MVA load, for, related to a new customer in the Baytown area.

CNP presented, their project overview, and ERCOT presented our, project scope in November, RPG.

And then we did updates, status updates in February and in March.

So this project's still, under Kirk, independent review.

So just to recap on, the violations that were seen by CNP, overloads, on, Chandler, Chandler View to, Landell circuits, overloads on the circuits coming in and out of the new sub, voltage violations, surrounding, you know, sort of the new sub.
00:43:21
And then there was a thermal overload on the, 30 kV, Grant Herman, line.

It's about 25 miles away from this area, but it's it is in downtown, Houston.

Hmm.

In terms of, the way that we constructed the base case, we did, start with the we first started with the 2028 summer peak, but then we didn't see a lot of violations.

So we choose the 2029, summer peak case.
00:43:50
We, installed, transmission upgrades based on the October 2024 tippet.

Those upgrades are listed in appendix a.

Remove projects, based on, 2020, or or we have you've we removed projects that were not approved in the 2023 RTP case.

Projects that were removed, which are none are, appendix b, and then, generation upgrades, generation updates, planning guide six point nine point one based on summer, GIS and, are listed in appendix c.

The, generators were dispatched, consistent with 2024 RTP methodology.
00:44:37
Load, of course, we added the, new confirmed load, 500 MVA with a 95 power factor.

We used the interconnection configuration that was selected by CNP, which involved, 230 kV lines that would pass, by the existing substation.

So one of which would be the, Cedar Bayou East to, Decker, front 138-kV line, and the other, Texas to, S. R. Bertron, Hundred And Thirty kV lines.

In order to adjust for loads, the remaining loads outside of the, study load study region were adjusted.

Preliminary recap of the results.
00:45:24
We did our reliability assessment at first, and we didn't see a lot of violations.

Just one thermal violation, that was, showed up in all of the reliability results.

So we had to, go ahead and do the plan maintenance, evaluation based on planning guide, section four point one point one point eight.

And, we did see violations there, of course.

So the, so we created the off peak conditions, based on scaling down the East Coast load by, to the 8085% level, and we did.
00:45:56
So let me get into a little bit of detail about how we do this.

We doN-2 that serve as a proxy for N-1-1.

If you see violations, then we'll do N-1-1 with, load flow solutions between the first and second contingency.

And when we see violations for that, then we have to go to prior outage cases in which we construct, prior outage cases for each of the violations, and we actually do SCOPF between the first and second, contingencies.

But we also reverse the contingencies.
00:46:27
We do, if we see prior outage, if we see violations for N-1-1 based on a load flow, solution, then we will, create a power prior outage case for each of the, contingencies so that we, have full coverage.

And so based on all that, we we saw about, 13, thermal overloads and lots of voltage violations that had to be corrected, using various, plans.

So, again, let let me get into a little more detail about how we did this.

So we, I mean, one, we did not restrict, the violations that we, that we, sought out to address two violations that were exclusively related to adding the load to the case.

So some of the violations that we addressed, would be there whether or not, the load was added.
00:47:16
Also, the geographic scope was pretty much it was it was restricted to, Chambers County and Harris County, but that's fairly, densely populated and dense pretty pretty dense, urban area with a a dense network.

And so, you know, we ended up with about 40 different, prior outage cases that we had to examine.

So, for option one, this is the, CNP, preferred option.

If we're looking at the Midtown oh, I'm sorry.

Let me go back to this.
00:47:50
So when when I describe these options to you, what I'll be doing is looking at the different sections of Houston, so that, you know, we're not zoomed out too far so we can zoom in a little bit.

So we'll look at, Baytown First.

That's where the load is.

Then Midtown, which is really densely dense area of Downtown Houston.

And then, Southeast, which is basically, PH Robinson north and Northwest of PH Robinson and then North Houston, which is on the North Side Of Houston.
00:48:19
Okay.

So first, for option one, look at Midtown.

Again, this is, the CMP preferred option, involves the upgrade of the Grant to Herman, a 30 kV transmission line.

Option two, to address all of the violations that we saw, or or yeah.

That's that.
00:48:42
That CMP saw, involves upgrading, the thermal rating from channel of view to Landau.

But on that case, they don't need I think they're able to do that, just, with, performing some equipment upgrades within the substations.

There's no a reconductor involved.

And then also, upgrading the, 30 kV line from SR Bertron to, Decker and to, and Decker, doing some, no.

I'm sorry.
00:49:17
From SR Bertron to the new subs as well as, some Decker Decker upgrades that are that they saw, that were needed, and also Baytown to Exxon.

And then, Cedar Bayou, to, to the new sub Cedar Bayou substation as opposed to the, power plant to the new sub.

In terms of, substation upgrades, this option involves adding a 30-kV mean, a hundred MVA, cap bank at, Cedar Bayou East, power plant as well as some, short circuit, rating up free upgrades at the SR Bertron.

Some, yes, short circuit serving capability at SR Bertron.

So this is textual, yeah, fault duty, upgrades at SR Bertron.
00:50:16
So this is a textual kinda description of of the, option one there.

For option one, there were no upgrades in, Southeast Houston nor in, North Houston.

Option two, a little more, more upgrades in the downtown or midtown area.

So it does involve the upgrade of the, upgrade of the, grant to Herman, the same as option one, but also upgrade from, Memorial to, Woodcreek to, Brickmore.

In addition to that, upgrade from Gulf Gate to, Knight To Plaza.
00:50:49
That circuit passes by a bunker, but also, upgrade of the HO Clarke to a Bunker, transmission line.

For option two in terms of the Baytown area, option two would involve the upgrade of the SR Bertron to a new sub, as well as upgrade of the transmission line that extends from the, cedar bio power plant all the way to the new sub, as well as, upgrades on some of the lines that are kinda slightly to the north, east of the area.

So, Hopson connects, directly to, Warview.

And sorry, Warview was listed a little little far above there, above the little dot.

But this involves an upgrade from Hobson to Warview, upgraded the transmission line, also a hundred kV transmission line from Mont Belvieu to, Bryan to Dalton.
00:51:46
And then, the addition of a cap bank at, Miller.

Option two for the Southeast, involves upgrade of the 30 kV transmission line from PH Robinson to Seabrook to Hanna, to Hunter, as well as installing, additional or a cap banks at Bayway and at, South South Houston, which is the, Ellington tap.

Option two, North Houston, would involve, installing additional cap banks at Humble and, cap banks at Treaschwig.

So this is a textual, description of option two.

Option 3, for, three of the four, regions or areas of Houston.
00:52:42
It's exactly the same as option two.

It's just the, Baytown area that's where it's different.

So, option two, for Midtown or Option 3 for Midtown is the same as option two.

Option 3 for Baytown, we looked at, an option to, extend the double circuit 345-kV aligned from Sheldon to the new sub and then another double circuit 345-kV line from new sub to, center.

And then, again, so for Option 3, the upgrades in the Southeast are, the same as the, upgrades, for option two and, the same, for North North Houston.
00:53:29
The, Option 3 upgrades are the same as option two.

Again, these are the textual description of the upgrades.

And, so, our time timeline, we still, feel like we finished this project by, q two, have it to the board in June in June, and, and provide further updates in, next next month's RPG.

So that's it.

Any questions on this project?
00:54:04
I don't see any hands in the room.

The queue is empty for this project, so thank you very much, Ben.

There there is a question in the queue about the update for the 765-kV transmission.

We'll give a a brief update at the end of RPG today.

I believe Prabhu will be giving that update.
00:54:26
So he he's tied up this morning, but he'll he'll give an update to the group.

So with that, we're moving right along to the next EIR, status update.

This will be for the Texas A&M University System, Relis Relis campus liability project.

So at this time, I will turn it over to Ying from ERCOT, and she will walk us through the status update.

So the the floor is yours whenever you're ready.
Item 6 - EIR Status Update – Texas A&M University System RELLIS Campus Reliability Project
00:55:00
Good morning, everyone.

This is Ying Li in ERCOT planning.

So I'll present the ERCOT independent review status update to the BTU Texas A&M University System, Riley's campus reliability project.

A good introduction, this project is a tier one project with the cost estimate about, $271,000,000, and the CCN will be required.

Estimated in service date is May 2029.
00:55:32
We have presented the stethoscope in the March RPG meeting as we presented there.

This map shows the reliability violations seen by BTU.

So, basically, pretty much all the BTU system is overloaded with the, new confirmed load.

So we presented the study assumptions for ERCOT independent review.

So, basically, we use 2024 RTP 2030, some of the case, as well as the, maintenance case, to perform this study.
00:56:08
Again, the main point is that this study is driven by the new confirmed load about 378 megawatt, in 2030.

With that, we performed the reliability need analysis, and these people summarize the reliability violations in the study area.

So, basically, we see, violations in, all different, competency conditions.

Low voltage there's in N-0, both thermal overloads and, low voltage there's on the N-1 as well as additional thermal overload on the G-1, N-1, and X-1-1

And for some, overload, the thermal overload is really high even on the N-1 contingency condition.
00:57:02
This map shows the reliability need seen by, ERCOT.

So, yeah, ERCOT use RTP case is a little bit more clean than SSWG case.

So Question number.

Less or less.

Very quick.
00:57:17
Yes, please.

We don't have a record on the meeting.

Kelly asked me to record certain part.

On Teams?

Okay.
00:57:26
You're good.

People on the line, please make sure that you're muted.

Thank you.

Yeah.

So this is the, reliability violations seen by ERCOT.
00:57:46
Just mentioned, since the overload, even on the N-1 is really high, which indicate, multiple connections will be needed to connect it to Riley substation to solve the load.

To solve this, resolve these violations, ERCOT, studied four options.

This is the option one, which is BTU, proposed option.

Preferred option.

This option is, expand the existing Riley's one hundred k v substation and install two transformers.
00:58:24
And then add a new 345-kV double circuit line from TNP one to Raleigh's about, 40 miles.

Inside the BTU, there are some 100-kV upgrade.

First is add a new Riverside, 100-kV substation, which cut into the existing Dansby to Thompson Creek, 100-kV line.

And they add a new 100-kV line from Riverside to RELLIS.

And also connect, existing cooks points to still store, the new 100-kV line.
00:59:04
Also, upgrade the existing, TAMU to Atkins, 100-kV line.

So for the following evaluations, since we do need additional connections to rallies, the 100-kV upgrade inside BTU system are the same.

The only difference is the import line to RELLIS.

This is the project description for your reference.

Option two, instead of building new 345-kV line to RELLIS.
00:59:39
Option two is build a new one solid kV line from TNP one to Rellis.

Option 3 is new 345-kV double circular line from Sandor to RELLIS about 42 miles.

Option four or four is new 345-kV double circle line from Salem to RELLIS about, 45 miles.

All these import line is a straight line distance, with 20% adder.

So this table summarize the preliminary results of the reliability assessment.
01:00:23
Option one, option two, and option four, solved all the reliability violations under some particular case condition.

So there's no reliability violation under N-1, G-1-1, or X-1-1 contingency condition.

Options three, however, has, still have some, overload on the different contingency conditions.

So with that, option one, two, and four was selected as the shortlisted options for options for for the evaluation.

For these shortlisted, options, we performed planned maintenance outage evaluation, and, this table, summarize the study results.
01:01:07
For the maintenance evaluation, we used the 2024 RTP 20 thirty maintenance audit case, of course, with additional, updates.

So option one to four, resolve all the, violations on the maintenance audit condition.

Next steps, we will perform us continue evaluate the options and perform long term load serving capability assessment and the cost estimates and the feasibility assessment, as well as additional, evaluation analysis, which required, for the tier one project.

Tenantime timeline is, final recommendation, for the three of this year.

That concludes my presentation.
01:01:59
Any questions?

Well, it doesn't look like we have any questions in the room, and the queue is is empty as well.

So thank you very much, Ying, for that presentation.

Thanks.

We will have to go to the the next window for the other presentation.
01:02:21
So if you minimize this one, you should have the rest of the presentations there we go.

So thank you.

That does bring us up to the the next EIR status update for today.

That is the Aransas Pass to Roncon 69-kV line rebuild project.

And at this point, Travis from ERCOT will be giving that presentation.
01:02:45
So when whenever you're ready, the floor is yours.

Thank you, Robert.

Good morning.
Item 7 - EIR Status Update – Aransas Pass to Rincon 69-kV Line Rebuild Project
01:02:50
This is Travis Head from ERCOT.

Like he said, I am giving the update, for AEP.
01:02:54
Aransas Pass to Rincon 69-kV line rebuild project.

This will be the final update, for this project.

So as a recap, this is a spend it as a tier two project, submitted in November 2024, estimated to cost $33,000,000 and will require a CCN.

Estimated in service date is for June 2026 and is to address post contingency thermal overloads in the San Patricio County.

AEP presented a project overview and ERCOT project scope in the January 2025 RPG meeting, and ERCOT also provided a project update in the March RPG meeting, product still under ERCOT independent review.
01:03:33
This project area is above the Corpus Christi Bay, just north of it.

Kinda looking at the, once again, Gregory Randses Pass and Rincon area.

AEP identified a violation, thermal violation from Gregory to Aransas Pass as you can see here.

Doing the reliability assessment, for P1 to P7 of the base case, there was no violation seen for both for both voltage and thermal.

Doing the ERCOT plan maintenance out of evaluation, scaling loads moved to the off peak load conditions.
01:04:04
The base case did have one thermal overload, and the three options that we looked at did not have any.

So ERCOT saw the same violation that AEP did.

Once again, thermal violation of Gregory to Aransas Pass.

To address this, AEP submitted, option one, which is to rebuild the existing Aransas Pass to Gregory 69-kV transmission line, to 138-kV cable, operable at 69-kV with normal emergency ratings of two thirty nine MVA, approximately 8.5 miles.

It will also rebuild the Gregory to Rincon 69-kV transmission line, similar ratings and conditions for about point zero three miles along with relevant substation equipment.
01:04:46
As we can see here in this top right, you can kinda see that point zero three mile section from Rincon to Gregory just to bring the line to its full rating as well as the Gregory Duran's Pass portion.

Option two is to build a new Gregory to Gibbs 138-kV transmission line, normal emergency ratings of 239 MVA, approximately point three six miles, as well install a transformer for that line also.

This will also include the elements of option one, included in this option.

So we can see here the major difference is once again just from Gregory to Gibbs, such as small little segment there.

We also Option 3, which is to build a new Ingleside DuPont switch to Ingleside 138-kV double circuit transition line, ratings of 478 MVA, approximately 3.25 miles along with relevant substation equipment.
01:05:37
Here we can see that towards the bottom right.

There is currently a single transition line going there, and this will be rebuilding the towers to be double circuit.

Doing a live reliability assessment of these options, there was no violations for both thermal and voltage violations for N-1, G-1, plus N-1, and X-1 plus N-1.

TSP has provided a cost estimates and feasibility assessment.

All three options were feasible with option one costing about $34,000,000 and requiring one mile of CCN.
01:06:11
Option two, $52,000,000 and 1.36 miles.

And Option 3 is for $48,000,000 and 3.25 miles.

Doing a long term load serving capability of the of the area, option one and option two, option three, all about 40 megawatts for the incremental load serving capability, so pretty equal on that part.

Comparing the options, all three of the options meet the ERCOT and their reliability criteria.

They all improve the long term load serving capability, and they all are feasible, as we previously said, for the CCN mileage, the main one we're focusing on here is for option one, which is for one mile and the cost estimate of $34,000,000 as this is the ERCOT preferred option.
01:06:54
So the reason it's preferred option is because it addresses the product need in the area.

It's the least expensive option, requires least amount of CC and mileage, and, as we said, improves a long term load serving capability.

We also did a congestion analysis for this project using the 2024 RTP 2029 economic case.

The preferred option did not result in any new congestion within the study area.

Once again, this recommends option one, approximately $34,000,000 for cost, estimated in service date of June 2026, And the CCN filing will be required to rebuild the Aransas Pass to Gregory 69-kv transmission line segment.
01:07:32
Once again, the reiterate the option here is to rebuild the existing reg Aransas Pass to Gregory 69-kv transmission line to two thirty nine MVA ratings, approximate 8.5 miles, as well as a Gregory to Rincon, 69-kV transmission line for ratings of two thirty nine MVA, approximately point zero three miles, and relevant substation equipment.

Here we can see the map of the areas we saw before.

Only thing left for this project is to have the EIR EIR report posted in the MIS in May.

Any questions?

I don't see any questions in the room.
01:08:14
The queue still remains empty.

So thank you very much, Travis, for that presentation.

Thank you.

That leads us to the next EIR status update.

This is for the Oncor Roscoe area upgrades project.
01:08:31
At this time, Abhishek from ERCOT will be giving this presentation.

So whenever you are ready, the floor is yours.
Item 8 - EIR Status Update – Roscoe Area Upgrades
01:08:38
Good morning, everyone.

My name is, Abishek Penti, with ERCOT Planning, and I'll be providing a status update of, Oncor, Roscoe area, upgrades project.

Just to recap about the project, Oncor submitted the Roscoe area upgrades project for, RPG review in December of 2024.
01:09:01
This is a tier two project with an estimated cost around $83,000,000, and the project would require a CCN.

The estimated in service date, for the project is June 2028, and the main purpose of this project is to address the voltage violations as seen by Oncor.

Oncor presented the, project overview, and, corporate, presented the, project scope, during the February RPG meeting, and the project is currently under a continental.

Also, a recap about the study area map, and the project is, in the West weather zone in Nolan County.

And this is just a recap, with this, the recap of the study area map with the Permian Basin l 25 project included.
01:09:55
And the project need, as seen by Oncor.

Oncor was seeing some low voltages along the, the s Escota to, Oak Creek, Oak Creek to Nolan, and Nolan to, Saltwater Creek, path.

Here's a, map showing the proposed project by Oncor.

Oncor was, proposing the project, to upgrade, Eskota to Oak Creek, Oak Creek to Nolan and Nolan to Sweetwater, upgrading that, path from 69-kV to 138-kV, and, constructing a new, 138-kV line from Sweetwater Creek to Kilgore.

Kilgore is the new, load serving, substation, and Kilgore to, Oak Spring.
01:10:47
Yeah.

This is just a project description.

Just to recap about how the study, base case was built, 2024 RTP 2029, Summer peak case was used to build the, study base case.

Loads in the study area were updated to create the, study base case, and result levels were maintained consistent with 2024 RTP.

With regards to the transmission updates, appendix a has a list of all the transmission projects, added to the, study based case, and appendix b of this presentation has the list of all the RTP placeholder projects that were removed.
01:11:30
And with regards to the generation, appendix c of this presentation has the list of all the generators that were the generation projects that were added.

Here are the preliminary results of our reliability assessment performed on the study based case.

Archived identified, some voltage violations, thermal violations, and unsolved power flow violations, for N-1, G-1, N-1, and X-1, N-1, contingency scenarios.

And appendix d has the list of all the G-1 generators and the X-1 transformers testing.

Here's the study area map, with, with the violations as seen by ERCOT.
01:12:18
ERCOT was seeing some thermal violations, along the to Oak Creek and Oak Creek to, Nolan and Nolan to Sweet Water tap.

And also the seeing some, low voltages at Oak Creek, Nolan, and, Sweetwater Creek tap.

I've got, evaluated four different options.

Option one is, Oncor proposed option, which was, presented earlier.

So I won't go in details.
01:12:49
Option two is, to construct a new, 69-kV line from Sealed Water Creek to the new, Kelgor Station, and, to address the voltage violation, three blocks of 9.2 m war, switch ons were, are included in this option at Kilgore Station.

And this is just the, description, of the option.

Option 3 is kind of similar to, Oncor, option, but, instead of instead of, connecting the Sweetwater Creek to, Kilgore to, Oak Spring, Oak Spring already has, two, auto transformers, 345 to 138-kV.

So this option includes adding an additional third auto transformer at Oak Spring and the new, newly constructed, sweet Sweetwater Creek tap to Kilgo to Oak Spring will be connected to the newly, constructed or installed, third auto transformer 138-kV terminal.

And this is the SD, auction description.
01:14:04
Option four, is, is also kind of similar to Option 3 and, Oncor auction.

In this option, a new sub, substation, will be, constructed, which taps in between the Champion Crate to Oak Oak Spring, 345-kV line.

And, instead of instead of, connecting, the 138-kV k con connecting the 138-kV line from Sweetwater Creek to Kilgore to Oak Spring, Now it is connected to the new sub subscription.

And this is the option description.

Here are the preliminary results of the reliability assessment on all the, four different options evaluated.
01:14:52
Option 1, 3, and 4, did not show any thermal voltage, or unsolved power flow violations.

Option two has, as a thermal violation.

And Option 3 was deemed infeasible by Oncor.

So, option one and four are, shortlisted for further evaluation.

Here are the preliminary results of our planned maintenance outage evaluation on the shortlisted auctions.
01:15:23
For this evaluation, the load level in the West weather zone was scaled down to 82.5, percent of the summer peak load, And this is done to mimic the off peak, load condition.

N minus two contingencies were tested as a proxy for N-1, minus one, and, any applicable violating contingencies where, for the test and with system adjustments.

And all the transmission elements within the, Roscoe area were monitored, for this evaluation.

And, both the options did not show any voltage violations or terminal overloads or unsolved power flow violations.

Here's the, evaluation results for long term load serving capability on, both the options.
01:16:13
Both the options, show, an improved, long term load serving capability.

Next steps, Cord will provide, further evaluate the options and provide status update for the next RPG meeting.

And, condition analysis will be performed based on the recommended options just to make sure that, the, the, transmission updates do not, result in new connection in the study area.

Cost estimates and feasibility assessments will be requested, from Oncor.

Tentative timelines.
01:16:53
Again, status updates will be provided in the RPG meetings, and, the final recommendation will be provided, for the next, RPG meeting.

And, the report will be posted, tentatively, May.

That concludes my presentation.

Any questions?

Well, it doesn't look like we have any questions in the room for this project, and the the queue is still empty.
01:17:24
So thank you, Abhishek, for that presentation.

One announcement I didn't, make in the beginning.

For those in the room, you will find these menus laying around.

We are having another food truck here.

So you can use the QR code to to place your orders.
01:17:40
They will be available from eleven to one today.

So, hopefully, we'll have some sort of break between RPG and PLWG, and we can, you know, schedule food accordingly and, not go the whole day without eating.

So at this point, moving along in the the RPG, agenda, we now have the Oncor project overview for the Southern DFW load interconnection and general grid strengthening project.

So at this time, I'll turn it over to Zara.

And whenever you are ready, the floor is yours.
01:18:20
Thank you, Robert.
Item 9 - Southern DFW Load Interconnection and General Grid Strengthening Project Overview
01:18:22
Hi, everyone.

I'm Zahra Jianpanah, from Oncor transmission planning.

Today, I'm going to give you a presentation about, the RPG submittal, that ONCOR submitted for review, which is Southern DFW load interconnection and general grid strengthening part.

So, starting from project overview, this is a tier one project, spanning, all TFW as you can see in the map from Dallas, Ellis, Navarro, Parker, Freestone, Leon, Henderson, Rockwall, and Colin Counts.
01:18:59
As part of this project development, there will be a CCN filing requirements.

The need for this project is driven by, the total of new 4,064 megawatts of load that is mainly in Dallas and Ellis Counties, that either executed an interconnection agreement between Oncor and, the customer or they have demonstrated well defined forward movements in meeting the condition for our load interconnection process.

This project will resolve, all identified thermal and voltage violations.

It provides additional 345-kV sources for the area, enhances the load serving capability by upgrading the existing transmission infrastructure and enhances overall system reliability.

As a result of this project, there will be four new switching stations, across, metroplex.
01:20:00
Two of them are going to be 345 and 138-kV switch.

With two other transformer at each station, the remaining two will be only 345-kV switch.

We will rebuild, big brown 345-kV switching station with the new name of Pinoc.

There will be four new 138-kV, lines, which are the parts that, you know, will require CCN that I will touch point, you know, later on throughout my presentation.

There will be a total of 243 circuit miles upgrades in which 169.8 will be 345-kV and 73.1 will be 138-kV.
01:20:42
There will be nine reactive devices where we have three STATCOMs, mainly in, Dallas County, and the remaining will be a combination of 345 and 138-kV capacity turbines.

The estimated cost for this project is 1,219,000,000.000.

So, this table leads all the upgrades that I mentioned in the previous slides.

I'm not going through, each of them.

However, I'm going through the map to show you where the upgrades are are located.
01:21:15
As you can see, all upgrades are, you know, all across DFW.

The orange line represents the, lines that are going to be rebuilt.

The purple, shows the from and to existing stations.

You see, the, yellow circles here, which points to the new 345/138-kV switches that we are going to have.

The green circles which have the 345-kV switch and, the little red triangles which points to the locations where the three STATCOMs are go going to be located.
01:21:55
Moving on to next slide, this is, a table that lists all the projects that supports this RPG submittal, that the need for them were also identified during 24 RTP studies.

All of them are mentioned in the report.

Again, I'm not going to through them line by line.

So let's talk about load assumptions, where they are, and, how much they are.

This table shows the load distribution, across, mainly, as you can see, all the loads are concentrated in Dallas County.
01:22:31
It shows the station name, the associated megawatts, and the cable level along with the bus number in our modeling cases where you can find in RTP cases and in future SSWG cases.

So, to run our studies, we, picked, 24 SSWG update one cases.

To improve the case before we perform the studies, we, grabbed the case, remodeled the load, and we update the updated the case using the GIS reports from October and February.

And we added all the generators that had met 6.9 criteria.

With adding all generators, we were still, having 450 megawatts of deficit, which we proportionally scaled the load in coast and south weather zone in ERCOT, and that gave us a good case that was ready to be, perform to be done from our studies.
01:23:33
Table, in this slide shows, how each unit was dispatched at what level and how many of them were modeled in the cases.

So now that we have modeled everything, our generation, our load, time for violations, we have a lot of, thermal and voltage violations.

There were a total of 169.8 circuit mites of 345-kV line that, resulted in thermal violation.

Same for 73.1 of 138-kV lines.

There were three other transformers.
01:24:08
I believe one of them was 138-kV 69, and their, remaining two were 345, 138-kV transformers.

So after adding the total of 4,064 megawatts of load in the case, we were seeing, some, voltage violations in base case, which was violating their criteria, which was below point nine five.

And for that, we proposed, you know, all the reactive devices that I mentioned in the second slide.

To mitigate all those projects, Oncor recommends, the establishment of 345-kV switch along with two 345-kV auto transformers.

We will recommend the establishment of iron wood, 345-kV switch.
01:25:03
I'm not gonna go line by line.

I feel like there are too many details.

Feel free to ask any questions if you have later on.

However, on the second slide, I will talk about the STATCOMs where they're going to be located in Alba Road, Wilmer, and, Steynback as I showed, in the map earlier.

These are exactly, you know, shows the number of stages and the size of capacity banks along DFW.
01:25:34
For the existing 345-kV terminal equipments, we ensured if they're existing, they at least meet, 3,000 amp or seventeen ninety two MVA.

If they are new and if the session is capable, they are going to be 5,000 amp.

Otherwise, they will remain at 3,200 amp.

For the 138-kV terminal equipment, we ensured that the terminal equipment are at least 3,200 amp.

The, all these proposed projects are, anticipated for an in service date between 2026 and 2028.
01:26:08
So as I mentioned earlier, there will be two, 345, one 30 kV switches that not only change the topology, of course, if they are gonna impact the flow as we are, you know, installing, new, 345-kV, other transformers.

In this slide and the following slide, I'm just gonna walk you through the configuration of the two new switching stations that Oncor is proposing.

The first one is going to be, Green Road, as you can see here.

And right side of it, we have Alba Road.

For those who might be familiar with the previous RPG that Oncor submitted, we have Wilmer here.
01:26:45
And as opposed to Wilmer, it's gonna be kinda Northwest of Wilmer.

The Green Road switch will be, terminating to Watermill to Sargent Road and West Liberty 345-kV line.

On the 130-kV side, we have Watermill to Cedar Crest and Sargent Road, and we will install two autos along with the cap banks and statcom here.

For the iron boot switch, we are establishing a new 345-kV switch, right north of Venus the existing Venus switch.

We are installing two other transformer, and this is the project where CCN is required.
01:27:26
To connect the new 130-kV switch to the nearby transmission lines, we will not we will need to install four 130-kV lines each two miles circuit to connect a new, 130-kV switch.

Again, this station will have two other transformers with two 130-kV cap banks, and it will be North of Venus.

That brings my presentation to end.

I'm happy to answer any questions if you guys have any.

Well, it looks like we are breaking the streak.
01:27:59
We do have a question in the queue.

This question's from Jeff.

Hi.

Jeff Bilal with, ERCOT operations.

Zara, thanks for the, presentation.
01:28:17
So my, question actually, I have a couple questions.

So first, it so with, it it seems like there's a lot of line rebuild all in the same area, all in a short amount of time.

Have y'all done an analysis an analysis to see if it's feasible to take all of those line outages in in the time frame that you're looking along with?

I I know that there are other projects that have also are that have previously gone through RPG review that are also looking at line rebuilds in the same area in the same time period.

Have have you all done an analysis to see if that's feasible?
01:28:52
So for those that either anticipating an outage conflict, yes, we did.

But, no.

The outage the overall outage scenario has not been studied for these projects, and we will be performing them, as we move forward.

Okay.

And and, I would just wanna add one more comment.
01:29:09
So the construction will happen between '26 and '28.

So it's not that all of the lines that are being proposed will be taken at the same time.

This will happen over many construction seasons.

Yeah.

Okay.
01:29:19
Understood.

Thanks.

And and then, you so your 80 megabar cap bang, so have you done an analysis to see if it's, in, like, an off peak?

Can can you switch those in and not cause voltage issues switching them in and out?

The the does there and and the reason I'm asking is I think historically, we've seen that there have been challenges, maybe not at peak, but at other times switching in large capacitor banks in and out.
01:29:49
Yes, Jeff.

I believe we performed the peak and off peak case.

So, yes, all the, mitigations that are proposed throughout this RPG were to set through off peak as well.

And we also have STATCOMs that can sort of go in the other side to if there are voltage fluctuations, STATCOMs will sort of tune them out.

Okay.
01:30:09
So in in even in a because we're doing capacitors along with, static on the same region.

So if we expect any deviation outside of that, 3% or so will help hopefully, stat comes will help.

Okay.

And and then I think my last question, do do you know off the top of your head so so the it seems like you're adding a lot of capacitors, a lot of STATCOMs, which your total megavar, for active compensation you're adding in and and that compared to the total megavar of the load, the new load that's in that area?

This table shows how much megavar we are adding, you know, to the case.
01:30:53
It's $25.00 2 MVAR.

And sorry, Jeff.

I'm not sure if I understood your second part of the question.

Yeah.

So the the second part is what what's the total megabar consumption of the new load that is in that area?
01:31:09
So it's about 4,000 megawatts.

We are assuming 95% power factor, so around 1,515.

Yeah.

Mhmm.

Okay.
01:31:18
So so a lot of the reactive devices are sort of compensating for that power factor being at 95% and then additional amount for the line losses and other things.

Okay.

And and are are we, get getting to or are we overcompensating because we have high reactive losses?

So so are we are we getting into that?

So so it's your reactive losses are I I I squared x.
01:31:44
And are are you getting into that steep part of your of that that curve?

Yeah.

No.

That's a good point.

So when we started doing this study, I think that was one of the things we looked at, which is how much load can we support without needing to build new transmission line.
01:32:01
And this is where we sort of stop that this is how much we can serve in this region.

And just to your point, if you go if you try to serve any more load, then you get into that I squared x issue, and you would just have tremendous voltage issues.

So this is where we think is a sweet spot of let's rebuild the lines.

We can without building new transmission.

But you are you are correct.
01:32:23
Meaning, that's the next step Get the edge.

In this area to continue serving more load.

That's where we're gonna go.

Got it.

Okay.
01:32:30
Cool.

Thank you.

All of these projects, Zara mentioned on one of the slides, they're also in the RTP, so they go well with even when we add new transmission lines, it doesn't mean that the need for these lines will go away.

So these projects will still be needed.

Okay.
01:32:44
Thank you.

Okay.

We have one more question in the queue from John.

John, we can't hear you, but his question is in the chat.

Will additional row be needed for the 345-kV line upgrade between Watermill and Steinbeck?
01:33:12
Is is there a more detailed map of the Watermill area upgrades?

Yeah.

The, the answer to the first question is no.

As part of the detailed map for Water Mill area, I think this is as detailed as, you know, we can show when we have it in the report as well where where it includes all the new searching sessions along with any new line rebuild that we are proposing in the nearby area.

Common from Brazos agrees with the additional capacity near Venus.
01:33:59
Thank you for that comment.

I believe that is all the oh, we have a question in the room.

Apologies.

Thanks, Robert.

This is Yang from.
01:34:13
I got a question regarding the loads.

So, if I'm not mistaken, so this whole project need to serve the load in the D F, DFW area.

I want some clarification on those loads.

Are they the forecasting residential industrial load, or do they include all the large loads, Oncor received recently?

If so, are those loads sent IA already, or some of them, endorsed by office letter?
01:34:47
Could you provide some clarification on that?

Yes.

Thanks.

So all these loads are as part of, the loads, as you said, as Oncor received, and they were shared with ERCOT or as part of other loads.

As I mentioned in the previous slide, all of them are either have, the signed agreement or they have shown promising, you know, process that, aligns with our data interconnection process.
01:35:16
Thanks.

Then I have a follow-up question regarding this.

So as far as I know, those large loads, the majority of them are, data center or cryptos.

Mhmm.

So they they want to be in service, like, in the next two years.
01:35:31
Right?

So but with this upgrades, it looks like it's gonna take at least three or four years due to the supply chain constraints.

So how does Oncor handle this kind of situation?

So depending on the customer request and the load ramp that they are proposing, we are gonna sequence and prioritize the projects to make sure we meet the customer in service dates along with the load ramp that they are proposing.

K.
01:36:03
So now oh, we got another comment in the room.

Yeah.

So I if you can go to the slide five, please, on the so I'm I'm looking at the loads here.

It looks like the largest load there is five 750 megawatts connecting to a 138-kV.

Is is that correct?
01:36:25
That's what I'm reading here.

So my my question is is are there any Oncor standards on how much load you connect to a 138-kV?

Or Oh, probably just to have a clarification, so the seven fifty six megawatts of load that you are seeing is the one hundred 138-kV, which had, you know, another RPG submittal.

We don't have a rule on, you know, like, what is the maximum megawatts that we are connecting to 138-kV to 345.

I believe depending on the area and whether our serving capabilities, that answer, you know, can vary.
01:37:03
And, of course, compared to the location when the customer, you know, is requesting the load and within the timeline.

But but this is connecting to the 138-kV.

All of them?

Okay.

Yes.
01:37:20
So So Yeah.

Gotcha.

Yeah.

Probably, this is Justin.

I will that's a good question.
01:37:25
And and Zara is absolutely right.

We don't have a a firm rule.

But, you know, over the past over the past couple of years, with the immersion of, you know, mega large loads or hyperscale hyperscale large loads, it it definitely begs the question.

And and we've looked into developing guidelines of, like like Zara mentioned, where are the places that make most sense to consume load at the 138-kV level?

You know, you're gonna be trading sometimes speed for speed for equipment, especially autos.
01:37:52
Your autos are gonna be the limiting element, but, you know, like, moving forward now, we're getting smarter.

We're looking at, we're looking at systems in a different way.

And, also, it's a function of of what the customer's, preferred voltage are.

Some are able to, connect at the 345, and so we are allowing that.

And that that pose new, questions for us to ask ourselves and and develop new guidelines.
01:38:14
But, I would say the majority of, the majority of our our large interconnections, that that we're that we're looking at moving forward, if they if they can, especially that triple high triple digit megawatts.

It it if it makes it usually makes most sense to connect them with the 345, so that we avoid, some of the other upgrades that may be required at the at the 138-kV level.

Alright.

Thank you for that conversation.

No more questions in the queue, and one last look around the room.
01:38:49
I think I think we're good here.

So thank you very much, sir, for that project overview.

That does lead us into the ERCOT, scope presentation for this.

So I will yet again turn the floor back over to Tanzilla from ERCOT, and she will walk through the scope project for this.

So the floor is yours, Tanzila.
01:39:12
Thank you again, Robert.

Good morning, everybody.

Third time is the term, I guess.
Item 10 - ERCOT Independent Review Scope: Southern DFW Load Interconnection and General Grid Strengthening Project
01:39:20
Here, this is Tanzila here to give you guys the scope for the, ERCOT ind independent review for the, Oncor, Southern, DFW load integration and general grid strengthening project.

So, Zara gave a very good introduction, so I will skip through all of these and go right to the scope.
01:39:45
So, for, study assumptions base case, the region is North Central East weather zone focusing on the transmission elements in the Collin, Dallas, Ellis, Firestone, Henderson, Leon, Navarro, Parker, Rockwell, and Tarrant Counties.

We'll be using final 2024 RTP RTP 2029 summer peak load case, that was posted in MIS, in December of last year, to construct our summer peak load case.

And the link is provided here for the MIS.

For transmission based on the February 2025, transmission, TIPET project, sorry, report published in ERCOT website, projects within the study date on or before December 2028 within the study area will be, added into the study based case that are not already in the, case.

So some of the projects basically, listed in appendix a right now is all the latest, recently approved RPG projects, that were identified in the study area are listed in appendix a one will be added to the project, the study base case.
01:41:04
Transmission project, as Zara has mentioned in her, report, that were identified in the, 2024 RTP as a placeholder projects, will be removed and, list of this project is also, available in the appendix, a two.

New generation that meets, at the, planning guide section 6.91 condition with the commercial in service date of, before December 2028 in the study area, will be added, anything that has not already been modeled in the, RTP cases already.

And this is based on the 2025, March GIS report.

All generations will be dispatched consistent with the 2024 RTP, recently sorry.

Recently, retired indefinitely multiple units will also be reviewed and turned on, or opened or turned off, basically, if not already reflected in the 2024 RTP final case.
01:42:13
Load in the study area, will be scaled down to reflect the project submittal, and load outside study study area may be scaled to maintain the reserve consistent with the 2024 RTP.

Standard contingencies and criteria will be followed, based on the NERC, TPL zero zero one dash 5.1 and ERCOT planning guide.

So I wanna mention that there are various, G-1s, will be for generation outages, we'll be looking at Dansby plant, diamonds, Shamrock, Battle Guard, combined cycled, train, Forney CC train, and also, Mountain Creek generation will be tested.

For transformer, 345 to 138-kV transformers only, DeSoto switch, Green Road, Monticello, Seagoville, Trinidad, Venus Camp, Ranch, and West Levy, three forty, transformer will be tested with the, X-1.

So standard study procedure is, we'll first, run a reliability analysis to identify project need to, in the study based case.
01:43:38
Once we find the, project, violations, we will go into evaluating project options, to satisfy the NERC and ERCOT reliability requirements.

We'll then run a planned maintenance outage, evaluation and long term load serving capability assessment, and we will request cost estimate and feasibility assessment from, TSPs in the area.

Once we select a, preferred option, we will test we'll run additional analysis such as generation addition and load scaling sensitivity analysis, SSR assessment, and congestion analysis on the preferred option.

Next step is, in tentative timeline.

Status update will be provided at the future RPG meetings, and final recommendation is, scheduled tentatively for quarter three of 2025.
01:44:33
That concludes my presentation, and thank you for your time and open up the floor for question.

It doesn't look like there's any questions in the room for the the project scope.

No questions in the queue, so thank you again, for that that presentation.

At this time, I do need to transfer the presenter over to, my laptop so that, Beck Hamilton, project overview could be made.

So if you just wait one second, we'll get that situated.
01:45:55
Hi, Robert.

This is Brian Heathersay from Browser Electric.

Hey, Brian.

Yeah.

Just, one one second.
01:46:02
We're trying to get it up up on the screen as well in the room here.

So it looks like we have everybody, on on the Webex, can see the presentation, but not in the room.

So give us give us one minute.

Okay.

It looks like we have it all situated now in the room.
01:47:14
So whenever you are ready, please feel free to proceed.
Item 11 - Hamilton County Conversion Project Overview
01:47:19
Alright.

So the Hamilton County conversion project is not just in Hamilton County.

It actually stretches from Comanche County through Hamilton County, Cordele County, and goes into Bell County.

Brazos Electric has a very extensively long, 69-kV transmission line across that corridor.
01:47:43
And on about page six, you can see a map of it, which can kind of give a little bit more of an overview.

Yeah.

Page five has a map showing both, kind of all the TSP facilities in the area there.

I can explain it from that point.

On the north end of the site, a very thing you see, a station called Hasee, that has a 138-kv source, connected to it.
01:48:16
And process intends to start our voltage conversion pro project there at the Hassie Substation.

We intend to move south to the Gusteen to Indian Gap, transmission line, And that radial transmission line portion requires CCN application due to the fact that our easements do not cover the full capability of, rebuild.

And we are in the process of acquiring those additional easements as we speak.

Brazos intends to do a full voltage conversion on this due to a generic transmission constraint.

On the center of the map, you see a dot that says Grizzly Ridge.
01:49:01
There is a generator that is currently limited to about 70 megawatts of its 10 megawatt capability at that location.

And between that location and Gustine, Brazos has an SGAA signed.

It now meets planning guide 6.9 with another 100 megawatt solar farm.

There are multiple other generation interconnection requests.

However, only these two are official projects to interconnect into the grid at this time.
01:49:35
There have been also multiple large load inquiries and not even necessarily large load inquiries, but sometimes in the tune of four or five megawatt, requests throughout this whole section of transmission that Brazos has informed them it's going to be a number of years for a having the full capability to give them the full service in order to keep the grid iN-1 secure.

And this has frankly scared off a lot of requesting entities who otherwise would have connected into the grid.

Brazos has now just just with regular subdivision and load growth, had enough, load that it's creating potential voltage violations in in the future study cases.

And of that, I'm using Brazos Electric's voltage criteria where Brazos Electric stations are required to have a minimum of 0.92 per unit voltage capability.

And so the overall project scope is to perform a full voltage conversion from Hassy all the way south until you get to what's currently on the map as Pogue.
01:50:55
We will be replacing Pogue as part of the, Oncor temporary improvement project with a new station called Crusader.

And that's the proposed project from Brazos Electric.

Thank you for that quick quick overview.

Just FYI to the group, what's on the screen right now is the submitted project description.

So it is located in the project folder on the ERCOT MIS site, but it will not be posted with the meeting materials.
01:51:32
We do have the scope following this that we'll go over, just just to address any any comments.

But it looks like there's no no additional comments in the room, and it does look like the queue is empty.

So thank you very much, for that that project overview.

We will transition back to the podium.

So it'll take us a a minute to get that situated.
01:51:57
But thank you very much.

Okay.

Hello.
Item 12 - ERCOT Independent Review Scope: Hamilton County Conversion Project
01:52:58
My name is Sarah Ganasekra.

As Robert, said, I'll be presenting the scope for the Beck Hamilton County conversion project.
01:53:09
So as Brian was mentioning earlier, Beck submitted this project to RPG review in February of this year.

It's a tier two project estimated to cost 90,000,000 that will require CCN, and That's estimated in service date will be in fall of 20 thirty.

And it's being recommended as a GTC exit strategy for the Hamilton GTC.

To review, this is a study area map.

So like Brian was mentioning, we're looking at the 69-kV pathway from Hassy, up here down to Pogue.
01:53:48
So the proposed project by Beck essentially is converting all of that 69-kV pathway up to 138-kV.

So walking through it, we'll be converting the existing Hasse to Gustine to operate as a 138-kV with normal and emergency of 418 MVA, converting Gustine to energy to energy switch, Waring, Indian Gap, Pottsville, Hamilton, Gatesville, Fort Gates Switch, Fort Gates, Gatesville TDC Switch, Leon Junction, and Poage.

69-kV substations all up to 138-kV operation.

They'll be rebuilding the existing Gustene to Energy switch as a double circuit, with emergency normal and emergency ratings of five 24 MVA, rebuilding the energy switch to energy as a 138-kV double circuit with similar normal and emergency ratings of five 24 MVA, and then rebuilding energy switch to Indian gap also as a double circuit 138-kV with normal and emergency of five 24 MVA.

They'll be converting the existing Guste to Pottsville, Pottsville to Hamilton, Hamilton to Pancake, Pancake to Gatesville, and Gatesville to Fort Gates.
01:55:07
69-kV transmission lines to 138-kV transmission lines operating at normal and emergency ratings of 138-kV MVA.

And they'll also be installing two 138-kV 69-kV transformers with pancake.

They'll be rebuilding the Fort Gates switch to Fort Gates as a 138-kV double circuit, with emergency and normal ratings of five 24 MVA.

They'll be converting the Fort Gates to Santa Fe switch to 138-kV line with normal and emergency ratings of 138-kV MVA, installing two 138-kV to 69-kV auto transformers at Santa Fe, then rebuilding the Santa Fe to Gates Ville as a 138-kV double circuit with normal emergency ratings of five 24.

I'll be moving the existing Gates Ville TDC switch to the Gates Ville Army tie line to connect to Santa Fe.
01:56:06
They'll be converting the Santa Fe switch to Leon Junction and the Leon Junction to Polk, 69-kV transmission lines to operate at 138-kV with normal emergency ratings of 138-kV MVA, and then retiring the existing auto transformers at Polk.

So to see that graphically, rebuilding this whole section out into 138-kV, they'll be double circuiting, these four substations and then putting a double circuit between, Santa Fe and four gates.

And so our looking at our study assumptions, for the base case for this project, we'll be looking at North Central weather zone focusing on transmission on Comanche, Hamilton, Coryell, and Bell Counties.

We'll be using the final 2024 RTP 2030 summer peak case, and that can be found on the MIS.

The transmission in this project will be updated with the February 2025 tippet project, and all the projects added to this base case can be seen in appendix a of this presentation.
01:57:15
The transmission projects that were added to the case, to be backed out for the 2024 RTP can be seen in appendix b.

Any new generation that met's planning guide 6.91, before the fall 20 thirty ISD, was added to the case based on the February 2025 GIS report, and that can be seen in appendix c of this presentation.

All the generation will be dispatched consistent with the 2024 RTP methodology, and all retired or indefinitely mothballed units will be reviewed and opened, if not already reflected in the 24 RTP.

Loads in the study area will be, maintained consistent with the 2024 RTP case, and load outside of the North Central weather zones might be adjusted to maintain that reserve.

Also, be conducting an economic study for this project.
01:58:12
And for that, the 2024 RTP economic study based case for the 2029 will be used.

And all the study assumptions will be maintained, according to the presentations linked below.

For our contingency and criteria information, that will be remaining consistent with our other studies.

We have a list of our G-1, X-1 units below.

I'm looking at Grizzly Ridge Solar, Panda, Temple, and Logan's Gap Wind for G-1s, the transformer at Hassy, Comanche switch, and Temple switch for X-1s.
01:58:54
Moving forward to our study procedure, we'll be conducting our need analysis, both our reliability and our economic analysis for this project.

Our project evaluation will include project alternatives, that will be tested.

We'll also perform a planned maintenance outage and long term load serving capability assessment and a congestion analysis for our preferred option.

Our tentative timeline for this project is we'll be continuing to provide status updates at future RPG meetings, and our final recommendation for this project will come in quarter two this year.

And with that, thank you so much, and I'll take any questions.
01:59:38
Well, thank you, Sarah.

There is a a question, looks like for Brian.

The recent generation that was added for Brazos is after the February planning guide 6.9?

Oh, yes.

There is an additional generator, that Brian had mentioned that will be interconnecting into this project area, and that will be part of, I believe, the April GIS report that'll be posted, next month in May.
02:00:14
So that will also be added.

Yes.

That will be updated.

Thank you.

We've got a a question from Ross.
02:00:30
Hi.

Good morning, everyone.

I was just curious.

Will our copy studying the GTC exit strategy option, as part of the internal review?

That is something that we're looking at studying as a project alternative.
02:00:44
Yes.

Okay.

Thank you.

Mhmm.

Yeah.
02:00:51
It looks like that's all the questions in the room.

I don't think there's any more questions in the queue.

So thank you very much, Sarah, for that presentation.

That does wrap up the the RPG EIRs, and and scopes.

So now we'll turn it over, to Pria in the economics group.
02:01:11
She'll be presenting the update on financial assumptions for ERCOT economic planning criteria.

So whenever you're ready, Priya, the floor is yours.

Thank you, Robert.

Good morning, RPG.
Item 13 - Update on Financial Assumptions for ERCOT Economic Planning Criteria
02:01:25
This is Priya Ramasubbu with ERCOT Transmission Planning.
02:01:28
And, I'm here to provide an update on the financial assumptions for ERCOT economic planning criteria.

So as a high level background, for economic projects, the PUCT substantive rules require that ERCOT perform two tests, namely the congestion cost savings test and a production cost savings test.

And this is to quantify the potential economic benefits that adding a transmission project could bring to the ERCOT grid.

To justify a transmission project as economically viable, it has to pass either one of these two tests.

The congestion cost savings test analyzes whether the ERCOT wide total, consumer energy cost savings attributed to that project can be, greater than or equal to the average of the first three years annual revenue requirement.
02:02:28
And then the production cost savings test analyzes whether the the ERCOT wide annual production cost savings attributable to that particular project, is greater than or equal to the first year annual revenue requirement.

The nodal protocol sections, three point eleven point two, subsections five and six, require that these financial assumptions that are used to determine the first year annual revenue requirement and the average of the first three years annual revenue requirement be reviewed annually.

The revenue requirement calculation for any TSP for a rate based transmission asset typically includes a few items.

And these are the return on rate base, which is further defined by the cost of equity and debt and also the debt to equity ratio.

And there's accumulated depreciation, O and M both fixed and variable, and taxes.
02:03:28
Now majority of this information is available for us through the TDSB PUCT rate filings, and the link to the PUCT website on this, slide can be accessed for can be used to access all of that information.

The current methodology that we use is the same as what we had for 2024.

So, essentially, we determine the first, the first year annual revenue requirement as well as the average of the first three years annual revenue requirement for each TSP using a generic transmission project with an assumed generic capital cost.

And then we utilize the schedule based methodology to, update the financial assumptions.

So, essentially, what the methodology does is it takes into consideration the most updated PUCT filings, and then it calculates the weighted average annual revenue requirement based on the rate base.
02:04:33
And then the the presentation that's linked on this slide has a lot more details and also has an example if you're interested in that.

So what we have here is a side by side comparison of the first year revenue requirement for individual TSPs over the past few years.

And this is unweighted at this point.

So if you look at the these, the data that's presented, these filings do not change very often.

So they don't get updated very often.
02:05:06
They don't change much.

And then if you look at this slide, it shows a side by side comparison of the first year as well as the average of the first three years annual revenue requirement for those mentioned specific TSPs in ERCOT footprint.

And this is again unweighted.

It also shows the rate base for each of those TSPs as they have filed it with the PUCT.

Using the schedule based methodology, the weighted first year annual revenue requirement was determined to be 13%, and the weighted average first three years' annual revenue requirement was determined to be 12.7% this year.
02:05:53
In '24, these numbers were 12.912.6%, respectively.

So effective February of 2025, first year annual revenue requirement of 13% and the average of the first three years annual revenue requirement of 12.7% will be used for economic project evaluations.

Thank you for your time, and I can take any questions if you have any.

Hi, Priya.

I have a question.
02:06:28
This is Andres with Cypress Creek.

Hi, Andres.

So just out of curiosity, has any project met the the economic criteria, like the the con the new congestion cost savings test?

So, we implemented that test for the first time in last year's RTP economic analysis.

And, the report is available on the MIS website if you have if you can access that, Andres.
02:07:01
So it does, list all of the tests and how the projects that we tested fare using those two.

And for the congestion cost savings test, I off the top of my head, I do not recall if there were any that passed last year.

But for this year, we have yet to perform the like, we haven't, started testing or, you know, haven't started performing those analyses yet.

But the report is available on the MIS website.

Okay.
02:07:29
Thank you.

Sure.

Doesn't look like there's any other questions in the queue, and don't see oh, we got one question in the room.

The the generic project that was that applied to all TSPs, the same generic project?

And how was how was that devised?
02:07:52
Correct.

So what we did was essentially to set a baseline to establish something that, can be used to calculate, the revenue requirement for each TSP.

So instead of using the total revenue requirement and the total consolidated rate base for all DSPs as one, we decided to calculate the revenue requirement for individual DSPs using the same projects.

So that would establish a baseline and then to weight those using the contribution of each, TSP towards the total grade base.

And that was averaged out to come up with the the weighted, to come up with the average.
02:08:29
So this was just a fictional project Correct.

That you just that you made up.

Okay.

K.

Thanks.
02:08:41
Okay.

So now it looks like there's no more questions in in the room.

Queue is empty.

So thank you very much, Priya, for that presentation.

Thank you.
02:08:51
I am shocked of how closely we are following the proposed timeline for the agenda.

So we are onto our last presentation for today.
Item 14 - Long-Term Load Forecast
02:09:02
This is the, long term load forecast.

So I believe, Katie and Sam, from ERCOT will be presenting this to the group.

So whenever you are ready, the floor is yours.
02:09:17
Hi, everyone.

I'm Kate Lam, and I'm gonna go over the first part of our presentation today.

And then about two thirds of the way through, Sam's gonna jump in and talk about the overall outlook of the long term load forecast on the ERCOT system.

So to start, I'm gonna go over the forecast components.

If you have seen the waterfall approach that we've used in the past, not much has changed to that.
02:09:39
So first, I'll go over how the base economic forecast is derived, what our economic growth outlook, mainly our premise forecast looks like, how our electric vehicle forecast, looks this year, and then also our crypto and rooftop solar forecast.

I'll briefly touch what our waterfall forecast looks like and how it should be read on our website.

I'm also gonna touch on how our annual energy and summer peak relationship has changed.

And then to end my part of the presentation, I'm gonna go over our winter weather scenarios, Yuri and Elliot.

So to start, I'll go over how our base economic forecast is created.
02:10:19
Our model is made up of calendar weather economic variables, which are our main drivers, and then we have our native load, which is reconstituted for PV as well as for winter storm Yuri.

So we actually did load research and it to be able to add winter storm Yuri outages back.

So, essentially, we have simulated what winter storm Yuri would look like had we not had outages so that when we ran our forecast, we were able to see what Yuri would have looked like.

So we create 15 weather year forecasts for each weather zone, and then they're ranked by year and month.

And then we average across the the 15 weather years to get our fifty fifty forecast, which essentially is a 50 fiftieth percentile forecast.
02:11:06
And then we also map to a mid weather year, which would be 02/2008, which just means it was a typical weather year in comparison to the other years that were used in the 15.

So going over our base economic outlook, the graph that y'all see is our premise forecast.

So, yes, you can see there's just a linear trend for our residential and business premises.

Something to note is that the premise forecast, they do not include, large loads like we would see in our RFI.

It's just base business and residential growth.
02:11:39
And as you can see, between 2026 and 2031, that base growth is pretty consistent, but it's not growing by a ton.

It's just a slight linear trend.

So now I'm gonna go over our EV forecast.

Our EV outlook is growing slightly slower than we anticipated last year due to lack of EV sales.

You can see that in 2031, our max charging is 2,642 megawatts.
02:12:07
We also have done a little bit more sophisticated studies and realized that different zones have different charging patterns.

So that's something that you'll see when you look at our, our forecast on the website.

We have it broken down by weather zone.

And as you can also see, our graph for 2025 starts out a little bit higher, and then it's when it starts to grow slower than our forecast from last year.

That's just because our input for that year started out higher than last year.
02:12:38
So going over our LFL or crypto forecast, this year, we do have a new large flexible load daily profile.

So last year, you would have seen a dip down to 15% during net load peak or over our peak hours.

But now we have a more sophisticated profile that we created using observed behavior from the February.

So we drop down to about 50% during our peak hours.

And then during net load peak, we get all the way down to 15%, and then we slowly come back up.
02:13:10
This is subject to change depending on what our observed behavior is this summer.

So that is something to watch out for as it is going to keep evolving as our grid keeps change.

Okay.

So now I'll go over our rooftop solar forecast.

Oh.
02:13:28
Let's go ahead and take that question.

Yep.

Yeah.

There's there's a question in the queue on the LFL profile from John.

Yes.
02:13:38
Hi.

Thank you.

Can you hear me?

Yes.

Okay.
02:13:41
I just wanted to understand.

So this this profile, is it kind of like an aggregated, like, average behavior that you're seeing of across the summer, or is it is it just kind of the peak like a gross load peak day?

Because there was there was a similar slide shown in, like, the October board meeting that and just trying to understand, is this what you're expecting, like, on a four CP day, or is this just a pattern that you expect to see on a daily basis?

So this is a pattern that we observed not just on a four CP day, but on average for summer of 2024.

Sam, did you wanna add something to that?
02:14:19
Nope.

Do I have any questions?

Yeah.

That's the answer is the direct question.

They're kinda the part that's a little bit of a head scratcher is with the addition of solar.
02:14:30
You it's a little surprising that you're seeing some of the interruptions as early as you are.

You know, in '23, I think that made sense and but '24, we're kinda trying to understand why that might still be happening.

So but appreciate the insight.

Thank you.

No problem.
02:14:46
Quick question on that.

First, Oncor.

Do you apply that profile only to crypto loads?

To oh, did can you repeat that?

Sorry.
02:14:56
I didn't Do you apply that only to crypto mining loads, the profile?

Yes.

Okay.

Got it.

Thank you.
02:15:02
Oh, something to note.

If you do look at anything that we got as a proposed new load didn't and it if it was categorized as crypto, we did not use the pattern.

This is only for crypto that we have observed behavior for.

So anything new does not have this production pattern.

Got it.
02:15:20
Thank you.

Okay.

So going over our rooftop solar forecast, we created a usage per customer model, for residential and business.

This was created using weather and calendar variables, and it was driven by the solar irradiance variable because it captured solar generation really well.

It was mapped to 2018.
02:15:44
As you can see, the PV growth has slowed since last year.

I believe last year, we were at one in seven homes.

But the year before that, it was about one in eight or one in nine, and I think we're still on track with about one in seven.

It hasn't changed much.

So going over our waterfall methodology, this is a really good representation of how our forecast is created and what it looks like online, but in graphical form.
02:16:10
So the first bar on the left would would just contain our base economic forecast.

So that would be what is driven, by our premise and existing load information.

And we each subsequent bar would indicate a new forecast being added.

So the second bar would be base plus EV, and the third would be base plus EV, and then subtract PV and so forth all the way to our contracts and officer letters.

This methodology is used so that we can see the impact of each individual forecast, on our peaks.
02:16:48
It's been really helpful for transparency.

This is how we're able to catch, peak hour shifts due to LFL and, solar PV.

So now I'm gonna go over our annual energy and peak relationship shifts.

So as you can see, based on the orange, lines, our the relationship between annual energy and peak has been pretty consistently intertwined.

As our system grows and demand response has increased during the summer, our peak is growing slower now than our annual energy is.
02:17:27
So you can see that the relationship is kind of splitting off.

There there's a comment on the line, that they can't hear the RPG mic anymore.

Can can somebody else on the line please confirm?

Okay.

Yeah.
02:17:40
Others others can still hear.

So, Raj, I think it's it's just your your line.

Alright.

Sorry about that.

Okay.
02:17:48
No problem.

So as you can see, the relationship is kind of shifting.

They're no longer intertwined.

The farther out we go in the forecast, peak is growing slightly less than our annual energy is.

That's due to demand response increasing.
02:18:03
So now I'm gonna go over our winter weather scenarios.

So something to note is the fact that our our large load growth is so substantial in the first year of our forecast in '25 that there's five gigawatt difference between, January and or February and December.

So we did keep the large loads constant in this simulation so that you can see the impact of weather on the forecast.

So this would be assuming Yuri were to happen in December so that the large load addition is the same.

So with this scenario, we would be at 97 gigs for Yuri if it were to happen in 2025.
02:18:47
We would be at 88, almost 89 gigawatts in December.

And then in 2031, there's still about an eight gig difference.

And with that, I am going to move on to Sam who's gonna go over our methodologies and the outlook of the new forecast.

Could I ask a quick question?

Yeah.
02:19:07
On the base profile, it's showing that it's only residential and commercial, and then you include contracts and office letter loads.

So my question is if it's a 10 megawatt industrial load, where does that get captured?

In, like, a new proposed load?

Sure.

So that would be captured in the contracts and officer letters.
02:19:28
So our information that we have, our economic inputs that we receive from a vendor, they do not include any information based on contracts and officer letters.

We did meet with them to ask them about this to see if it would be captured at both, and they're not.

They don't have any insight into these new loads that are coming in, so it's only captured in contracts and officer letters.

Okay.

So you expect to capture every megawatt that gets added through, any initial loads regardless of how small it is.
02:19:56
Your expectation is you'll have that captured through TSP, contracts and officer letters?

Yes.

We had we had, actually submitted down to, even sub five megawatt level.

Okay.

Okay.
02:20:11
Yeah.

Understood.

Thank you.

Cool.

Hi.
02:20:15
This is from White.

I've got two, questions for you.

First one is the the EV.

So it's a purely low considered as a load or when it's charging.

Right?
02:20:27
But, sometimes they will discharge.

So is that, taking into account?

So we haven't seen any type of pushback on the channel floor on the channel four of the meter data Mhmm.

Showing that anybody's really pushing back to the grid.

Is that because our current market rule doesn't allow that?
02:20:52
There's no I don't I don't think we have anything that doesn't allow that.

I mean, it would be the same as solar.

Right?

You would Right.

It Solar battery.
02:21:02
So, you know, you can put a battery on your house and push back to the grid when, you know, when you have access.

So I think it's the same way.

We just haven't seen that.

We've we've been looking at the patterns at the individual level, and coming up with a, you know, a a true profile of what an EV customer looks like.

And, we haven't seen anything that is pushing back to channel four.
02:21:29
That's not to say this is not happening, but they may not be signed up in a way that they get a channel four to where they can we can monitor that.

Alright.

Thanks, San.

Second question is that, about the large load.

Looks like only crypto load consider.
02:21:47
But, actually, based on my observation, we actually received more data center loads rather than So we haven't gotten to that part of the presentation yet.

Sam is gonna talk about the rest of the large loads that are coming in.

Alright.

Thanks.

Yeah.
02:22:01
Katie, I have one question.

I'm Monica from Vistra.

On slide six, I think in your interaction with Arish, you mentioned that this profile Mhmm.

You're applying only to the existing crypto Yes.

Not for any forecasted.
02:22:18
So something we have seen is that somebody will come with a proposed contract for a crypto site, and then it may change to be something else.

So we don't want to expect that there's going to be this observed behavior if we haven't actually seen it.

So we are only adding this profile to loads that are existing now.

And for, in your slide wherever you have the LFL slide eight, I guess, the LFLs you're assuming no cut no flexibility, no curtailment over there.

Could you repeat that icon?
02:22:53
The LFLs over here, are you expecting them to have show any amount of curtailment?

Or Right.

So if the EV is in the one, two, the fourth bar, then, yes, we're assuming it's gonna have this profile.

But if it is in within the contracts or the officer letter bars, we are not assuming that profile.

Okay.
02:23:14
Let me get to the next slides, Monica.

I think you you'll Yeah.

See.

I hear you.

Alright.
02:23:24
Okay.

Thanks, everybody.

Alright.

So new methodologies, things that we've observed, things that we've done, and things that, well, are constantly evolving.

Right?
02:23:36
You know?

I mean, is it this thing's growing so fast and things are moving around so much.

It's you know, we have to keep moving with it.

I'm not gonna bore you with this slide because everybody knows.

This one is kind of an important thing.
02:23:49
Right?

So when we talked to the TSPs and we said, hey.

Send us what you have.

Right?

Send us your contracts.
02:23:57
Send us your officer letters.

Tell us what's go what you see is going on.

We also ask them, hey.

What do you not only what do you, you know, feel a little strongly about, but what have you gotten?

Like, you got a phone call and somebody said, hey.
02:24:14
Can you give me, you know, 200 megawatts?

And then you never heard from them again, but it's still an inquiry.

So when we add that up, we end up on this third on the 31 number being at 340 gigs for the forecast.

So TSPs reduce that down basically to two eighteen.

This is people that they feel a little more confident in dealing with.
02:24:38
Right?

And the methodology that we're gonna talk about now kinda brings that down to the one forty five.

Now if we looked at prior method, so where we were just kinda looking at the contracts, we're just kinda looking at this this, very you know, a little more, constraint around it, we would have been at one nineteen.

So we are well above where we would have been.

Now if we take last year versus this year in contrast, so last year would be in the blue.
02:25:09
When we brought these TSP, oscillators and contracts in, we saw that in '31, we would be right around one fifty now.

For the RTP, you're gonna add some some losses and and, some factors to that.

But for the load forecasting purposes, one fifty.

This year, when we add everything together, we end up at two eighteen.

Just straight off straight off the, sheets from the RFIs, we end up at two eighteen.
02:25:41
There's a very substantial increase, especially in offshore letters this year.

As you can kinda see in the bars there at the bottom, our offshore letters just drastically increased.

So what does that mean when we bring it all down to what types of load are we talking about here?

And you can see the winner of the day is the data centers.

So data center load for 31, we have 86 gigs.
02:26:14
86 gigs of request.

That's followed by 13 gigs of request for hydrogen and about 12 gigs for industrial and then another 11 gigs for crypto.

Okay.

So what did we do?

How did we get to where we are with the forecast?
02:26:42
So ERCOT, we looked into what is going on with these contracts and offshore letters.

How often do they delay?

What is their average delay?

All that.

Right?
02:26:56
And we said from the point that they said that, hey.

We're gonna energize versus the point that they say that they actually do energize.

What is that delay?

And we came up with a number.

So we took off all these kind of bigger thing bigger projects that had, you know, some some other things around them and said, let's concentrate on kind of the mean here.
02:27:22
And we ended up a little over two hundred days.

Right?

So we said, okay.

Fine.

Here's a good place to draw draw a line, a hundred and eighty day delay in the contracts and officer letters.
02:27:36
Then we looked at every data center that's in the competitive areas.

So across the entire state, we've looked at every data center.

We said, what is their load?

What did they ask for?

What and we also went into some square footages and things like that to try and understand better.
02:28:01
Of what they requested or what they built for and what they are doing, we said, okay.

Give me your highest peak in the past two years or past three years.

Sorry.

Past three years.

Give me your highest peak in the past three years.
02:28:17
What was the maximum that your data center was was consuming?

Then we take that number and compare it with what they requested.

When we did that, we brought it all together.

So this is noncoincidental peak.

So, you know, this one may have been in October of of 24, and this one might have been in January of 24.
02:28:41
But we still put it all together, and we came up with that 49.8% was kind of the highest achievement.

Okay.

So once you put all that together, now we looked at the officer letters.

So officer letters, we don't have a a tremendous amount of data.

Right?
02:29:03
We've only got a couple years of of that, and we actually even took that first year and kinda weighted it a lot lower, just because of the newness of it all.

We ended up with that of what was said that was gonna come on in, by the by January of 25.

It was only 55.4% of those loads, meaning that they in they actually energized.

I didn't we we didn't care about the megawatts.

Right?
02:29:36
So your megawatts were you know, if you had one megawatt, even if you requested 200 and you're coming in at one megawatt, we're counting you as as you energized.

When we looked at the megawatts though, because, you know, curiosity kills the cat sometimes, we did find that of those officer letters, the megawatts were only at 26%, right around 26%.

So we made the decision.

Now the 55.4 seems good.

Right?
02:30:09
We'll we'll stick with that.

So once you add once you take that all of that into account, that is where we end up with the 1 40 5 at 31.

Alright.

So how does that look when we take it back to the level of types of load?

Well, that brings that data center down data center load down to to 24 gigs.
02:30:44
It also brings down quite a bit, on the hydrogen to nine gigs, and then as well, the crypto comes down to eight.

Oil and gas doesn't move that much just because a lot of it is contracted, and a lot of it is really, taken care of in the Permian Basin study.

So alright.

Let's talk about uses.

So the main focus use for for this is going to be for the CDR.
02:31:20
Now RTP will start off with this.

There will be some other adjustments made there as well as well with our RPG.

And then, outage scheduling.

So I do wanna just touch at this real quick.

So outage scheduling for the longer term outage studies, we'll use the adjusted forecast.
02:31:49
Now when it comes to the shorter term stuff, so when we're looking at the next hundred and eighty days, we're using the the interconnection queue.

The interconnection queue does tend to have a little more in it than what we're realizing, what's really coming on.

So, you know, I'll encourage everybody here.

You know, make sure that you're using the interconnection queue.

This is the best way to communicate with us what's going on and making sure that it's up to date.
02:32:20
K?

So now that I've shamelessly done my Bill Blevins plug, you know, the the important thing to note with all of this, with this adjustment is, it's just like the LFL forecast.

Right?

Just like how we're how we're dealing with the crypto.

As we observe things, we'll we're gonna be making changes.
02:32:47
You know, every every time we look at something, it changes.

Right?

Well, that's the beauty of this is that, yep, as as we get more data.

Right?

Because right now, we're looking at, let's say, 200 megawatt data center that's only consuming x.
02:33:05
Right?

Well, as the 500 megawatt data center comes on, are we going to see the same characteristics?

And if we do, good.

Alright.

We're we're establishing a baseline.
02:33:19
If we say something different, then we change and we say, okay.

This is kinda what we're observing now.

Alright.

So I'm gonna jump back over here, and I'm gonna give you the plug for the website.

So we posted both forecast.
02:33:36
We have the TESP provided, and we have the ERCOT adjusted.

Full 87 sixties going up to 20 forty four.

Every hourly waterfall that miss Lam just spoke about will is in there as well for each weather zone.

Lots and lots of data.

Have any questions?
02:33:56
Let us know.

We also are publishing the, the weather scenarios, so the weather years.

And we're going back to 1980 with that, so that if you want you if you wanna look at the 1982, Christmas storm, hey.

We we can you can see it right there.

So, you know, we're trying to be as transparent with this as we can and show you guys exactly what we're thinking.
02:34:27
Alright.

Questions, concerns, comments, and or queries?

Yes.

You do have a a handful of questions in the queue.

Yep.
02:34:35
So first, we'll start with Chris.

Toast with Google, and and I appreciate the efforts ERCOT's taken here to, refine these large load interconnections.

I understand they can be quite frustrating.

I think it'd be helpful on a going forward basis to interlay some of this into the large load planning report, like, what was presented at TAC last week just to give some character to how there's there's a difference between what you're seeing and and what we're actually planning on right now.

And I think continuing to address that as a conversation discussion going forward would be helpful if this final, slide 17, which is gonna add it to that large load in the connection report.
02:35:27
So just a comment.

Thank you.

Yes.

Thank you.

And, yeah, that is actually being discussed and worked on right now.
02:35:40
Next in the queue is Shane.

Hi.

Shane Thomas with Shell.

Yeah.

Again, really thanks, to Sam and Kate and all the team over there for, you know, making this, parade around with the forecast, making sure everybody's got a good understanding of it, and having lots of chances to have eyes on it.
02:35:58
It's been very helpful and and all that.

So thank you.

Yeah.

Thanks for everyone over there.

I had a question on, well, I have two questions.
02:36:07
One is on the use of the the large Los interconnection.

So I'm gonna, I guess, make an assumption and then see if that's correct.

So that that's just a snapshot at the time of the like, when you are doing this study?

Yes.

Okay.
02:36:26
So, like, that's not getting updated as those numbers are updated.

No.

No.

It's this and this particular snapshot was, January 31 in well, for, for the study for the, load research.

Yeah.
02:36:46
We cut we cut everything off at January 31 to go to be with in line with with the, the RFIs coming back in.

Has there been any thought on making a little bit more dynamic updates to the the forecast using that, kind of at regular intervals.

Like, maybe not revisiting the whole forecast, but maybe if you've got that opponent separate component separate, you could quarterly update those forecasts just to kind of allow them to live a little bit more?

Yeah.

So we right now, we're you know, it's it's a little bit of a a staffing issue, but we are working towards that.
02:37:33
So trying to basically consolidate some data and everything so that we can actually do this a little more often.

Right now, it's kinda staying at the annual level, but, I don't think in the future, it it will remain there.

I think you'll you'll start seeing it a little more often.

Okay.

That's good to hear that.
02:37:55
I mean, it feels like at least that one component could be a little simpler to to add in and out without kind of looking at the waterfall methodology that y'all are Yep.

Using.

That also definitely helps in figuring out how y'all got there too.

So, and the last question I had is on, actually, the reliability standard study is, do we have any is that just using one of these forecasts, or is that another forecast?

So that, reliability standards, that's using the 1980 forecast.
02:38:30
Right?

So, yes, it'll use the 1980 forecast, that will be posted.

I think we have parts of it posted now, but it's such you know, it goes back to 1980 and then forward all the way too.

So, it's very, very large forecast.

So it does it we're having to put it onto the website in pieces.
02:38:54
And then, I guess, for the more recent or is it only looking that's that's only looking to be looking at historical forecast, I guess, and projecting them onto the maybe that's not the time we talk about that in detail.

But Yeah.

So, so, basically, right, the way that the the current, you know, the base that base economic forecast is put together, you use the 15 weather you use we're using 15 weather years and kinda, you know, average across.

What what the, weather scenario forecast does is it takes us back takes that back to 1980.

Okay.
02:39:40
That's helpful.

I'm sure I have more questions on that.

But, I think y'all have some more specific where to find me.

Yeah.

Appreciate it.
02:39:51
So next up in the queue is Monica.

Thanks, Sam.

A few questions.

First one, this so the studies reflect that, data centers take time to ramp up.

And was wondering if you are looking to use their load commissioning plan versus the final megawatt.
02:40:15
Which one did you use?

So we used what was provided to us.

We requested from the TSPs the ramp rate of these of these data of data centers or whatever load they were submitting.

So we use their ramp rates as the basis.

Okay.
02:40:33
So then we then then we can assume that their ramp schedule was included in the okay.

The other question I had was sorry.

When you when you looked at the officer letter loads and decided and cut use the percentage, to haircut that, was that the was it taken into consideration the fact that some were delayed versus canceled?

Was that kinda analysis done?

Or So, actually, we didn't any one of them that got canceled, we didn't include those.
02:41:20
We only looked at the ones that that were active and the one yeah.

How they energized.

Okay.

So when when it came to and, like, if we were told, yeah.

This was canceled, then we just we didn't even we didn't pay attention to it.
02:41:38
We just we just paid attention to what was in the interconnection queue and what we were given as officer letters that that energized.

So okay.

K.

So then you said x percentage of whatever was done was energized.

The total took off the what was canceled out of it is what you're trying to say.
02:41:57
Right.

So okay.

Yeah.

So those canceled ones didn't didn't make it into the account.

And then the haircut which was done so data center got a total different, kind of analysis.
02:42:08
Did you think of doing a different kind of analysis for how much haircut to do, say, for hydrogen loads versus industrial load versus the others?

And So hydrogen and right?

You you can't really do a haircut because we only got thirty thirty bags.

Right?

So it's, there's not a lot out there for us to to know what to do there.
02:42:29
You know, you the the data centers were kind of the low hanging fruit.

Right.

We could look at the others, but then you get very then you're starting to get very, very specific, especially with the industrial.

Like, oh, what kind of industry is it?

You know?
02:42:50
But, you know, the same could be applied across across the others.

I think, again, you know, as we look at, like, with oil and gas, I think the Permian Basin study, you know, we're we're kinda still following that.

And as we're seeing these contracts come in, those are mainly from that that same, from that same area, so it is part of that.

So, it becomes really, you know, like, ONG don't really wanna mess with because it's already there.

It's in the study, and it's coming to fruition.
02:43:25
But then as you kinda go back up here.

Then as you kinda look, you know, that's really really the I'm really wanting I I can't wait till we start seeing some hydrogen come in.

I'll be honest.

Right.

That's I wanna see what it does.
02:43:43
Right?

You know, like, what Right now, we don't have a good idea, but I just wanna see what it does.

Yeah.

That that leads me to the next question.

So on the oil and gas that we start seeing now, are those the Permian Island?
02:43:58
Yes.

Because it used to be last year that we were told that it is in the base forecast.

Yeah.

So so this so the Permian stuff itself is in the base.

This is the additionals.
02:44:13
So it's on And so this is what we've got contracted what we're seeing in contracts now as opposed to contracts and offshore letters as opposed to what was in the Permian Basin study.

And so the idea in the base forecast, like, for far let's say for far west is you're gonna try and match the Permian Basin study.

But you also have to take into account that the Permian Basin study is saying, hey.

I've got this much addition.

Well, now we're seeing officer letters and contracts come in that say that is part of that addition.
02:44:49
And so trying to level out and, make it there.

Now one thing I will say is the Permian Basin study is a little behind Right.

In my in my opinion, just because there's portions that aren't included out there.

If you were looking at kind of the overall demand, there are different types of industry that are out there, in Far West that are were not included in the in the Permian Basin study.

And then on the flip side of the coin, on the operational load side, you do have the batteries that are showing up that weren't part of the Permian Basin study either.
02:45:33
So So but I'm sorry.

To repeat, but make sure I'm understanding correctly the Permian the oil and gas Mhmm.

Which is being shown here is on top of whatever Permian Basin oil and gas portion which was earlier in the They melted.

They melted.

So So if we have like, so so here, let's say we have three gigs of contract and officer letter.
02:46:01
We're gonna take three gigs of contract and officer letter, and we're gonna say, okay.

That's that's there.

And then Permian, we're gonna push the two together and say, okay.

Now we're still kinda matching up with what the Permian Basin study is saying.

K.
02:46:20
Thank you.

Alright.

So the next next in the queue is Navaraj.

I think, Monica asked a lot of my question, but, very, very simply saying, so when you determine that haircut process, like a 49% or 55 you mentioned earlier, so can you tell me the process or what are the things you include to determine those percentage?

Can can you repeat that?
02:47:00
So you you mentioned 49% or 55% haircut rate earlier.

So how you determine those numbers?

Sorry.

There's a air air vent right here, white noise generator, you know, Helps you guys not hear the airport, but it helps me not hear what's going on in the rooms.

Yeah.
02:47:26
So, basically, what we did was we we did a very deep dive in to the individual load level, looking at the looking at these, data centers in particular and then also looking at these officer letters that we had received.

And that's how we kinda came up with, okay.

Here's the timelines.

Here's what they asked for.

Here's where they are now.
02:47:57
And some of the some of these loads have been around since, you know, prior to 2020.

So we kinda have a a good feeling about that this is where they're, you know, they're not they're not just ramping.

This is where they live.

Right?

This is this is their numbers.
02:48:16
So, yeah, that's that was kind of the methodology.

So that, so those, sending the numbers, right, from whatever percentage you got.

Right?

So can you guys, make those process public, or is, you're gonna do it?

So everybody can know it.
02:48:40
Right?

All the stakeholders should know what is the process, how it is going on, how I mean, I don't know.

It is public or not.

Well, I mean, I think I think the process I I mean, I think we've explained the process.

The data is something that is a very, confidential thing.
02:49:03
Right?

That's you know, we're getting into individual meters.

So that that is not something that we could, you know, we could, put out there publicly.

No.

No.
02:49:15
I'm not I'm not asking, data.

I'm simply asking the process.

Here here is the, here is the process.

The process is right.

The process is well, I mean, we can, yeah, we can talk about that.
02:49:26
We can, not sure where it would fit, but we could we could run a flag policy who salutes.

How about that?

Okay.

Yeah.

Okay.
02:49:35
Yeah.

That's good.

Alright.

Thank you.

And, next and the second question on that.
02:49:42
So, maybe I missed it.

So that haircut process should apply to the all these, t s speed at the same time.

Right?

In the in the same ratio or how did how did it go If I'm missing, earlier.

Alright.
02:49:58
So I think I got the question right.

Is that does it apply to all t d s p TSPs, evenly?

And the answer to that is yes.

Okay.

It is yep.
02:50:11
Okay.

Got it.

Thank you.

Yep.

And next in the queue, we have Jim.
02:50:17
Yep.

Hey.

Jim Lee, Son of Oil Energy.

Same right here.

On slide 18, if you will.
02:50:25
Yeah.

Can you just help them help me understand a little bit more of what the RPG bullet is trying to tell us?

So if, like, a TSP submits a project based on our TSP forecast, like, what what is what is our expected outcome here?

I it's just a little bit confusing to me.

It begins with the adjusted and then but the TSP will be accepted.
02:50:53
Yeah.

This is, So we are we are still internally working on the process.

We will, you know, we'll bring it to you when we finalize that.

Yep.

Do you, you probably do you have a Yeah.
02:51:08
It's When?

I would say, you know, you should see some of our you know, maybe in the next week or two if we you know, we're working to see what the process would be, and maybe we'll, we'll you know, when when we decide, we will we will publish it, maybe a different form, or bring it back to the RPG next month.

So that's there's a lot going on in terms of, like, the RPG we're working with internally and receiving some feedback from the TSP.

So we'll, we'll let you know.

It it's just because, well, I guess, we we all have projects in flight and queue and trying to figure out how far that target is moving, the goalposts are moving.
02:51:55
And kind of a similar thing for the RTP, as well.

Just trying to figure out how TDSP forecasts fit into the RTP.

Yep.

I I I think you will get some sense in the next, I would say, in the next, week or so.

Okay.
02:52:14
I'm not getting into the details, but yep.

So to build on that, Prabhu, it's our expectation that we can submit projects with the TSP load forecast, and we would need to tell you how to adjust the RTP forecast to take into account additional or subtracting loads over what was in the RTP.

Is there any reason that you don't think you would accept the TSP forecast when you evaluate an RPG?

No.

Our RPG, we are accepting whatever the TSP is posing for that particular project.
02:52:51
Yes.

This I'm talking about RTP.

I'm sorry if if the question was near.

Maybe I got mixed.

Or, the center the previous question was that related to RPG or RTP?
02:53:02
The the first question was RPG, and then my second one was RTP.

Okay.

So the the Maybe I got switched.

So my response for the first one is RTP.

RTP, we are working on the process.
02:53:13
We you will hear more about in the next week or so.

For RPG, our practice is currently that we will stick to what's in the what's in the planning guides and protocols.

Basically, we will accept whatever the TSP is, you know, submitting for that particular project.

Okay.

Thank you.
02:53:34
Yep.

Sorry.

K.

We got a couple more in the room.

First, Harsh, and then Hey.
02:53:44
Probably real quick.

That that in for RPG, that also includes what you're saying is the ERCOT independent review analysis as well.

Yeah.

RPG, ERCOT independent review.

Yes.
02:53:57
That's that we would accept the TSPs loads based on the three different categories defined in the in the by in the protocols.

Harshan, Iq, Oncor.

Back to slide 16.

In your evaluation looking at the data center loads, 49.8%, What was your two questions.

What was the sample size?
02:54:21
And then second question is, what we have on the system are different kinds of data centers.

So was it those are mostly cloud based, I assume, and you did not include crypto in that.

But my question is all the future data centers we see typically are AI driven, and whether training the models or, you know, chat GPD type data centers.

So my question is, do you think those are same thing in terms of how they'll develop the facilities?

Any thought given there?
02:54:50
So one thing I'll say is take a look at your data centers.

If you look at some of the larger stuff I don't I'm I'm trying to figure out how to say this without, you know, timing out anybody here.

If you look at some of the larger stuff that you have on your systems, right, you will see some patterns.

And the idea that that data centers are single use only, I don't think that that's what we're really finding.

I think you're gonna find that there's a lot of mixed use to data centers.
02:55:45
Now cloud based computing and storage has been a very is very much what what a lot of what we have is.

Some of some of the data center that you have out there is even older than that.

Right?

It's it's, you know, old school streaming service stuff, you know, governmental, data warehousing, stuff like that.

You are seeing some of those guys basically tearing their buildings down and starting anew.
02:56:18
But right now, I think that when we talk about an AI data center, I don't think you have I mean, there are some.

Don't get me wrong.

There are you know, because and they're the ones that get the attention.

Right?

Because we're gonna put a huge gig or two gigs right here.
02:56:33
Right?

And it's all AI.

But it's all the other stuff that makes this the 86.

Right?

You don't have 86 gigs of of AI going in.
02:56:47
It's more of your of your video gaming services, streaming services, things like that.

Again, I'm up here not trying to say names of of of consumers, but it's that type of thing that that is actually the more more concentrated than the AI.

Now the AI does there are quite a there's quite a bit of AI in there as well.

Now for ERCOT, we have to we have to have the information, and it's a partnership.

It makes it a lot easier if we receive the information.
02:57:32
When when we do things and we have to go research it on our own, it takes a lot of time, and we may we're giving it our best guess.

When you guys, as the TSPs, tell us, hey.

This is what this is, and this is what we were expecting and and everything like that, it makes our jobs a whole lot easier.

So I, you know, I think that ultimately, every it it is a very much a mixed bag in there.

Now with the AI data centers, there's some solely AI data centers that are out there, not at the hyper scales that we're talking about.
02:58:12
Right?

So how do we handle that?

What do what do we do?

I think no matter what we do, we're just guessing because we're not we don't know what it's gonna look like when you hyperscale it.

We know that it looks like way up and down here, and then it goes into a running mode and kinda just hangs there.
02:58:35
Right?

We know that with the smaller stuff.

Now when you start putting 50 of the smaller things together, does this one cancel this one out?

You know, how does it how does it work?

And I think that's what we're trying to discover, whether it be with NERC right now, e sig, APRI.
02:58:58
You know, everybody's really studying this stuff.

And, actually, for us, we are we've, we're actually out there right now trying to commission our own study for, data centers to see, okay, what, you know conceivably, what does this look like?

How do how do we adapt to it?

You know?

Understood.
02:59:23
And what was the sample size again, the ones you looked at?

I think it was, like, somewhere around 40.

Okay.

Yeah.

And, you know, I would think that a lot of the 86 is AI driven, but what you're saying is it's a good mix of traditional and AI.
02:59:42
I don't yeah.

Like you said, we don't know the answer, But I would strongly suggest asking the, customers, you know, if it's a subset of them on what their business use case is because I would think a lot of that is AI, not your traditional cloud or storage type data center.

I would and I would love to.

Yeah.

I would love to, but I don't have that information.
03:00:06
I understand.

Hopefully, the LLTF, that we're got starting back up, maybe that's a good venue for those type of discussions so we all understand what the use cases are and can make better decisions.

Yes.

Again, if if if we were to get customer data, we would, by all means, be over the moon about it and and turn around and understand what they're trying to do.

But with the lack of that data, we don't have that option.
03:00:35
Got it.

So moving on to the officer letter load reduction, 55.4%.

Did I hear you say you looked at the the number of request TSPs gave you, and then you looked at how many energized?

Is that did I hear that right?

Yep.
03:00:50
So that whole concept is relatively new.

I think that last year was the first time we even did that.

So or the year before?

You guys sent us some things, in '23.

That's fine.
03:01:03
So you looked at '23 and '23 and '24.

Yep.

If they had the in service date between '23 and '24, then you so it's a small subset of the projects.

Because a lot of the stuff we give you now, it's '26, '20 '7.

So I think we really don't know.
03:01:20
So that's the point I'm trying to make that you looked at a very small subset.

The projects that had a near term in service state were the only ones you looked at.

Nothing that has longer in service state.

Correct.

Okay.
03:01:34
And what was the sample size for those then?

On the top of my head, I only have one, one TDSP's number.

Okay.

And I don't want to divulge that here.

There was a larger subset, but that I think that cancer was our I think that question was already answered.
03:01:56
Correct.

Again, I don't have the exact number for, for ERCOT as a whole.

I do have your number, but we can I could give that to you later?

Got it.

Thank you.
03:02:10
Yep.

K.

So there's one more question in the room.

This is Andrew Haman from LCRA.

So is ERCOT gonna bring the RTP load forecast to next month's meeting, to the May meeting?
03:02:32
Yes.

Very likely.

Yeah.

Okay.

And do y'all have any idea of how the adjusted load forecast is gonna be applied to to TSPs?
03:02:42
Is it gonna kinda follow the old RTP methodology, looking at historical load shares?

Is it kind of percentage of officer letter loads and RFI?

Is the haircut gonna be evenly distributed, unevenly distributed?

Yeah.

If you all have any sense of that.
03:03:03
Yeah.

Those are the details we are working on right now.

We don't have we haven't finalized those.

So I I can't, give you an answer right now.

Okay.
03:03:13
And then kind of a a follow-up question is is at any point, is is ERCOT gonna kinda try and unify how it applies load forecast generation assumptions to RTP and RPG analysis.

Last year in the 2024 RTP, we had the generation hub concept.

This year, it looks like we're gonna have this load forecast haircut, that we don't know any details about other than what we have here.

And it seems to go against what PGRR107 says the regional transmission plan is supposed to do.

Next door, an SSWG, there's a 90 gigawatts of load in the planning case.
03:04:13
And we got an email on Friday from ERCOT saying, hey.

Turn off loads.

We can't get the cases to solve even when we're adding hundreds of extraordinary dispatch generators into the case that may not have met kind of criteria for inclusion.

And it seems like we kinda we're using a scalpel, like, the first part of your presentation on EVs and rooftop solar, even LFL ramping.

I mean, that that's great stuff, and then it just comes in at the end.
03:04:49
The officer letter loads like the like the sledgehammer.

Right?

It's the same thing in the transmission planning cases.

We have all all these rules for how we model projects, when we model them, all the information we're looking for in steady state and dynamics, rules on how we model generators, and then we come in at the eleventh hour and try to plan a system with double the load forecast of what we're serving right now.

And it makes it very hard to center points point earlier to run a TPA, to plan projects, to have some predictability of what's gonna happen when we submit projects to ERCOT.
03:05:35
And I'm not I'm not talking about small projects.

I'm talking about big projects that affect zonal flows.

You know, the the the flows on the the Permian Basin import pass and the Permian Basin study and in the 2024 RTP were much different.

Right?

And I imagine they'll be different this year.
03:05:55
And they'll be different in RTP.

And then when you apply load forecasts, it's ten, 20, 30 gigawatts different.

And we discussed this yesterday in SSWG, but it would be nice from ERCOT because y'all kind of hold the information to to to bring something to try and unify these assumptions so that year over year, there there's some predictability, certainly on the transmission planning side, so that we can develop projects to serve this load, that we can kind of get something better than what we have right now.

Because it's it's very difficult to see 218 gigawatts by 2031.

That's six years from now.
03:06:48
That's a 20 gigawatts more no.

A 30 gigawatts more than our peak load in six years.

That's 20 gigawatts per year.

I mean, how are we supposed to plan?

How are we supposed to develop projects if load is increasing almost two gigawatts per month?
03:07:18
And so I I appreciate that y'all are trying to kinda bring this into a realm of just, not even sanity, but just technical feasibility.

But just as much as y'all can, try to document this, bring rules so that we can follow the rules instead of just just winging it.

You know?

Because it's not nice to be this late in the, let's say, SSWG case building process and trying to adjust the load forecast down by thirty, forty, 50 gigawatts.

Just anyways, that that's kind of my my my spiel.
03:07:56
So thank you, Sam.

Thank you, Kate, for for what y'all have done.

I think it's it's good stuff.

I just wanna confirm.

Was there a question in there?
03:08:08
I appreciate the state and the sentiment.

Yeah.

It looks like that's all the the comments I in the room.

Robert, one more.

Oh, one more.
03:08:19
I just wanted to piggyback on what this is Jim Lee for CenterPoint.

Just piggyback on what Andrew was talking about.

You know, we we felt like, again, moving goalposts, in particular, our Southwest Houston 345 reliability project.

You know, it it it it was there.

Tabbed as a reliability need in '23, submitted in '24, and then being told now that generation dispatch can resolve it.
03:08:45
Therefore, there's not a reliability need.

Those are moving goalposts.

It's hard to imagine that if it was identified in '23, how it magically disappeared this year.

And and and like what Andrew was saying, we have this extraordinary load growth.

We have to serve it.
03:09:06
There needs to be some sort of transparency there for on the generation dispatch side.

I mean, and and we've asked ERCOT for those numbers.

It it puts a really big kink in our in our project submissions and how we we can expect what the the the end results to be.

Right?

There used to be a pretty predictable outcome if something was tapped as a reliability need in one RTP for TSPs to come back and be able to have confidence that that that project will, you know, be be be planted and and and go.
03:09:50
So, just something that we, echo Andrew's comments, and, I think, like, the TSP really need that kind of transparency moving forward.

It's gonna be really hard when you have all the goal posts goal posts moving on us.

So thank you.

That that's all I wanted to add.

Oh, thank you thank you for that comment.
03:10:13
I believe that's everything in in the room and the queue.

So thank you, Sam.

Thank you, Kate, for that that presentation.

We do have a update from, I believe, Prabhu, if you wanna give a update on the 765-kV.

Yeah.
03:10:34
This is, Prabhu Naramarkat.

Sorry.

I missed the first part of the meeting.

So if there are any specific questions or do you want me to give a general update on July?

We we did have a question early on about one of the import paths, for the 765-kV, the Solstice to Howard, but I think just a a general update on the 765-kV as a whole.
03:10:59
Sure.

Yeah.

So everybody's aware last week, the PUC approved the 765-kV for the Permian import pads.

That includes the three, 765-kV lines into Permian.

So with that, this year, moving into our DP after all this, you know, you know, finalized one once we finalize the loads and the generation, our our plan is to proceed with, you know, one study.
03:11:30
And, like, last year, we looked at, like, different, like, you know, 345, 765 separate.

But this year, we will come up with one plan, look at, you know, the the needs of transmission needs, whether it's 765-kV or 345 based on the load projections and the updated generation projections.

So that's the plan from from the RTP side.

And, I'm also aware last year, we we identified some backbone infrastructure, whether it's 345, 765.

Now, we we have an option for July.
03:12:05
So we're also open to working with the TSPs and the PUC.

There is already, you know, language in 5066, which specifically says you, you know, there are other if there are other areas of large load growth that's identified, you know, the the PUC and the TSPs can pursue those with the direction from PUC.

So all those things are open.

So from our side, we are gonna continue as a normal RTP for this year.

Unlike last year, we came up with two different brands.
03:12:44
Well, thank you.

Thank you for that update.

Obviously, yeah, we'll we'll be looking into the future for July.

So if you do have any questions, comments, concerns, you know, please feel free to reach out, to the various departments, and hopefully, we'll be be able to give you an answer.

That covers all the material for today.
03:13:05
Are there any other last, questions, comments, concerns, ideas, before we adjourn?

Okay.

Not seeing any.
Item 15 - Adjourn
03:13:16
Thank you all very much for participating in today's RPG meeting.

We will be taking I think, what do you say about an hour break, before PLWG?
03:13:27
Well, I was thinking till 01:30.

One thirty?

Yeah.

Just go get some food and come back.

Sounds like I know my food's waiting for me at the at the truck.
03:13:38
Yeah.

I'm not getting the food checked.

I need something different.

Robert, nice.

Yeah.
03:13:43
I think, yeah.

Alright.

One thirty.

Yeah.

So are we gonna start the Webex again?
03:13:49
Is Is it a different Webex?

Are you gonna consume We we can use the same same Webex, and we'll just start at 01:30.

Okay.

Sounds good.

Thank you.
03:14:03
I'm sorry.

Tao, do you do you have a question?

I was I was muted, but, I think you mentioned about the how are to fastest some things for the import path question.

I didn't hear any update from or, discussion or, talking from Prabhu about it.

What was that?
03:14:24
That How are you?

The concept of the having a hard time hearing you, Tao.

Yeah.

I think my you mentioned the Howard two thousand 765-kV kV impo path comment or some questions about it.

I didn't hear any update from Prabhu.
03:14:43
Just wanna know some of the details you about that, input path.

Can you hear me still?

Having a lot of lot of noise in the room right now, so it's making it very hard to to hear you.

Could you just give me a a call?

Okay.
03:15:02
Will do.

Thank you.

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