(gavel hammering)
-: Good morning, this meeting of the
Public Utility Commission of Texas will come to order
to consider matters that have been duly posted
with the secretary of state of Texas for July 26th, 2021.
For the record my name is Peter lake and with me today are
Will McAdams and Lori Cobos.
This is another in our continuing series of work sessions to
learn about and discuss key topics
related to the Commission and ERCOT.
As a reminder,
today's discussion is about project number 52268.
Of course we can't have there are more people
with good insights and opinions on this project
than we can fit into the room or in a single day.
So we'll always ask folks to file comments or information
on these particular projects as we move through
these work sessions,
even if they don't have a chance to be in the room.
Let's move through our agenda.
I don't have anything for item one, two or three do you all?
-: No sir.
-: No.
-: Takes us to item number four,
on discussion and possible action
on electric liability, et cetera, et cetera.
Our first topic is DSP to RTO relationship
and we've got Richard Ross with AEP,
introduce yourself and take us through
your presentation please.
-: Yes, sir.
I need to do anything to this.
Okay.
I'm Richard Ross with
American Electric Power service corporation.
I'm the director of RTO policy.
I'm here today to talk to you about,
the RTO and TSO, DSO communication exchange.
I'm here, David Ball, my manager of transmission operations
would not be able to be here today with me.
So I'll do my best to answer any questions that you have
and take you through the information we have for you.
What I wanna do is give you a highest level overview of
the various roles and responsibilities between ERCOT
at my transmission, operations and distribution folks,
and give you some insight in terms of the comparison
to the Southwest Power Pool.
To the extent you're interested,
I'll touch on that very lightly.
You can certainly ask any questions you want
and I'll try to respond to those
and then some additional comparisons
at the very end of my presentation.
So next, the first element that I wanna clarify for you
is the balancing authority.
The balancing authority is that role that ERCOT serves.
The ERCOT staff serves and similarly
in the Southwest Power Pool.
The Southwest Power Pool serves as the balancing authority
for that particular region.
And under normal operations we're focusing on the commitment
of generation to match the demand that we have on the system
and there's an adequacy of generation so that we are
matching generation with demand.
When we experience a situation
like we experienced in February
where we have a generation deficiency that responsibility
or that action reverses.
So that we are doing everything we can to match the load
with the generation that we have available
and that is the balancing authority in ERCOT responsibility.
The second area that is the reliability coordinator
and the reliability coordinator is that entity
that is responsible for overseeing the reliability
and stability of the overall bulk electric system.
ERCOT also serves in that role as the RC in Texas
the Southwest Power Pool serves in that role as the RC
for the Southwest Power Pool.
But they have available to them all of the information
from all transmission operators
from the balancing authority functions
from the generation operators across the entire region
and so they with the tools,
the reliability tools that they have available to them
have the best insight available to them to determine risks
and actions that need to be taken
from a reliability standpoint
to maintain the security of the bulk electric system.
They have information that I as a transmission owner
is gonna be beyond my borders
and may that I can't have the visibility into
and likewise the other transmission operators
and so they bring us all together
although we work very tightly together
in our interaction.
Next the transmission operator,
is the entity that's responsible for that local transmission
so I'm overseeing and monitoring and responsible
for the switching activities associated with
the AEP transmission facilities
and in a deficiency situation like we experience
the operator is receiving in the instruction
from the reliability coordinator to curtail load
and how much to curtail.
The allocations based on the percentage
of the load at the Summer peak during the February event
AEP Texas Allocation was 8.7% of that responsibility
and the reliability coordinator at ERCOT
would communicate our curtailment responsibility
by telling us the number of megawatts we need to curtail
as a transmission operator.
We then will relay then that instruction down to
the appropriate DDC centers to effectuate that curtailment.
When they communicate that to us
it will come in via voice communication
so that there is clarity on exactly what we need to curtail
and then we will turn either through
SCADA if necessary from a transmission standpoint
to make that interruption
but most likely we will turn around
and give an operating order to our distribution centers
and then they implement their load shedding plan
where they will go through the plans
that they have developed shedding different blocks of load
under ideal circumstances going through a rotation
we simply got into a situation where we went further
and rotation became very challenging
but ideally they would then implement
and begin the rotation activities
that they have rehearsed in their training.
If the distribution center is unable to comply
unable to shed the necessary load in a timely fashion
from a transmission standpoint we can also take action
and would take action to make sure things get off the system
as quickly as necessary.
And this step is virtually identical
in the Southwest Power Pool
where the Southeast Power Pool as the RC
will communicate to my transmission operations staff
they will then likewise relay that signal back
to our distribution folks to effectuate the curtailments.
So very similar communications.
The distribution provider this feature role is where
it takes on the activities between the transmission system
and the customer so all of the distribution wires activities
that are in place or facilities that are in place
between the transmission system and the customer.
They are the folks that are in the best position
to determine what load needs to be shed
what the condition of the load is
and work directly with the customers to the
extent necessary to implement those curtailments
and achieve the necessary curtailment.
As I said earlier in the event that they are unable to
move quickly enough transmission actions can be taken to
at the transmission level to interrupt distribution circuits
or I'm sorry the distribution substations.
I would say that the actions the distribution system
can provide are far more surgical than the transmission,
transmission if it comes to that is gonna end up
taking out multiple circuits.
Training all of these activities fall under,
well many of these activities fall under the NERC criteria
and training requirements
and we go through training each and every year
to refresh these activities.
Prior to someone a transmission operator being placed
in this role where they are responsible for these functions
they're gonna go through training at E-training
as well as simulation training
and over and above that each year
the operators are going through training on both
curtailment activities as well as restoration drills.
So we do drill on these these things
so that they're familiar with the actions
they need to perform.
Some positives and improvement areas.
The pre-event planning activities before
we got into the curtailments was certainly good.
The operating instructions and restoration
we executed in a timely manner and avoided a system collapse
but we could use we,
we see some additional equipment in the field
for devices tied to the SCADA tools
and more smart grid activities.
There's also a need there may be between
the Southwest Power Pool and ERCOT we've been discussing
within the working groups in ERCOT some communication tools
that SPP has that we may want
to pursue implementing in ERCOT.
They've been talking about that for a little while
but ERCOT is seeing that as a heightened
area of improvement.
ERCOT versus SPP now during this event
we both experienced a capacity shortage
so they were very much the same the major difference was
the extent the depth of that curtailment situation.
SPP had more flexibility in that we had
SPP had available imports from outside parties
to the tune of 6000 megawatts at times that curtailed
as we got into further into the emergency
and as it lowered SPP had to curtail service
to interrupt customer service as well.
But much more availability of import capability
and that compares to ERCOT's roughly 12 to 1300 megawatts
of import capability not counting the blocking of resources
or blocking of loads.
As I said earlier ERCOT and spp similarities is in both the
reliability coordination and balancing authority functions
a small difference between the two in the sense that the
transmission operator functions are shared
between ERCOT and the transmission operators
and so there is some delegation activity there
whereas SPP is not registered as a TOP at all.
Not a major difference in this situation
but it is a difference of these
in the construction of these responsibilities.
The load shed activities were virtually identical.
SPP the allocation was 16.8%,
I've indicated it's the highest
it's actually the second highest
when EnerGs companies are taken into account
and in ERCOT we're the third highest.
Our peak load shed was virtually four times
in ERCOT what it was in SPP
and so you get an idea of the the scale of the difference
from that figure of the differences
in the scope of the curtailments.
And with that that's all that I have for you at this point
are there any questions?
-: I'm sure there will be.
-: So yeah thanks Richard,
question on the relationship between ERCOT and SPP
AEP's uniquely positioned and then you manage a DC tie.
-: Yes sir.
-: Okay so let's talk about DC ties
and is there a means that you could elaborate on
for possibly ERCOT to consider
especially in that last resort scenario
where we have a obligation for massive shedding of load
if we have foundational generator failure resource failure
in the system again is there a way to
on a transmission basis further integrate ERCOT
into other systems without necessarily
adding to a commercial application you see what I'm saying
I mean augment possibly our the security of the ERCOT grid
outside of opening it up to a larger DC footprint
than we otherwise would,
that may be a convoluted question
I am nibbling around the edges
of something very dangerous here so.
-: And which puts me also in dangerous territory.
(members laughing)
But I'm sure my attorney will yell at me if I get out a lot.
-: Mine can't reach me so.
(members laughing)
-: I think there are certainly some things
that we can investigate around the DC ties that might
in a extreme scenario if for say we had gotten into
a black start situation I'll go even the most extreme
where we could provide additional assistance
from the Southwest Power Pool into ERCOT
without exposing I mean there obviously would be
some commercial activity settlements
that would have to go on as those things go happen
but there's certainly ways to provide additional assistance
even beyond the DC ties
in that kind of restoration situation.
I can't magically make the ties bigger
in the throes of the event while it's still going on
but we can do everything we can to make them available,
make power available from the from the Southwest Power Pool
and in that most extreme situation,
provide assistance for restoration
there are some things that we've been discussing internally
that we might consider and might approach at some time later
but we've got to be mindful of the desire to
make sure we take all the steps necessary
before we move forward with anything like that.
So I hope I'm not being too vague.
-: No that's where I'm headed I'm trying to establish
for market participants that
yes all options are on the table but also maintenance
of the integrity of ERCOT
in terms of the commercial aspects of ERCOT
that we do, that we are self-contained
we are still Islanded
we still are captains of our own destiny in that respect
but that there are means available to ensure reliability
and possibly gain assistance from other grids
at the same time because who knows what the future holds
in terms of natural disasters
or any type of recovery efforts that may be warranted.
-: Absolutely I mean we've threaded that needle
to some degree or to a great degree already
with the block load transfer functions
we have in ERCOT today
where you end up with a situation where
load is either already gone because it's out
because of a contingency
or we're in that emergency situation
it's in the dark at that stage,
having it served or having it
us getting emergency assistance
in a way that doesn't integrate ERCOT into SPP
doesn't hurt the commercial system at all
because it's either lights out or light served
in another way so.
-: If I could add or ask,
how many ties do we have right now five, four or five?
-: Four or five.
-: Okay so it's about 1200 megawatts.
-: Yes ma'am.
-: Worth of megawatts that we can move back and forth.
To your knowledge are the are all of these DC ties
currently allowed for commercial transactions
right back and forth between okay so.
-: Yes if understanding yes ma'am
so certainly the ones AEP yes.
-: Okay, so certainly one thing
we don't want to lose sight of the fact is that
these DC ties while we do need them for reliability at times
and that's also dependent on whether our neighboring
ISO or TOs in Mexico are not in emergency conditions
because if they are they will cut them off
and we won't be able to use them.
But the DC ties also provide a means
for commercial transactions that will provide generators
an opportunity when we're not in reliability conditions
to access another market
and so it's also from an economic standpoint
a good model to have but I guess
certainly with an eye towards preserving our jurisdiction.
-: Yes.
-: But I think what you're alluding to is FERC
we already have an established process for DC ties
with DOE waivers and FERC approval
and although we've kind of gone through a dance
in the recent few years about
kind of looking into that a little bit deeper
as a result of some discussions
that may be at the Commission like maybe two three years ago
I think that model is still in place
and something that if we wanted to move forward on
there's an established process
that would not disturb FERC jurisdiction.
-: Certainly.
-: You mentioned that if the load shed
doesn't happen quickly enough at the distribution level
the transmission level can step in
I'll be on a less surgical base
or using a broader brush if you have a less surgical basis.
What time frame does that happen?
-: I mean we would see that if we're not able to
and Jeff you may want to supplement if I get this,
if I don't go quick accurately but if we have 30 minutes
to get the curtailment done
and we see that that's not coming off
we're gonna take that action if we get to the point
where we see the distribution centers
are not gonna be able to achieve the instruction
in the time frame required by ERCOT it's not gonna,
we're not gonna wait to the last minute.
-: Is 30 minutes of standard time frame.
-: I think that's what we've been operating under yes sir.
-: Okay so you'll get.
-: We're gonna achieve the directive.
-: Right but you when you get a directive for load shed
you've got 30 minutes to implement generally speaking.
Okay, you mentioned in your slide
about positives in areas for improvements
more field devices tied to distribution SCADA tools.
What does that look like in practice?
-: Why don't you come on up Jeff you can help me more with it
and introduce yourself.
-: Good morning I'm Jeff Stracener with AEP Texas
I'm vice president of the distribution organization
there so I'll try to help out with that a little bit
so one of the things we're looking at
that hasn't come up yet but we'll come up with a
upcoming presenter is the addition of natural gas
critical infrastructure and so how do you work around that
and so that's one of the issues around
more smart grid infrastructure if you've got a natural gas
customer that's on the middle of a line
right now you can't open up that breaker
and take that whole line out 'cause
you'll take that one customer out
but maybe you can put a sectionalizing device
just past that customer
and operate it from another system outside of the system
we're using to operate our breakers
and then that creates the issue
okay I've got to keep track of that load that I just dropped
out of a second system
and make sure I respond back our TOP and to ERCOT correctly
so that's one of the things,
are primarily the things that we're talking about there
we do have a small number of substations
that do not have SCADA on them out of the 1500 or so
circuits that we have we have a little less than 200
that do not have remote control to them
they're in mainly in rural West Texas,
not a lot of good communications out there much less
remote control of them
and even though that's less than 20% of our total circuits
it's only about 6% of our total load
that's controlled by that so
there is certainly an opportunity to extend that
through those type of substations
and get that added SCADA out there on the distribution side
but it is a little bit of a diminishing return for that
small incremental load that you'd be able to add to the mix.
-: And on that topic AEP by virtue of your service territory
let's talk oil field.
It's a lot of load not a lot of people
in terms of this prioritization conversation
that's gonna come up.
It'll be important in terms of knowing where
critically designated areas are for your system
and then I guess future enhancements
in terms of how you can maintain the integrity
of those areas while focusing your load shed efforts
in other areas meaning we don't need to prioritize
the entire field necessarily but we will need to prioritize
enough resource to keep ERCOT viable
in terms of a management condition during a scarcity event.
So I guess what I'm laying out there is that we need to
keep that in mind in terms of your position
and the co-ops position matter of fact how do you
communicate with the co-ops
in terms of the Eagle Ford Shale for instance
when managing through these type of events
how did you communicate with them during Yuri
I mean everybody basically got their big tranches
of the you know allowable load that they had to shed
but mechanically how did that work?
Everybody just did it over 30 minutes.
-: And I want you to take that.
-: Yeah.
-: So at least you take that spirit.
-: Yes so for the most part
we did not work directly with the co-ops
we only worked with the co-ops in cases
where they have metering points
tied to our distribution system.
So if they're, normally they work through
their transmission provider
whether it's south Texas electric co-op
or Golden spread or whatever they,
they get their load shared direction from ERCOT
and then communicate with those co-ops.
So from an AEP Texas perspective the only co-ops
we dealt with during this were ones that had a takeout point
on our distribution system.
-: I have a specific question that kind of goes along with
Mr. McAdams questions,
how many natural gas facilities do you currently have
registered as critical loads on your system right now?
-: Today we have 71,
in comparison we had 11 back in February.
-: So that's 71 what is that is that all
the drilling location is at?
-: Is at 171 we've gone from 11 to 171.
-: Right.
-: Of those 171 do you have a sense of
what are drilling locations versus
compressor station pump stations
and what those- -: No sir
and that's where we really need to fine-tune that
and that's where we need ERCOT, utilities, the Commission
railroad Commission all working together to really
identify what what truly is critical
versus some cathodic unit
or something that might be added to a list somewhere
so and the other valuable piece of information
that's 171 customers but it's on 85 to 90 circuits
so it's not like they're all on a handful of circuits
I mean they're spread all over so basically we got a
two to one ratio of customers per circuit
if you look at it that way sir.
-: So you're at 171 registered natural gas facilities
right now is critical loads
and I'm assuming that list is growing over time.
-: Yes ma'am. -: Yeah.
-: Okay.
-: And if you've touched on,
several points you've touched on
more surgical load shed whether it's at the
natural gas facilities or more broadly
isolating those circuits so the critical resources can be
kept online without while still maintaining enough load
to rotate for the the rest of your customer base.
If starting today hypothetically the decision was made
and all obstacles were removed
to implementing a plan like that
whether it's getting secondary circuits
for the gas pipeline like you mentioned,
how long it would it take to implement that?
-: I couldn't give you a realistic answer
I mean a lot of that's gonna depend on
where those accounts are along that circuit
I mean if they're right outside the substation
and I can just put a switching device right past them
and drop that entire load that's one thing
if they're sitting down there on the end of that line
there's not much I can do to surgically
remove load from that I'm pretty much gonna have to protect
that entire circuit for that customer that's down there
at the end of the line.
We would need some time again to pinpoint exactly
where all these are and what our options are now I mean
the technology and we're already doing something today
with the smart grid
and we have you know interrupting devices
other than breakers that we use today
as a part of our distribution automation schemes
and stuff and so we're already very familiar
with that technology and stuff and we've got that in-house
so it's not a matter of needing to develop
a lot of technology or bring it in-house
for us we're kind of there but the bigger issue is
pinpointing where they're at
looking at what our options are
and determining which is the best option to move forward.
-: Are there any actions that the PUC
and or ERCOT can take to further move along
smart grid infrastructure development
to allow for more surgical load shedding procedures?
-: Well first of all one of the actions
we need your help with is to make sure we're looking at
the appropriate accounts and don't have a mass list
that's not pertinent or not truly critical to this process
and again I think that's a combination
with the railroad Commission and the oil and gas industry
and the electric utility industry and so forth.
As far as advancing smart grid
you guys took some action back with AMI years ago
that certainly advanced that significantly
with the opportunity there maybe it's time to think about
smart grid in that that relation.
But conversely right now
we do have the opportunity to come in with
and show the prudency of the spin that we do have
and make it a part of our rates.
-: Right.
-: But there's not any specific like rule
or ERCOT protocol something we can work on
to provide you with some kind of regulatory certainty
to move forward with those investments.
-: Not to come to the top of my mind
but as the other utilities come up they may have something.
-: I think we'll touch on some of those
in the later presentations
but we're certainly always,
certainly looking at the situation
and we will certainly
AEP Texas will bring up the whatever possible solutions
or ways you can help us remove those barriers
certainly if it's an initiative the Commission wants us
to move forward and address
we're gonna do what we can to address those issues.
-: Please do yes as you come up with ideas on that
please do circle back because as you mentioned before
we've already invested in smart meters
the consumers have paid for the smart meters
and I think it's important to capitalize on that existing
technology where we can to help us more effectively
and equitably implement load shed procedures in the future.
-: Okay.
-: Anything else?
-: No sir.
-: Any other question for this?
-: I do not think.
-: All right thank you gentlemen.
-: Thank you.
-: We will now move on to our second topic
regarding existing ERCOT load shedding
process with Mr. Dan Woodfin.
-: Good morning I'm Dan Woodfin senior director
of system operations ERCOT.
Next slide.
So I mean I think a lot of this is gonna be
the interesting thing about being
sandwiched between ERCOT and AEP
is a lot of what they're talking about
in either presentation is a little repetitive of what
I'm gonna be talking about but there is
some new information in here.
The idea of course of load shed is that
when we just have exhausted all other possibilities
and don't have enough resources to serve the consumer demand
we as Richard mentioned earlier we have to lower that demand
and the way we do that is referred to as low shed.
ERCOT's role in that is determining how much load
needs to come off the system in order to balance
with the amount of generation that's available.
The obligation on doing that load shed as Richard mentioned
is on the distribution providers,
each distribution provider is obligated to have a 24 by 7
control room with which that has control over breakers
and those kind of things
and typically that's a a transmission operator
that provides that and so in the ERCOT operating guides
the load shed percentages are allocated out
to those transmission operators
rather than out to the distribution providers.
Next slide, this table is in the operating guides
it's based off of the percentage of peak demand
for the previous year for each of the transmission operators
that were reported at ERCOT.
So we review that at least annually
but also make changes to it when there's a change
like for example the city of Lubbock has been added
to this table recently and the allocation reallocated.
Each block of load shed as discussed earlier has to
it's required to be shed within 30 minutes
if the block size is above 1000 megawatts
they can actually in the current version
of the operating guides it may take longer for
those to be implemented
but as we saw in February for the most
part those blocks can be shed much
quicker than the 30 minute requirement
and so something that we did for Summer of 2021
based on what we learned from the February event
was ask the transmission operators
really how fast how much of this load can you shed via SCADA
rather than having to go out and shed it in the field
and how quickly can you do so
and the numbers that are in this table
and of course that will somewhat depend on how much load
is on a particular feeder that they're turning off
and so to try to allocate that we looked at the overall load
on the system and asked them three different categories
60 gigawatts on the system, 70 gigawatts and 80 gigawatts
how much would you be able to shed
and you can see the numbers there that roughly
23, 27, 31 gigawatts can be shed
kind of isn't on some of these critical circuits
isn't transmission connected loads
and is is controllable by SCADA.
So that's of the 60 gigawatts 23 out of 60
it could be shed that way
and then most of it can be shed within 15 minutes
some may take a little longer
and I think some of that may be how the TSP
answered this the transmission operators
answered this question.
Some were were saying well we can get it done
within 30 minutes because that's the requirement
they may actually be able to get it done
in a shorter period of time but it was the way they asked
the answered the questionnaire
it was what they were willing to commit to
and of course the avail amount available for load shed
depends on the weather conditions if it's
if a cool front has come through Dallas
and not gone on down to the valley
there may actually be more load that's in the AEP area
and the Houston area as opposed to the ERCOT area
and so it varies even within a particular weather pattern
how it's spread across the system
and so that's really what I wanted to provide to you
but I'm happy to answer your question.
-: Sure thank you can we go back to the previous slide.
When you said the total of the 60 megawatts
total load that can be shed is 23, 27 out of 70,
31 out of 80.
Is it correct to say that those 23
gigawatts are not critical load
and are controlled by SCADA and any other character's
characterization of those.
-: So under the kind of the below the table there
it's the ones that aren't don't have under frequency
load shed protection so they're not part of our kind
of safety net for if we can't shed the load
in a controlled way.
There aren't on critical loads
whatever those are defined to be by HTO
and they aren't on network distribution
so I think CenterPoint has some slides about what
network distribution is but basically it's in the cities
where you don't have radial distribution
you've got it more networked and then they aren't the
transmission connected more the industrial loads
we're taking out that as well.
-: Okay so broadly speaking we're only
about a third of the total.
-: System wide.
-: Yeah system-wide need for load
only about a third of that load is eligible for rapid
load shed without manual intervention.
-: Correct based on based on the TO's estimates
for this Summer.
-: Okay do you have any sense of how other ISOs fair in that
what other third a half 10%.
-: Yeah I know that this is something that's come up
on various calls with other entities like ERCOT
across the region is something that they've
when they saw kind of how much load we had to shed
at least the kind of discussion around that was
well we don't know what we could do in that regard either it
we may not be able to do any more than that maybe less
so I certainly think that based on my memory
and I wasn't in operations at the time
but in 2011 there was much less than that
that could have been shed that could be shed by SCADA
so the TO's have made some improvements since 2011
and how much can be done via SCADA.
-: Okay thank you.
-: I wanna follow back up on
so you confirmed that about a third would be eligible for.
-: Yeah bet you're asking me to do math on the-
-: I think the chairman said the third I count on his math.
(members laughing)
I think I can rely on his math
so about a third is eligible for load shed this Summer
and that is that-
-: That's actually is available.
-: Available. -: Yeah.
-: And that includes taking into account all the natural gas
facilities that have been registered as critical loads
that you're aware of.
-: Yeah so based on the discussion while ago
that that's been going up quite a bit.
This survey was sent about a month and a half or so ago
so it wouldn't include any increases
that have happened since then so it was based off
of what they knew at the time.
-: Okay thank you and I have like one I guess a question
or a request for an explanation,
the under frequency load protection
can you sort of explain that in just kind of
simplistic matter what is that exactly?
We've heard a lot, we heard a lot about
under frequency load protection during
the legislative hearings this past spring
and I'd just like to learn just a little bit more about it.
-: Yeah so if that, the idea is that
if the balance between generation
and load gets out of whack
where there's not enough generation to serve the load
and that happens in a kind of a slower manner
because of generators tripping off or load growth
then we can manually implement this kind of load shed
to protect the system and make sure that the frequency
doesn't get so far off that it causes bigger problems.
The idea of the under frequency load shed
is to provide a safety net
so that if a a unit trips or a bunch of units trip
and the frequency drops very low
then the their relays on some of the distribution circuits
are the transmissions distribution circuits out there
that are set to certain frequency levels so
59.3, 58.9 and 58.5 and so if the frequency
were to drop that much
then it automatically sheds load rather than us ordering
the load to be shed in order to bring the system back
into balance and recover the frequency
and that there's 5% of the system that's set at that
higher level the 59.3 and 10%
at each of the the other levels
and the utilities are required to maintain that
kind of safety net in place so there's at least
that 5, 10, 10% of the load on the system that is
can automatically be shed to provide like I say
that safety net.
-: Thank you.
-: All right thank you Dan appreciate it.
Next we'll have call up Oncor.
Oh I'm sorry yes Oncor, CenterPoint and TNMP.
-: If we weren't before we are now thank you.
-: That works well.
-: Good morning Commissioners chairman
my name is Liz Jones and I'm the vice president
of regulatory affairs for Oncor.
-: Good morning Colin Martin with Oncor electric delivery
senior director of transmission grid operations.
-: Good morning Eric Easton vice president
of real-time operations at CenterPoint Energy.
-: Good morning I'm Keith Nix I'm vice president
of engineering Tech services for TNMP.
Stacy Whitehurst vice president regulatory affairs
for Texas New mexico Power company.
-: Thank you all for being here.
If it works for y'all just we'll start off going through
I know what are several presentations
and if you don't mind I'm guessing
we'll ask some questions along the way
it would be may not be productive to wait till the end
so if you don't mind some interruptions
we'll appreciate you humoring questions
as you go through the presentations.
I'll turn it over to Oncor.
-: I appreciate the interruptions you might have.
I'm gonna skip this first slide
since Dan did such a good job of giving
the overview there
and start with the discussion of priorities
during a load shed event.
So during any what you call a normal day
there's a lot of operational priorities
that we manage through from a utility standpoint
ERCOT standpoint in our control room
to keep the system up and running in a reliable
and secure manner.
When you get into a short supply situation
there's some additional things that are they're always
in the back of your mind and things that we're prepared
for and ready to act on but they really come
to the forefront of what we're working on
during that day and we have to focus on.
And the number one is preventing a system blackout.
Protecting the system is absolutely number one
to avoid that blackout and having to go
through the process of picking up the pieces
and the way that we protect the system from that blackout
is what Dan was walking through
instead of the normal practice of manually
matching generation to the amount of load
as load just varies normally in coming up with
the economic solution,
we then have to manually control the amount of load
to match which generation is available.
And those manual actions it requires immediate accurate
and coordinated action between all
transmission operators and utilities across the state
to accomplish those actions and do that quickly.
Those actions have to be straightforward
have to be pre-planned
and you have to be well trained to execute those quickly
and get the desired results.
Number two with the system in a secure state
we're obviously in a bad situation when we're shedding load
customers are being significantly impacted.
It's critical for us to be aware of where we have
customers I'm gonna use the term exempt
and I'm gonna slide a bit later
a little bit later in the presentation
we'll give some clarity between exempt
and perhaps critical but knowing where those exempt
customers are at
and keeping those exempt customers online
that are critical to the public health community welfare
and integrity electric system
when you know where those are at
and we need to keep them online
during an event like this.
Now it's important to recognize that even for those
type of customers we can't guarantee continuity of service
but we do elevate those from a low shed standpoint
exempt them from those low shift rotations.
And then number three and this this one has come into
quite a bit of focus given the unprecedented depth
and duration of load shed that we had in February
but doing everything that we can to equitably
and effectively rotate what capacity is left
on the system to minimize impact to customers
and going through these slides I'll touch on
a little bit more detail on each of these topics.
So key thing here load shed is a pre-planned event
it's not something that we're coming up with
and figuring out how we're gonna handle this
by the seat of our pants when we get the call from archive
and I like to think of it.
(members laughs)
Now stating the obvious but I like think about it
in two pieces I mean you have the you have the plan
and then you have the execution of the plan.
In each entity everybody up here on the table
all the entities on the table that Dan showed as far
as how the load should have split up
everybody's gonna have a documented plan on how
they're gonna handle this.
Oncor plan is a 300 plus page document
it covers the procedures for load shed,
our philosophy, our priorities and it covers
how we're gonna handle that all the way down
to the distribution circuit level
and what type of exempt customers exist
on each of those circuits.
We review and update that plan twice a year
to capture any changes in customers or repeaters
or other system changes that need to be just need to be
updated in that plan.
Dan mentioned the the load share breakdown
Oncor percentage is 36.16% of ERCOT
our load shed plan will take that percent
and we'll actually break that out into six different regions
across our system to nail down exactly how that load shed
directive is gonna be spread
across our system geographically
so that we have that plan in place and ready to execute it.
All of the load on our system will really fall
into four buckets
and there was previously some discussion
on each of these items.
Under frequency load shed that's our safety net
that's automatic action that's taken by relays
out at the substation
there's no human interaction whatsoever.
Each entity is required to have a minimum level
of at least 25% of their load subscribe to UFLS at any time.
Now at that minimum level it means that's in any type
of situation whether it's the
highest level of the Summer or Winter
or shoulder month in in March or April
where loading might be lower.
So a little bit later in the discussion here
we'll see how that number does vary a bit
but the 25 is the floor.
So that the headroom in there might be something
that we can talk about using as a potential mechanism
to alleviate some of the rotational concerns.
The exempt customers that's the public health,
community welfare integrity of grid
those are those customers that need to stay online
to keep things up and running.
Transmission connected we do not include
transmission connected customers in our load shed plans
based on the impacts to the grid
of potentially shedding those customers
I mean they're connected directly to the grid
and that can cause disruptions to the transmission system
when the system's already in a somewhat of a fragile state
and we'll talk about that here a little bit more
two slides from now
and then everything else that's left on the table
falls into the manual load shed bucket
and from an Oncor standpoint that number
hovers around 40% plus or minus
depending on loading conditions.
-: Standard just 40% of total load is in the
eligible for the manual load shed.
-: That's what's left after
excluding under frequency load shed
exempt and transmission connected.
-: Okay great.
-: How many natural gas facilities do you currently have
registered as critical load today?
-: Today we have seven well as of early July we have 795
registered before the Winter event we had 35
and during the Winter event we didn't
shed a single one of those 35.
as we progressed through the week
of February 15th through various outreach
and starting to add back production fields
and midstream compression and the whole gas supply chain
that number grew from 135 to 187 during that week
and then with the revision of the forum
and the outreach with PC and railroad Commission and Oncor
and internally as well that number number's grown to 795.
-: So given the state of the law today
and your procedures and ERCOT's procedures
say a Yuri level event happens
with the increased
registration of critical infrastructure now
I assume a lot of that is concentrated
in certain parts of Texas your western territory probably.
-: Mostly but not entirely.
-: Okay so and you're dividing your
load shed percentages up six ways?
-: Across different regions.
-: So how do we keep the residents of West Texas
from freezing to death
in light of a heavy proportion of non-curtailable power
to certain areas?
-: So I think that you all have up to now made an assumption
that natural gas critical is non-curtailable
and depending on the depth and time dimension
of rolling outages that may not be
the right assumption to make.
So obviously the PUC staff and the railroad Commission staff
are engaged on the joint rulemakings that are required
and we expect to have a lot more sort of shake out
from that conversation because up to now
the electric companies and the gas companies
haven't communicated as well as they should have obviously
but it's important to note that there are five kinds
at least of of critical.
So there's critical load natural gas,
critical load industrial, critical load public safety,
critical care for individuals
and new categories that involve dialysis centers
and homes for older adults.
So if we were to honor all of the criticality
across those five categories
we would not have a feeder we could shed
given the other limitations that you see up there.
-: So essentially you would not have a what?
-: We would not have for,
we would have virtually no feeders that we could shed
because every feeder we have virtually
has one of those kinds of customers
and the natural gas guys are not only out in the Permian
although they're a bunch of them
those pipelines run all the way across the state
compressor stations, midstream processing facilities,
gas storage facilities.
So we're talking about a huge quantity for Oncor
and I think for the other utilities that is not sustainable
unless we have a very shallow and very brief load shed.
It is our hope and it is a hope that we express repeatedly
during the legislative session
and it is a hope that is manifested in the current version
of the critical load form for natural gas customers
that there can be a triage of sorts
and so if we can't keep every gas well on
for every oil and gas well on,
what provides the most production
to support the system
and how can we figure out what that is.
Similarly if we can't keep all the pipelines on
what are the pipelines that are actually
feeding the gas plants and can we triage those
and so Collin's got a lot more to talk to you about
on critical load
but I'm concerned that there's an assumption
in much of the discussion that has taken place up to now
that somehow we can take care of the gas guys
and still do everything else we have to do
and it's not that easy.
-: So Liz,
(clears throat)
very good points and very concerning points actually
and SP3 has the grid mapping system
and that's a report that's be due by January 1st 2022
which would hopefully assist us
in more precisely identifying which critic
which natural gas facilities are actually critical
to the electric gas, to the electric generation
and first like I guess process
but in the meantime we're here and the report's not due
till January 1st 2022 so during this this window
through the Summer up until January
we have this potential challenge if we were to have
a extreme event
that required a significant amount of load shed
is there anything that I mean it sounds like
you've the company has worked on the form
to try to triage is there anything within that form
that you provide for registration that could
further maybe triage the amount of natural gas facilities
that are signing up.
-: Well there's an important element here
which is for the TDUS
although not for the municipalities and co-ops
we don't have identities particularly associated
with our customers
so one of the pieces that they do in this form
is tell us what their meter number or easy ID
their essentially account number is,
they're also asked to identify what specific facility
and if they know how that relates to gas-fired generation
not everybody fills out that report completely
if they haven't filled if they've left no breadcrumbs
we'll call and ask and and ask for more information.
So with the railroad Commission's help
because this was actually suggested by one of them
we have the opportunity to have more visibility
what's a big field?
What's a small field?
What's a big well?
What's small well?
We don't necessarily have that for everyone because
there's simply no compulsion for them to complete the form
with that kind of detail and as we move forward in general
load shed that occurs during the Summer months
or the risk of load shed occurring during the Summer months
tends to be of a relatively short duration of an afternoon
and it tends to be significantly less
than we saw in February
and that was by far the most
severe load shed in living memory
and so for the Summer if we played the odds right
and we factored in generally where these facilities are
and generally what we think is gonna happen
the risk is not immediate
but Collin on his second slide said
the first thing we have to do is prevent blackouts
and we will do what we have to to prevent a grid failure.
-: Have along the lines of the natural gas supply chain
are you all aware this may be a question
for a different audience are you all aware of anybody
on the generation side who's taking the initiative
to trace their natural gas supply chain
just as an operational risk management mechanism or effort?
-: I think ERCOT actually asked last Summer
for them to do some work to at least identify their sources
the pipelines and to ask the pipelines to identify
if they were taking maintenance outages
during the Summer.
I don't believe there's any way that either
the wires company or the generators can compel
supply information behind the pipeline.
-: Sure okay thank you.
-: One thing I might add on to what Liz shared
on the gas supply chain,
as those numbers grow and as we get a better visibility of
what those exact facilities are
and where they fit in the supply chain
I know there's a project that'll address this,
I think there's an opportunity to tier
and really prioritize some of that because
if we're gonna have a Summer afternoon load shed
that lasts two or three hours are you really worried
about your production field probably not.
-: Yeah so what when you went from 35 to 750 critical I think
you've said it before if everybody's critical
nobody's critical well is there a minimum threshold
facility must clear before
or I guess is there a hurdle or threshold the natural gas
facility must clear before you put them on that list
or and if so what what is it
and does anyone get turned away?
-: There is not a threshold at this point
but that's something that that needs to be discussed.
-: To the triage all right thank you.
-: Is that something you feel
as we go through our SP3 implementation
on the critical mapping system
obviously that's gonna help us sort of kind of
really specifically identify what's which facilities
which natural gas facilities are critical
for electric generation
but as we look to I guess craft our roles surrounding it
that's something certainly to consider
to help you triage on your registration form.
-: I agree.
-: Okay.
-: And and on that okay so say we get to a point
to where we can start refining that definition of critical
and we can start prioritizing
what and again the law is somewhat broad in terms of
contemplation by the legislature
and even in legislative intent,
what type of regulatory certainty do you need from us
and the railroad Commission to give you comfort
in terms of your ability to manage that plan moving forward
is a memorandum of understanding
MOU between PUC and railroads sufficient
or what do we need to look for there.
-: What we have hoped for for quite some time is
to actually have some mirrored rules
so that the PUC who's directing the generators
and the wires companies and the railroad Commission
who's directing the gas supply chain owners
mapping is the most direct way of doing it
but also thinking about what the hierarchy is
so for instance the railroad Commission is gonna revise its
1973 priorities order on human needs
and on down the chain and it would be helpful for us
frankly for you all to think some more about
what priorities the electric companies should have
again not taking anything away from the severity
of the lack of electricity was to everyone
in wherever they were
but if the more you all have a vision of triage for us
the clearer it will be
when we get into a situation like this.
-: All right thank you.
-: So I think we covered the plan side of this now gonna the
execution side of it
and Dan and Richard covered the communication.
The communication coming from ERCOT
to the transmission operator
then down to the DSP to actually shed that load
some entities that will happen within
the transmission distribution part it will happen within
one location for larger entities for Oncor for example
that communication will come to my transmission control room
and then we will take that and we will break that out
to our two separate halves of our distribution system
and we've got two distribution operation centers
control rooms where they'll take that
and they'll execute that for their half of the system.
When they execute that we're using real-time control systems
so SCADA Supervisory Control and Data Acquisition
that's having direct control of the assets out in the field
on a real-time basis a very secure system
and having that is critical to be able to have
that quick and indefinite response
to be able to maintain reliability.
As far as tools we have tools that can allow us to do this
more or less automatically to where we can plug in
and what's the amount of load shed that we need to have
for this particular region
and that tool will take that and shed the load
and do the rotation based on
predetermined timing and whatnot.
And we also train annually every year
and do simulations on how to do that manually
with just paper and running down through the list
and handling and doing the math
and rotating that load.
SCADA versus manual control and manual means
person getting into a truck driving to the substation
and operating a facility there's obviously major benefits
of having that that remote capability
I mean especially if you get into a situation like February
where you've got ice everywhere and road conditions
and things like that having that remote control
gives you the ability to respond quickly and safely
and not be delayed by people
being dispatched to go do these types of activities.
Load rotation our target is to in a normal load shed event
if there ever is one,
our target is to rotate load within 15 to 30 minute time
increments so nobody would be off for more than
that 30 minute time frame that's our objective.
Obviously during this last February event
there was very limited in supply as far as that supply
and how far you had to stretch it
from a demand standpoint
so that time got stretched out significantly
and then the training I already touched on this
but this is something that that's trained on
and drilled and simulated annually
we have to be good at load shed
to avoid a black start event.
So the difference between critical and exempt
and we've already had a little bit of exchange here
but you know the four types defined in PUC rules
are listed up here
and those those categories get a higher restoration priority
in a storm event or outages though
to the extent there's some sort of planned maintenance
that would require them to be disconnected from the system
they'll get advanced notifications
and they'll also have certain protections
against disconnect for non-pay.
These customers in these categories are not automatically
on our exempt list.
I think Liz mentioned the pervasiveness of these customers
I mean they're it's very diverse they're spread out
across the system
and in fact I pulled the numbers over 90%
of our distribution circuits have some amount
of these customers on them so very diverse
so to be able to have a,
to be able to manage a load shed event
then we have to narrow that scope
and we narrow that scope to the customers
that are listed on the bottom of the screen here
for the ones that are critical to public health,
community welfare, integrity of the grid.
Anything else to add on I was gonna talk about
some of the gas stuff here I think we've covered that.
-: Distributed generation major exporter,
can you drill down what we're talking about there?
-: Yeah so these are distributed generation
resources Oncor currently has
two major distributed generation resources
that actually participate in the ancillary service market
and so they are excluded from load shed.
-: And in order to participate as a distributed generation
resource in the ancillary service market
we and ERCOT have required those DG facilities
to be on dedicated feeders
and to not be on feeders with other customers.
So there's distributed generation across multiple feeders
in our system it's only those ancillary service
provision DG installations that have this protection.
-: So as we see more of that which is a good thing
it sounds like I think for the purposes of grid resiliency
that helps and they're all in their own feeder
so in terms of their portion of the allocation
they're really not impacting us on the allocation side
because their own dedicated feeder.
-: That's correct.
-: Okay.
-: So we're not just to be clear
as we have more DG on the system
and DG that may be participating in ancillary services
or cup market rules open up
to allow that kind of participation,
how does that impact the amount of circuits
we can rotate out during a load shed event
'cause we have a long list already of folks
we got to protect.
-: That's a good question
so for the distributed generation resources
that I'm speaking about it's a relatively narrow
scope so it's the DGR
the resources that are registered as a DGR with ERCOT
and they're providing those ancillary services
and our company philosophy is to
anytime we have one of them hooking up
we're gonna connect them to a separate feeder
that's connected directly to the substation.
There are a recent change to the archive protocols
I believe it was last year that basically requires that
any type of resource or distribution resources
providing ancillary services has to be excluded
from under frequency load shed
and from under voltage load shed.
So that they have to be excluded from those buckets
and then we obviously we're not if it's a resource
we're not gonna shed them during a load shed event
so we require them to be on a separate feed
or not to dilute that pool.
-: The other kinds of distributed generation
say associated with a grocery store.
If that feeder is shed that grocery store
can continue to operate that distributed generation on site
but the fact that there is distributed
generation along that feeder
doesn't change that feeder's priority.
You want me try again?
-: A little bit more.
-: Okay, so there is distributed generation
all across our system
and it's integrated with customers
sometimes it's adjacent to a customer
sometimes it's just an attractive place to put
a DG solar farm
all the ones that are like that that produce energy
either for a customer
or just to put on the system generally during
potentially high price periods
that sails along just fine unless there is a load shed event
if there is a load shed event the fact that a feeder
has distributed generation on it will not keep us
from shedding that feeder.
Now having said that if we have shed a feeder
that has distributed generation on it
and it is co-located with a customer
that customer can use that DG as a source of backup power
so they receive a clear benefit in that event
but the system as a whole is not going to be able to keep
all of the distributed generation on the grid
for grid consumption.
-: But the DG that's AS will not get rotated out.
-: Exactly and frankly we would never want to rotate them out
because they have no load on it so they can't decrease
the load side of the equation that we're talking about.
-: Okay so it's not going to result in further
limiting the amount of customers that can be wrote
or the amount of I guess limiting the load shed.
-: Right so let's say there are 20 of these in 2022 or 2023
we would have on our books it would show
that we have 20 more feeders
and we couldn't shed those 20 more feeders
but not shutting those feeders does not materially change
our ability to manage a load shed event.
-: It's only a net positive.
-: Yes.
-: In terms of the Oncor systems accounting.
-: Yes.
-: Thank you for that clarification it's very helpful.
-: Next slide.
So this slide shows our our February trend
of transmission connected loads.
So each little vertical line
that's a different day in February
and this slide tells a pretty interesting story.
Oncor we do not include transmission connected load
in our load shed plans
and two main reasons there is due to the
highly interconnected nature of the transmission system
so disconnecting certain transmission loads
can impact the topology of your transmission system
which then can cause additional constraints
from an overall grid standpoint.
So going and putting your when the grid's already
at a fragile state going
and putting that that grid in a number of different spots
into a abnormal state is not a good practice
and then a number of these very large customers
they carry significant environmental risks as well
if you disrupt them and just turn them
from 100 down to zero.
This chart it shows a significant voluntary reduction
both ahead of and during the load shed event.
So you can see the the three days
leading up to the blue box there.
So the blue box is a load shed event
there's a significant downtick in the load.
Now whether that was a result of calls for conservation
from from ERCOT, from Oncor,
from outreach directly to customers
or how much of this is due to price responsiveness
or really a combination of both of those two things
it shows that our transmission customers have
they significantly responded
and really shouldn't be subjected to mandatory load shed.
The reduction before the load shed
they reduced by 48% from net level on the days leading up
to the event and then actually during the event
from a couple days ahead to the middle of the event
there was a 60 reduction.
So doing a little bit of math and ERCOT hit
a new Winter peak the Sunday before load shed
it was just south of 70,000 megawatts notionally
and the deepest that we got from a load shed standpoint
was on Monday afternoon and that was 20,000 megawatts.
So if you 20,000 out of 70,000 that's 29%
if you were to spread load shed peanut butter
across every load on the ERCOT system.
The transmission customers covered 48% of that
before the load shed event started
and got down to 60% during the event.
So to me this shows that though those transmission
customers carried a significant amount of water
and they actually ultimately reduced the impact
to other customer classes by dipping deeper
than that 29% that was spread across the system.
-: It is our intention.
-: You fear in curtailing them
or this is a physical constraint
that you cannot turn them off
because they carry such internal infrastructure
that by nature of that setup they cannot be turned off.
-: So either because of their location on the system
and their integration into the transmission system
and or because the facility itself has environmental hazards
associated with it I mean you all remember
there was a plant that lost power.
That we are very concerned with just cutting them off
we don't think that that is a safe step to take
we are continuing conversations with those customers
to try to figure out on a more predictable basis
what they could be capable of
and there's probably room to have
some of those conversations at ERCOT as well
but it's very dependent on what that business is.
-: So the the where my question goes is
some transmission level customers
do not have inside the fence co-located generation capacity
and so their business model is predicated upon
being an off taker from the Texas grid
but during a event like February
or even like you don't need an event like February
I mean in a cold event and we're looking at these thresholds
of as you're ratcheting down load shed
deeper and deeper into the I mean we're shedding
residential consumers all over the place.
What is that that bright line
when we look everybody's off?
Microchips or not, so what's that line?
-: We don't have a line yet across ERCOT
we could try to draw one I guess our first goal was
to try to recognize the individuality
of those business operations.
I will tell you during February
there were industrial customers
that to the extent they had gas
continued to run their cogen
and dialed their behind the fence operations way down
their off takers as you called them
that had a wide range of outcomes from
their customary load to significantly less
and I know of at least one customer that
couldn't get gas for its cogen
but continued to take at full capacity
without regard for the system.
So I mean there's always a bad guy out here somewhere
but there was a wide range of intermediate responses
that we felt were very constructive.
-: So moving forward one of the key questions
is how do we improve rotations?
How do we reduce the customer impact
in a situation like this?
And it really boils down to you need a bigger pool of load
to be able to rotate and there's different ways
that you can accomplish that.
So I got a couple items on the on the slide here
that I'd like to walk through with you
and I've listed them in what I see from my mind
is as rough order from a cost or benefit standpoint
as opposed to just the flat you know physical cost
and the cost in terms of risk to the system
as far as getting the desired outcome
so number one this one anywhere that an entity doesn't have
remote control SCADA capability at a substation
it makes sense to add that avoid relying on
dispatching personnel out to the substation
to do the switching that's number one.
Number two and number three are are tied to
the bucket of under frequency load shed load.
So earlier Dan mentioned I mentioned as well
that floor for under frequency load shed is 25%
of your connected load.
Now given that that's a floor that floor is measured
at the time it's typically a situation
where the system is in a shoulder month
and system loads are relatively low
so you've got higher commercial
or commercial and transmission connected
and lower residential type load.
So as you get to situations where you're at high load events
that UFLS magnitude increases
it doesn't stay at 25%
and actually cycles day to day as well
but it can get up into the range of the 30 to 35
even getting close to 40%
and every entity will be different on how their load
is spread out.
But there are some things that we can do
during a load shed event to dynamically adjust
the amount of load that we have
dedicated to that safety net under frequency load shed.
We can as we get the load shed we can start
moving some of that load or start actually rotating
some of that under frequency load shed capable load
to address the limited pool of resources.
So using up that that margin to the extent you're above 25%
that's something we can look at
and there's actually some discussion
going on in the the ERCOT stakeholder community
on what type of changes or clarifications
to the workout operating guys might be required to
effectuate some of that.
Number three is similar but for Oncor
our under frequency load shed feeders
that we use to meet that threshold that's a static list
it's not something that we can remotely
enable or disable that functionality.
If we were to add devices to the station
and each of those feeders to be able to turn on or off
that load shed capability
and also add that capability to feeders that are on
our manual load shed list
that could facilitate potentially having a dynamic
UFLS bucket if you will.
So that this is not static but we're actually rotating
that UFLS protection around to customers
that are in the manual load shed list.
So that bucket gets it's substantially bigger
you've got a bigger group that you're working with
as you're spreading that that generation constraint
around the loads.
Now that as we go down the list those things
do get more complicated from a control standpoint
and from a load shed standpoint
that's more place that we're having to spend
more systems that you're depending on to keep track
and keep those things running so
we're increasing your risk as we move down this list.
Number four AEP mentioned this one a bit
it's further segmentation of the distribution system.
Identifying where you have some of those exempt loads
the hospitals natural gas facility or whatever it might be
and surgically going in and adding additional automation
or segmentation facilities that could be integrated
into the load shed plans.
Now that from a risk standpoint that it
one thing it does is it blurs the lines
between control systems this is something
that Jeff mentioned earlier
we have our real-time transmission management system
that we use to control feeder breakers in the substation
things that are outside of that fence
that are on down the feeder
on the other side of that hospital
that's a different type of control system.
So there's things that you get into
from a cyber security standpoint from the controls,
how do you manage all that
and how do you make it all meshed together
when we're looking at load shed
those are the the risks and the complications
that have to be addressed.
And then on from an advanced metering
infrastructure standpoint I'm gonna hold off on that
one I've got a slide on the back to talk about it
but just the general concept here is that
making the pool bigger reduces the
it spreads the pain more equally
but in doing that we have to make sure that what we're doing
doesn't diminish reliability
and doesn't diminish the the speed
at which we can execute these actions.
-: Good deal thanks.
-: All right so from an AMI load shed standpoint.
I've talked about our load shed systems
as being real-time systems.
(clears throat)
They're highly reliable highly secure
and controlled within a box.
AMI is I would call it more of a near real-time system
and its primary purpose is to measure energy consumption
provide meter reads and operate remote
disconnect or reconnect for certain premises.
We take that data (clears throat) and integrate that
into our outage management system
to give our operators additional information on the system
and make better operational decisions and restoration.
So some considerations associated with AMI,
number one not all meters have the capability to
remotely disconnect or reconnect a customer.
It's limited right now to single-phase premises
it's primarily residential
and some small very small commercial locations.
Now while that covers about 90% of our meters
that we have on our system
we have 3.8 million meters better than 90% of them
have this remote disconnect capability.
The limitation is that only covers 40% of your load
the the other 10% of the meters represent your
that's your large that's your commercial industrial
as transmission connected that that's bigger stuff
and that represents 60% of the actual load.
So for encore that's 270,000 premises
where to actually use a metering system to
premise by premise with pinpoint accuracy rotate load shed,
those locations you have to you'd have to install insert
some sort of interrupting device at each of those locations
and that's not a it's not a small task.
The meters that are used for small residential
that you have on your house
they're meant for for small loads
if you get to a large commercial or industrial plant
that's much more substantial electrical equipment
so having those devices to be able to interrupt
be able to remotely control that
be able to integrate that with the AMI system
that's a substantial task
and it's 270,000 locations.
The speed of executing load shed
again is of critical importance.
Each entity's meteor infrastructure
would be will be different
from an Oncor standpoint a comparison
that I would make is that
using our transmission management system
or our real-time SCADA system
we could interrupt say 10 distribution feeders
that might serve 15,000 customers
get confirmation of the amount of load
that it was shed and the new status within 10 seconds
that same action to send the command on the AMI system
might take 30 minutes for 15,000 customers.
So the size of the pipe the latency of the pipe
it's not built as a real-time control system
it's built as a metering system
and that's a big, getting that pipe big enough
and reliable enough is a big something significant
to be required to translate that into a real-time control.
Similarly on the the network resiliency
and the control system resiliency
again these are architected for meter reading
they're not architected to have
the high levels of redundancy
and reliability that's required
for a real-time control system.
So in the communications networks,
in the actual control system so it has to be built to
effectuate these changes that's a significant move
from where it's at today to an architecture
that would be able to accommodate those
those millions of commands.
And then the last items or two items.
If we were able to get to the point where
we could reliably shed load
so we get we get the instruction work out to shed
x number of megawatts and we can shed that.
The February event highlighted that
at one time we might have had 1 million customers out
for Oncor more than a million.
If we want to effectively rotate that
that's a million customers that you're rotating
on a regular basis.
So the pipe which gets bigger and bigger
and bigger as you think okay load shed
is one thing but effective rotation
is potentially another item
and then the last item of things that would
have to be overcome is I've struggled
with how we would potentially test a system like that
to ensure that we would have a high level of confidence
that we get the desired result.
You're talking millions of meters out there
and complex control systems
and communication there's always something unknown
that might happen and you need to do thorough testing
to make sure that that it's gonna work correctly
and that's a challenge that would have to work through
and then the last item just thinking through
in our real-time control system
there's you'll have a sporadic communication issue here
or some device might not respond exactly
how you think it would respond
so if you assume you had a 99% success rate
with our real-time control system.
We're having to do something manually
to address that last 1% that means
rolling truck out the field to address that breaker
address those customers whatever it might be
so if that's 1% on a feeder basis
that's I'm sending out a dozen or two trucks
to different locations on the system.
If we have that same 1% miss rate from an AMI standpoint,
1% of 3.8 million meters is 38,000 customers
or truck rolls that we're looking at
having to roll out in address.
So all that being said the purpose of this live was just to
provide some perspective on some of the substantial
infrastructure and architectural changes that are required
to make AMI work in that manner.
-: So Murphy's law still applies.
-: It always applies.
-: All right thanks.
-: I have one question
before we move on to the next panelist.
First of all it sounds very complex and expensive
what the AMI involvement in load shed
but I think it's something we need to continue
to maybe look at to see if there's ways in the future
that we can kind of make that.
Make that work and it might be driven by
the pure size also and and the unique characteristics
of your system too, right?
What I wanted to touch base with you on
specifically with your company Collin
is Oncor's use of voltage reduction
as a tool to reduce load at the distribution feeder level.
Can you talk?
Can you give us a description of how that tool is used
and how it works and when it's used.
-: Sure that's a good question so
voltage reduction is a tool that is used
it's currently in EEA2.
So when ERCOT reaches the EEA II level
they'll request TSPs to implement voltage reduction measures
there was actually a voltage reduction
task force with ERCOT that concluded their work back
in 2015 I'll get you some of their findings there but
the premise of voltage reduction is the
power is the product of the voltage and current
so if you can while maintaining the appropriate pan
with the voltage if you can squeeze that voltage down
you can reduce the amount of power being
consumed on the distribution system.
The task force found that a demand response
that could be expected in what we've actually experienced
on the Oncor system could be between one to 2%
of overall demand based on the number of stations that have
the capability to regulate voltage.
Not all not all transformers
have the capability to change taps
and control voltage in this manner.
At Oncor we have at about one-third of our eligible
stations where we have that capability
we have this remote control set up where
at the push of a button when ERCOT calls
for EEA2 voltage reduction we implement that
and in previous events we've seen
upwards of 100 to 120 megawatts of demand
or not demand response would
demand reduction as a result of
voltage reduction activities.
So that's the kind of the easy button side of it
and as we add stations rebuild stations
that's something that we've integrated
into our standard design that capability to do that
for the other two-thirds of our system
when we do get that call from ERCOT
we hit that button and then we also call
all of our regional operations folks
and they go out and they start actually
manually changing those voltages out in the field
obviously much slower but it still gives you some benefit.
-: And so this tool is used during the time
that ERCOT is an emergency procedure
so it's not a tool to avoid emergency procedures
it's a tool that when you're in emergency procedures EEA2
that it would help I guess lower the amount of
load that's being reduced it's a lesser.
-: So for an IOU the only time that we use it
is in emergency and when it's ordered by ERCOT in EA2.
-: Has it, have the stakeholders has ERCOT
or the stakeholders and or the stakeholders
evaluated whether that tool could be used earlier
in the emergency procedures process like maybe EA1.
-: I'm not sure that's been discussed recently
but I do think that is something
that's worth talking about particularly given that it
for the vast majority of those type of benefits it requires
folks to roll trucks and go out and make those changes
so there is a significant time lag associated with it.
-: I think you described there's like specific equipment
you can add into the design of the stations
and that's something Oncor
and it's on its own has decided to look at
and I think that's an interesting tool
and I'd be interested in learning as we move on to
the other panelists.
If that is a tool that the other companies are using
and if they're not why not and what would it take
to allow for this transmission,
I'm sorry voltage reduction told to be used
in the other TDU service territories so that we can
potentially garner the benefits of getting back megawatts
during load shed procedures.
So thank you, appreciate it.
-: All right thank you Oncor.
Next up I think we've got CenterPoint.
-: Yes thank you very much.
So significant portion of what Collin covered
is true also for CenterPoint
I think it probably is for other TSPs as well.
So I'm gonna highlight just a few of the other points
related to starting with the industrial customers.
So in terms of the industrial customers
obviously that's gonna the percentage
of the load that is industrial customer
will vary for each utility.
However that load reduction or that load amount
is considered in the allocation of load
when we start to calculate obligations that
were on the table that Dan showed us earlier
and so those industrial customers load is concentrated
into one footprint but when they do reduce load
it benefits obviously ERCOT wide.
CenterPoint saw similar behavior
from our industrial customers
during the February event reductions of 60 plus percent
in the industrial load
and so we also would not advocate for the utilities
to be shedding that load for the same reasons
there's the health and safety of the public,
the operations of those facilities
and so we think that right now
that process worked in terms of reducing the load
and providing a benefit to ERCOT as a whole.
But however the the the load differential
as those loads do reduce.
It reduces the amount of load in each utility's footprint
and but the allocation from the shed obligation
stays constant so that allocation for the load shed
obligation is a Summer number
and it's a one-time value.
As the industrial load changes in the footprint
that could be as a percentage due to the season
so during the Winter the industrial load may be a higher
percentage of the total load
versus the Summer as you have more air conditioning load
that differential if you are into a load shed event
is then spread to the residential customers
and so today there's no way to really account for that
change in the industrial load whether it's seasonal
or based on the specifics of the event
and then also there's no way to account
for the fact that now the reduced load in the footprint
is being shed at the residential level
and so that's something that puts a
depending on the allocation of industrial load,
puts additional load shed requirements
on the remaining residential load
to still maintain an arrest system frequency decay.
So that's just one of the things that we wanted to highlight
in terms of how the changing of the industrial load
allocation during an event or prior to an event
impacts each utility differently.
So here on the on the next slide
it's somewhat of a related topic in terms of
how the allocations can change either seasonally
or during an event so what this graph on the right
at the top is depicting is based on ERCOT
weather zone data so we pulled some data
from the ERCOT website
which doesn't give us the resolution of
each individual utility,
however we can see the different weather
zones that are listed there on the bottom so you can see
Coast and East and Central and so forth.
So the allocations as you can see from the plot are changing
throughout the entire year but as we just discussed
the number that we are obligated to shed is a fixed amount
based on the Summer.
So there's been some discussion on this topic
however we feel like there needs to be more study
to determine what is the actual bandwidth
that we are experiencing in terms of load
throughout the year or throughout a particular season
'cause you can at several points here
you can see the Winter event is depicted
where you see these spikes in kind of that first quarter
from the left you can see where there was differences
in the way that allocations were changing
but then also as we moved later in the year
the plots are also showing that same behavior
just at a much lower scale.
So the regional allocations can also impact the ability
to shed load and to rotate load.
So as you have more allocation than you have available load
it becomes more and more difficult to rotate the load
because you're shedding a larger percentage
of your remaining share.
An extreme example of this would be a hurricane
scenario during hurricane Ike
the CenterPoint footprint we were roughly 5%
of the ERCOT total system load just
because we had so many feeder lockouts.
So one of our concerns there is that if ERCOT called,
if for some reason we had to do a load shed
during such an extreme event
the expectation would be for CenterPoint to shed
25% of our load
but if we were already only 5% of the ERCOT load
it may not be effective in arresting a frequency decay
which then could continue to have to
shed either additional load
or if we don't shed the load fast enough
it could pose a greater risk to system stability
and so then in that case we'd be on the fly trying to
determine how to reproportion those allocations
or the work needs to be done to determine
how to do that in advance so again another area
where we would like to see some study conducted
to understand in these extreme events
or as the seasons change are there things
that we should be doing differently
in the way that we're allocating the load
and then also to Collins point around the maximum
we have a minimum number in terms of the 5,
10 and 10 or the 25% that we need to have available
for under frequency.
But as these values change also those allocations
of under frequency are changing as well
talk about that a little bit on the next slide.
So on this slide you can you can see some of the main groups
in this top right chart
where your exempt feeders are basically staying the same
they're static number and they're maintained.
The manual load which is the load that we would
initially start to shed is obviously decreasing
because we're reducing that amount of load.
The industrial load is also decreasing as we saw
from the chart that Collin provided
but in total what that means is that
the amount that's left in the under frequency relaying
is increasing because you're shedding the rest of the load
and as that does it leads to this bottom graph where
the red section of this chart really depicts
the efforts that were taking place
at all the control centers in the ERCOT footprint
we were all manually shedding load either
by entering it into a load program
or doing it through more manual means
to produce that recovery of the frequency
that you see in the red portion of the plot.
One of the concerns is that if this under frequency
value gets too high and then we shed a tremendous amount
of load all at once relative to the total amount of load
it could potentially result in power system instability
so the frequency would go too high in that case
and if it went too high then the units
the generators that we were concerned about staying on
could then trip offline
and if enough of that happens in rapid succession
then that instability
could again lead to a system-wide blackout.
So one of the things that we believe needs to be studied
is how should we proportion that under frequency load
for such a long duration event as Oncor mentioned
our typical Summer event
or the Summer event we experienced in 2011
was seven and a half hours long
whereas this was 70 and a half hours
and so with those extremely long duration events
the ability to continue to maintain proper under frequency
relay allocation could become a critical piece
of sustaining grid stability
and so that's something that ERCOT we need their support
in understanding and doing the studies
as to should we not only have a minimum
but should we also have a maximum
amount of under frequency
which also if we start to implement those types of processes
will give us additional load that we can rotate
because today we don't have clear direction on
whether we should or should not rotate
that under frequency load.
-: But again that's sets a maximum of the tranches
that you are ordered to shed at any given time right?
So basically for your operational purposes
you want a more incremental approach
even if it's in a short like a machine gun bam bam bam
sequence but you don't want big bulk
orders coming down on you because especially
you've got so much that cannot be turned off
it's transmission level.
-: That's correct.
-: So question on the transmission level
again we're learning and I think the problem
in the near term may be more acute
because we now have this critical infrastructure
equation that we've got to get right for your purposes.
what's the the status of discussion or has it been discussed
you're different from West Texas
you're different from North Texas
you have a huge industrial footprint
along the Houston Ship channel
you've got a lot of critical load right there
already transmission level which you cannot cut off
but we're seeing that they voluntarily turn themselves off
they reduce load,
so is there any proportionality between
again there's this is kind of a Dan thing too
but your customers are voluntarily going into an event
shedding load or they're turning themselves off
they're reducing right load
and but you're still asked to shed however many megawatts
because that's your allocation on the ERCOT system.
-: Correct.
-: Is there any discussion on proportional
as your load reduces not having that allocation
or pegging that allocation to the voluntary reduction load
is there any conversation around that?
-: There is and that's what we're looking forward
to studying with ERCOT is understanding
what is the mechanism in which we could accomplish that?
And so the there's two things that happened
during the Winter storm you had the industrial load
that was reducing but then there was also
and you see it in the in the weather zone data
a temperature gradient also that we were experiencing.
So on the coast the megawatts per customer
was at a slightly different rate than maybe
extreme cold in the North more northern parts of the state.
So we need a way in our opinion to normalize that load shed
kind of like what you're saying
but then also there will be times where maybe there's
extreme heat in the Houston area
and so the gradient has swung the other way
and that's what we see in the preliminary data
is that there it is not a unidirectional shift
it varies based on the weather
and whatever events are taking place
and so to account for the variation first
to understand how large is the variation
and can we what is the most simplistic way
to make it equitable.
But then once we understand what the variation is
I think then we can design something that will
allow us to shed load in the most efficient manner.
Because the other thing that we have to touch on
from a technical standpoint is the more efficient
the load shed the faster we get the load off of the system
and the quicker we can arrest the frequency decay.
So if you're having to shed I make a number up
20% more customers to get the same number of megawatts
because it's in a less low dense area
it's gonna take longer to get that load off the system
and one thing that we learned from the Winter storm
is speed is of the essence
and I think that was why ERCOT sent that RFQ out
and we try to provide the information
as to how quickly we can reduce that load
because we do need to be doing it
in the most efficient manners possible.
-: How many natural gas facilities do you have?
Natural gas facilities do you have registered
as critical load.
-: We have 18 so we don't have near the challenges of others.
During the Winter storm we did have two that called in
that were not previously registered
but we don't have near the challenges of West Texas.
-: So your natural gas related facilities
are more downstream assets.
-: Yeah that we assume so obviously we don't
have that level of detail.
So we have been participating in the
gas electric working group through ERCOT
where we are able to coordinate with some of the folks
in our footprint and then naturally after the Winter storm
we had six additional folks that contacted us
through the process.
But we don't have a lot of insight into
what their facilities are providing.
-: Okay but you before the storm you it sounds like
you had 10.
-: Yes.
-: Natural gas facilities registered
as critical infrastructure now you've got 18.
-: Correct.
-: So even though it's not the numbers of the West Texas.
-: That's ratio yes it's still right that's a yes.
-: 80% increase in registration.
-: Correct.
-: But I wonder how how big is that load
were those eight that came on are they really big loads.
-: I don't have the specifics yeah.
-: So that's interesting.
Such a stark significant difference between Oncor
service territory that obviously covers the oil patch
and Permian Basin and elsewhere
and I guess Delaware as well and versus
CenterPoint service territory that's heavily industrial
so your challenges are more with the
I guess the challenges in load shed
are more focused on the industrial loads that are exempt
from load shed procedures.
-: Yes lets me say that really is our biggest challenge.
-: So I should have added one thing earlier
and that is there's been some discussion about
how do you manage the critical loads in the Eagle Ford
the way that the current process this natural gas
critical form is structured it has to be turned into
the wires company that serves whatever that thing is
it's a compressor station it might be
San Bernard electric co-op or if it's a midstream processing
it might be TNMP but that's how
we try to avoid duplication.
-: Yeah and it's a fair point the load size
on CenterPoint area is probably large natural gas assets
with big loads but once you get past the midstream point
they're less relevant to the generation supply chain.
So another element of balance.
-: And if I could ask does CenterPoint have
a voltage reduction tool at this time.
-: So we don't have a tool we have a plan.
So we implement CVR on a manual basis
the days where conservation voltage reduction are
most likely to be called on are usually
gonna be days where we can see that event
it's a slow progressing event.
It's not like the under frequency relay event that happens
out of the blue sky.
So on those days what we will typically do
is we will dispatch our crews to the substations
so they're pre-positioned in the case that
we need to reduce the voltage on the distribution system
but this is also another difference that's gonna occur
from system to system and so I think that's probably
gonna be a reoccurring theme is that it depends
based on the system.
It largely depends on the load characteristics of the
customers that are connected to your feeders as to how well
voltage reduction is gonna work
and mainly that's because as you reduce the voltage
the work that needs to be done is still the same.
So in terms of air conditioning what we found on studies
we performed some studies on our system
and so we would get an initial reduction in demand,
however because of the loss of diversity
so the diversity is how many AC units
are running simultaneously,
so as you as you reduce the the voltage
it typically the air conditioner then runs longer
and so where you may have five on at a time
out of 100 that number continually increases
as the units run longer and they start to overlap each other
so after about 35 to 40 minutes we would actually see
the load start to increase again to the levels that it was
prior to when we did the voltage reduction.
So the voltage reduction effect is not sustained
depending on the type of load
but if you have resistive heating where it's more
constant power then you can get a more sustained effect
so it depends on the time of year,
it depends on the type of load
and so for those reasons we haven't implemented
a automated process of doing voltage reduction
but we do have predetermined feeders that we study each year
and our distribution planning our engineering folks
will study those feeders tell us where we can pre-position
our substation resources
where they will be most effective on our system.
-: So the voltage reduction practices
that you're currently conducting
are just sort of voluntary actions
that you take they're not
baked into the emergency procedures process.
-: No similar to Oncor it would be during the EA2.
-: Okay thank you. -: Yeah.
-: All right thank you CenterPoint
next up is TNMP.
-: Thank you chairman Commissioners.
Oncor and CenterPoint provided
some really great information this morning.
Keith and I would like to drill down a little bit
to discuss how load shed it affect
a small electric utility TNMP.
TNMP does not serve large cities like Houston
Fort Worth or Dallas what we do serve is
suburbs of some of those areas and rural towns in Texas.
But we do serve some very important load
specifically along with Oncor and AEP
we do serve natural gas and petroleum out in West Texas
and like CenterPoint we serve refineries
and petrochemicals in the Texas city area.
What I show, what we show here is the
TNMP's 4CP at ERCOT times
and obviously you should as you can see
that ranges anywhere from about a little
over 1800 megawatts to 2000 megawatts
with an average of roughly 1900 megawatts.
Embedded in this 1900 megawatts is 550 megawatts
of transmission load
and is what we've heard today already is
that 550 megawatts of transmission load
is not something we consider in the load shed event.
But once again that 550 megawatts
is included when we get our load shed amount ratio.
As I show on this slide as well our we
actually had a peak demand on February 14th of
at roughly 6:30 p.m of a little over 1700 megawatts.
On February 15th around right after midnight
that had dropped down to 1647 megawatts.
We could see that some of the transmission customers were
curtailing either on their own
or participating in the emergency response at ERCOT
but what this shows is that
on the beginning of the morning of February 15th
our load was already down 13%
of what was calculated for our load ratio shed
that we were gonna have to start load shedding.
I'm gonna let Keith address some of the specific challenges
that he saw and from his operations group.
-: Good morning one of the things one of the benefits I guess
is going after my colleagues is that I can point straight
to him and say pretty much what they said happened but
in a sense I'd like to cover it a little bit about
what our load service territory challenges are
is that in availability of SCADA
in all of our substations as you can see by the
the numerous little pockets and smaller areas that we serve
is very dependent upon communications infrastructure.
In my opinion from my experience
we do a pretty decent job of this already
we only have about 11% of our feeders that are not on SCADA
however the downside of that is that going out
and putting them is that as the gentleman from AEP said
is that putting it out there's very limited load available
even in these rural areas to hit that.
So impact emergency and response service participants
is that during the event as Stacy said we saw
loads dropping on the transmission system.
Some of those customers were participating in ERS
some of the other transmission customers
they may have been curtailing on their own
from the voluntary
they may have been experiencing conditions on their own
equipment that necessitated that.
I know at least one case we had a large facility that had
Cogen right next door that was typically a large exporter
onto the system and suddenly that flipped
and was actually taking off of the system
so I think Liz covered that earlier is
that we saw that in there as well.
The under frequency load shed we've discussed pretty
intensively around that we have to set
that certain block away that's that external to anything
that we put in a manual load shed program
so there's a large block of the load that we had
that was not available for rotation
and what this meant is that what you heard earlier is that
very early on in the event because of our size
and the scale of the event we had implemented
our automatic load shedding program
and pretty much hit the maximum to where
no rotation was happening.
So for those of you who have been around a long time
you probably understand when Y2K was out there
and all of the things that happened with Y2K
and all the bad things we were told happening
I kind of characterized this event as Y2K
with a social media kicker
because as things happened in various areas
as we started rotating outages
and then as we started not having rotating outages
the communications got out there that
hey things are happening lights aren't coming back on
what's going on.
We were very privy to that
and we started trying to get very inventive
on what can we do to implement rotations.
We talked a little bit about actually going
and switching out under frequency feeders
by changing relay settings
and making a feeder that wasn't available for rotation
because it was on an under frequency list
available for rotation in the meantime
going and enabling a feeder that was rotated
and making that part of our under frequency block
so we could keep that hole.
So that was a learning experience for me
to say well maybe we should be putting
under frequency remote capability into our substation
so we can switch that on the fly
and as Collin mentioned that's a big coordination problem
because your under frequency requirement
is constantly changing.
So that's something that we need to study
as far as the number of gas customers
that we had in our system as you can see
we serve a big portion of the Permian as well
before the event we had about two customers registered
we ended up just recently we're at about 177
so we saw an exponential increase in that as well.
So I think the challenge with gas customers
as everyone knows is that assigning criticality
is probably gonna be one of the biggest things
that I think we can get help for
is that I've traditionally been in
historically I've had some experience in gas contracts
and when we're dealing at least in TNMP's case
we're getting notifications from the operators on site
that hey my facility is critical
but in reality when you're putting in a gas contract
you're not going and saying individual whales
are putting into the whole entire pipe
and this well is critical this was critical
it's usually a package of a volume of gas.
So we're trying to get explanations from the operators
a little bit more we're trying to dive down
into it a little bit more and saying well
tell me how this is critical
do you have a contract for it
where is it going ex cetera.
The experience that I've had is that I've reviewed
some of the easy IDs that have come in
and just from you know being nosy
and Google earthing on my look
and I say wow well that doesn't look very critical to me
because it looks like a series of trailers.
So you go well that's your are you telling me that
the place where you're keeping your workers is critical
to your outfit yes or no so that's kind of
that's a little different
it's different in the semantics I guess.
So that's one of the things
that we're really working through.
With that as we're kind of a hybrid between
CenterPoint and Oncor service territory albeit
on a smaller scale is that
we have a large impact of commercial customers down
in the Texas city area,
our experience during that was is that as they were
either reducing load or not reducing load
but their suppliers were reducing load
which caused their plants to start reducing
we were getting phone calls
are you reducing these guys
are you curtailing them when in fact
there was no director from TNMP to do.
So it's a very dynamic situation on the flip side
in West Texas you know we were still
seeing a lot of the gas facilities that were
trying to stay up but either couldn't
we were not necessarily rotating a large volume of them
but we were a smaller footprint so
that's kind of our experience with that
and with that I'll take any questions or Stacey.
-: How many natural gas facilities do you currently
have registered as critical load.
-: 177, it was two prior to the event.
-: And they were transmission rates.
-: Yeah the two that we had were transmission.
-: So they wouldn't have been rotated anyway.
-: Right.
-: Their transmission level customers?
-: Right.
-: Got you, the any sense of same question
are there any sense of what type of natural gas facility
is now on that list of 171.
-: It varies we have large compressor stations
we've had individual well customers
this is off the easy ID level what I'm talking about.
We've seen individual facilities,
we've seen individual fields
all the way up to large compression those kinds of things,
it's all over the all of them the gamut.
-: Okay interesting.
-: Do you utilize voltage reduction.
-: Yeah much the same as CenterPoint is
that it's more of a manual situation for us
we don't have, our transmission stops at about 138KV
so we will dispatch it's primarily in the Gulf Coast
that we have distribution load that's available
for voltage reduction that's done under EA2 as well.
-: Is there any and I guess maybe this is
just general question across the board it sounds like
depending on your service territory
the unique characteristics on of your service territories
voltage reduction means different things for each company
is there anything that we as a PUC and or ERCOT
can do to drive more of that,
more use of voltage reduction
and to drive that investment or incent those actions.
-: In the TNMP case we're participating in the studies
and we would be incented just by
what the results of the study say for the benefit
of the system.
So we're relatively small players
so our loads you know the one to 2% would not necessarily be
a large significant benefit but we would
definitely participate as we go.
-: It's just as you sort of look across the broad spectrum
of all the TDUs in the ERCOT region that potentially
there could be additional benefits that we can gain
through voltage reduction by either moving it up
in the emergency procedure process
so that maybe we don't get to you know
help mitigate the risk of gonna EA2
and also to reduce the amount of load shed
if it stays in EA I guess well I guess EA3 is load shed
but I guess there there seems to be like
more benefits we can garner from this tool
so that's what I'm kind of just trying
to evaluate right now.
-: I think for CenterPoint we probably see more advantages
in the load management space
than the voltage reduction space so we were
very encouraged by some of the recent
changes to allow us to do more
in that load management area
because the net effect and the long-term effect
of the load management is more significant
than the voltage reduction piece
and so I would say if we were gonna focus
we would probably focus more of our attention to
how expediently we can get the load management programs
up and going because I think they're
gonna be a bigger impact.
-: That's a really good point Eric
and it's not clear from Senate Bill 3 whether
the additional load management programs
are intended to be a part of our energy efficiency portfolio
or separate from
and on the one hand it doesn't specifically call out
a Commission rulemaking on this issue
on the other hand at least some initial clarity
particularly around interim adoption of the programs
would be really beneficial.
-: I agree.
-: Within the load management universe
what are the top two or three things that you'd say
we need to be focused on or implementing.
-: Well historically there's been some tension
on having the energy efficiency load management programs
relative to some of the ERCOT load management programs
like ERS one of the things that was done
after 2011 to try to reconcile that is that
all of the TDU load management programs are called by ERCOT
so we will implement at ERCOT's instruction
another piece is it's something as basic as
the way the math is set up around energy efficiency
and demonstrating energy efficiency savings
the off-peak load management programs
which is what we're talking about now
outside of the four Summer months
it's not clear how that plugs into our
overall performance under our goals
and so they're I mean these sound like details
and there is no program the Commission oversees
that is more detailed than energy efficiency
but they're important and it makes a difference in
how we go about implementation.
-: Yeah I think that the load management programs
are gonna have similar effects as the other things
we described in terms of load ratio share.
So as you have certain footprints
that are more successful in implementing
load management programs
I think there needs to be consideration
in how that changes their load shed obligation
such that it is equitable
and it bakes in these other factors
that we know change in throughout the event as it evolves.
-: Gotcha thank, you good?
-: I'm good thank you.
-: Just a question on that because
I don't know Dan if you want to hop in on this
or stay masked over there
'cause I can't see your facial expression
but what's the downside for ERCOT
is what we're talking about in terms of
adjusting real time that load ratio share
in proportion to transmission level voluntary curtailment
is that too complicated to do instantaneously
at a moment's notice to keep the lights on or
I mean it seems like that would be
in the history of the state of Texas
and managing our grid that would have been
considered before now
especially we are a heavy industrial state
I mean that's our claim to fame we're becoming more so.
So operationally what's the downside?
-: So I'm gonna spring to ERCOT's defense
before they speak for themselves.
Load shed events have historically been so rare
that the kind of rough justice that we employ
under the existing protocols.
-: That's a good way to put it.
-: Was sufficient I think what we've learned is
it's not always and I'll give you my chair.
-: Yeah I think that Liz is probably right
there hasn't been enough of these that we've
explored some of the things especially
that Eric was talking about but I think Oncor
had a bullet point on their slide that is very accurate
which is when we do need to shed load
it has to be done very quickly
and so anything that adds to the confusion
or the complexity of it is got to be balanced
with that ability to shed quickly and so in the past
because these happen so infrequently
there hasn't been a lot of maybe effort put into identifying
the amount of allocation due to transmission
and those kind of things.
If we can do those things in advance such that they
don't cause confusion and complexity
of getting the load shed when we actually need it
in order to preserve the system
then I think we're all for working with them to do that.
-: Okay thank you.
-: All right thank you panelists appreciate it.
I think that gets us to our fourth topic
but given the time of day
do y'all wanna recess for lunch now?
-: Your call sir.
-: It's your call I'm good either way.
-: I think you wanted more guidance I think
you wanted to vote on that.
-: Yeah everybody wants guidance.
-: Sure you want to take.
-: Yeah let's go take 45 minutes,
all right we'll recess for lunch now
be back at say 12:40.
Meeting of the Public Utility Commission of Texas is now
back in session for the final portion
of our work session today,
fourth topic covering Rio Grande Valley transmission.
We'll hear from a panel including ERCOT, AEP
and Sharyland utilities.
Thank you gentlemen for being here.
Start with you Mr. Lasher.
-: Sure.
-: Take it away.
-: Thank you for the record Warren Lasher
with the Electric Reliability Council of Texas.
Good afternoon Commissioners it's a pleasure to be here.
I've got a couple slides I brought some slides
kind of looking at transmission planning in general.
I thought we could go through those
and then Wayman here I think has some much more
detailed slides to probe down into the
Lower Rio Grande Valley Area.
So I think I'll turn it over to him
when I've kind of got through my general slides
and then we can Wayman and Michael can speak
and then if possible I'd like to kind of come back
to my last slide at the end of that
kind of to round out the conversation about the
Lower Rio Grande Valley Area if that's acceptable.
So just background here the transmission system in ERCOT
I've got a map of it here.
Basically what the transmission system does is it moves
just a massive amount of power from 700 plus
generating units to every consumer in the ERCOT region
which covers about 75% of the state of Texas
and so just if you think
about the massive amount of energy that is
moving around the grid at any given time
and it's imperative on ERCOT to operate this system
within the limits of the system.
So every single last element of of the transmission system
has some maximum amount of power that can flow
through that device without that device being damaged.
As over time as people move to the state
as new businesses get started the customer demand in regions
can increase and as a result of that
we can run into situations where we come to the point where
we're starting to get close to exceeding
the capacity of some of the transmission in that area.
So there can be a need to increase the capacity
of the transmission system because of population growth,
economic growth throughout the state
at the same time we have new power plants
that are being built on a daily basis
and we have some of our older less efficient plants
very older plants that get retired
and so kind of where the power comes from changes over time
and again that changes the need for transmission
so in essence we have to move the power
from different locations to all of this
growing customer demand.
So those are kind of the two drivers that we have
that really force us to do transmission planning
to predict in advance where new transmission
is going to be needed
and to make sure that that transmission is in place
in advance of need
and so ERCOT works directly with the transmission companies
the transmission service providers
we also work with a stakeholder committee called the
Regional Planning Group in order to study the needs
on the system
and to evaluate specific projects to meet those needs
so that's kind of the overview of transmission planning.
So next slide, so kind of the way I broke it out before
we've got customer demand growing in some regions
and we've got generation that is being built
that kind of leads us to two different types of projects
that we have on the system
we call them reliability projects and economic projects.
Reliability projects are projects that are needed
in order to reliably serve customers
and there are a set of North American
Electric Reliability Corporation standards NERC standards.
There's also a set of additional standards
associated with what level of reliability
is required for customers that are in the ERCOT protocols
and the ERCOT planning guides.
Once a project is determined to be needed once our analysis
working with the transmission service providers
once our analysis shows that a project is needed
to meet these reliability criteria
we judge any project to allow us to meet
that reliability criteria based on the effectiveness
of the project and the cost of the project
but we don't not do the project because it's too expensive
meaning we look we compare projects based on cost
but we don't say yes or no based on cost.
So from a reliability perspective cost is a comparison
but it's not something that
we would say yes or no on a project
does that make sense?
-: Yeah it's a factor in prioritization not determination of
course you're not built.
-: Right so we actually we do a determination of need first
and once there's a determination of need
and we say yeah there's a need
we're going to build a project
it's just a matter of which project.
Economic projects on the other hand
are primarily designed to allow more efficient generation
to have greater access to the market
and for this there really is a cost-benefit analysis
we look at the current economic criteria
that is actually in substantive rule
and we evaluate the savings in the overall cost
to operate the system the variable cost, the fuel cost
to operate the system and compare those costs
to the annual carrying cost
of the transmission asset itself.
Now obviously that rule in 25 101 has been modified by
Senate Bill 1281 and I believe Michael is gonna hit on that
in his topic
so we can kind of leave that topic of conversation
for when he has his slides, if that's okay?
-: Sure.
-: Okay so it's important to note that both of these
situations kind of reliability projects, economic projects
they're both driven off the fact that
there's insufficient transmission
but because of the fact that we have alternatives
in real time operation for redispatching the fleet
to control congestion for economic projects
we don't have to do those projects
and we only do those projects if they meet
specific economic criteria.
Does that make sense?
Okay, next slide.
It's important to note that the process
of building transmission takes a long time,
it takes about six years
it can take more than six years
we're gonna start talking about that
with the Lower Rio Grande Valley area
it's one of the areas
where it can actually take longer than six years
from the point at which there's analysis
that indicates that there could be a need
to the point at which we're actually closing a breaker
and we've got new circuits in place.
This kind of runs through the whole set of activities
you've got the kind of the initial proposal
ERCOT has an independent project review
it's important to note that takes about six months
out of this six year period engineering and routing
and then you've got the the typically a one-year
hearing here for a CCN analysis
and then the actual construction of the project
and we have a our typical planning horizon is six years
because of this requirement that it takes about six years
to bring a project online.
Okay, next slide.
So just kind of running around the system here
we've got across the system we've got a set of different
challenges right now
and they some are reliability, some are economic,
some are a little bit of both
if you look all the way over on the left the Delaware basin
we've got growing customer demand associated with oil
and gas so keeping up with that is a challenge
I'll talk a little bit more about that at the very very end
on my last slide but just the idea that we can have
10, 15, 50, 100 megawatts just pop up in different areas
both because of oil extraction
but then also midstream processing ex cetera.
Keeping up with that is difficult
their planning horizon is about 18 months
for the most part of building new facilities
and again our transmission planning horizon
is around six years.
So that's one of the key issues there.
Swinging over to Dallas we've got growing customer demand
many parts of Dallas are growing at a very fast pace
at the same time Dallas kind of stands in the way of
all of that wind generation
that brand new wind generation out in west Texas
and all the way up in the panhandle
trying to move across the system
and get customers some of that power
wants to go all the way down to Houston.
So kind of Dallas is almost a waste station
for some of that energy that's flowing onto the system.
Houston growing customer demand.
I don't need to really say much more about
that obviously a need for reliability projects
over time the last project came online in 2018
I believe and so that's a large customer demand center.
The valley we'll be talking more about the valley
interesting part about the valley is that it is both
a export constrained when the wind is blowing
at a fast clip that power moving out of the region
and it's also import constrained when the wind is low
because of the growing customer demand down there
so it's both an import and an export constraint
and then you've got kind of in the center of the system
you've got that West Texas export
that's kind of a limitation on moving power
from the West where we've got a lot of wind
and a growing amount of solar
to customers on the East side of the system
it's just it's basically we have right now
an interface which cuts the system in two
and limits power flow from left to right.
So these are just some of the challenges
that we're facing right now
and you can kind of see how they're split up by reliability
and economics, any questions about that?
-: So Warren and and I'll ask this of both yourself
and AEP's analyst but why is the valley different?
Why does it take longer?
-: Well Wayman has quite a few slides on that
about why does it take longer
I'll leave that for Wayman yeah,
why does it take longer.
-: Okay, so ERCOT has no official view on why
the the process is taking longer for RGV.
-: I mean I would just say there are
it's just much more difficult to bring a CCN case
because of property ownership and issues like that.
-: Okay it's the property ownership side of the equation.
-: I mean that's part of it
but I would imagine there are other issues as well.
-: Okay I'll wait then.
-: So Warren that's interesting because
in the last several years
within the last 10 years ERCOT has approved
and PUC has issued out CCNs for
significant amount of transmission into the valley
the cross valley import transmission lines
and but yet we still continue to have
issues down there why?
-: For I would argue for two reasons
first of all because we have I started off my whole
slide deck saying we've got specific standards
the North American Electric Reliability Corporation
Standards and the protocols the ERCOT protocols ex cetera
and to some extent I said that
they allow us to find a need
and to find a project to meet that need regardless of cost
so that sounds like it's expansive but at the same time
to some extent those protocols and criteria limit us
because if we see something that doesn't meet
one of those specific criteria
it's much harder for us to point at that
and say this is something that we need to address.
Because those protocols are the things that
allow us to define what a reliability need
on the transmission system is
and to some extent the valley I apologize
to some extent the valley is a situation where
it is so distant from the system
and there are so few options there
there just are not that many generation units
to provide for some of that reliability
services that we need
that I think the valley requires a little bit of a
more expansive reliability set of considerations.
Now interestingly
and this is what I'll get to at the very end
it's not that different
from what we found in the Delaware Basin,
dealing with the Delaware basin
and trying to keep up with that
and so I think we may have learned something there
which we'll talk about when we get done.
The other thing I wanted to say is
two things that I think have driven some of
the issues down in the valley the first is,
we've been surprised by some of the load growth there
my recollection is that when the February 2011
event happened the actual customer demand
that occurred in February 2011
Wayman's gonna correct me here because
I may be wrong about this but that's
okay the actual customer demand was
greater than what we had in our planning models.
-: Yeah for sure.
-: Oh there you go okay well.
-: Yeah doubt.
-: Okay and the second thing is not long after
that Frontera decided that they wanted to retire from
ERCOT and moved to Mexico so that was a completely
unexpected event we lost one of our combined cycle
facilities down in the valley which again significantly
limited some of the reliability issues
so there have been other issues as well.
-: Okay yeah that's interesting
I guess it's irrespective of those large 345KV
transmission projects that were built into the valley
load growth continues to increase down there
that requires more generation to be brought in
or more transmission to be built
and a lot of the generation resources down,
the primary generation resources down in the valley
are it sounds like Gulf Coast wind or wind.
-: There is wind, gas and solar in the queue.
-: But maybe like one or two gas plants
I think I saw one.
-: There's more than two there's two combined cycles
South Texas electric co-op has a set of peaking units
Brownsville I believe has some generation
along the coast as well.
We also have DC tie.
-: They've got a coal plant down there
Brownsville don't they?
-: A coal plant I don't believe there's a coal plant down
I think there's an old gas plan, older gas plant yeah.
So I do apologize but he's got some really good slides
so let me turn it over to Wayman at this point
and he can go through some of his slides
and then we can come back to my
yeah keep going a few more, one more there you go okay
and then we can come back to my last slide one.
-: Yep thank you Warren.
-: Please.
-: Good afternoon Commissioners I'm truly appreciative
of the opportunity to be here
and talk to you about the Rio Grande Valley.
I can tell you that that I first started
working on issues in the valley in the mid to late 90s
so that says a couple of things one I'm no spring chicken
and two what is it that's unique about the valley
that it's still a focus as we sit here today 25 years later
so I really wanna and I think I'll address
some of the specific questions that have been asked already
but and I'll be honest I had the question not too long ago
someone asked me how come every time something bad happens
it always happens in the valley?
What is it about the valley that makes it susceptible
and so it made me really start to think about it
and so I've got a whole list of things here
and I have to apologize
by my very nature I get down into the weeds very quickly
and I realize it's after lunch
and I don't want to put you to sleep
so if you wanna pull me up out of the weeds at any time
please feel free to do that but,
I wanted to start just a little bit here with the topology
of the electrical network relative to the load
in the valley and I've shown here in the circle
kind of the load pocket where the largest concentration
of the load is
and when I talk about the valley
I'll refer to the Lower Rio Grande Valley
which I'm showing here.
The Rio Grande Valley which typically would be
further North up to include Laredo
and then when I talk about South Texas
that's all the way up encompassing the Corpus area
at least that's my nomenclature
but what I've kind of zeroed in here on
is the Lower Rio Grande Valley
where the bulk of that load is
and I wanna draw your attention to the blue line
that's a little bit hard to see
but you can see the the the blue lines two on the East
side of the valley one on the West.
So those are 345KV transmission lines
one originating from Lobo on the West
the other two are from Long Hill
which is just south of Corpus Christi.
So in terms of the ability to import power
from the West of ERCOT into the Lower Rio Grande Valley
that's the bulk of the capability is right there
in those three transmission lines
and that's it there are also three 138s
that that can carry some
but the bulk of the import is there on
those three transmission lines.
So that was that was kind of the first thing
and if we go to the next slide
I tried to put this in in kind of a bubble format here
sort of illustrating what I just showed you
on the previous slide,
you can see the Lower Rio Grande Valley
there at the bottom we've got about 3900,
approximately 3900 megawatts generation.
As was pointed out there's about 1500 megawatts of that
that is conventional gas fire generation
but that's really concentrated in two plants
those two plants are 1150 or so of that 1500
and the bulk of that generation is wind
there's about 2000 megawatts of wind generation down there
and then I'm showing a load depending on which forecast
and which probabilistic range you wanna look at
about 2800 kind of ballpark
and then I show there the valley import
that's this was actually on a real-time basis
from an operations perspective minute to minute
how much can we import into the valley
over the last year it ranged from 700 to 3500
and one of the things I want to call your attention to
is the volatility of that number
it varies greatly depending on
what outages are out there on the system
it also varies depending on what generation is on
within the valley in that 3900
which of those units are on
where are they dispatched at because as I said
a lot of that is wind generation,
when their output drops to a certain level
they no longer have to supply reactive power
to help support the voltage
and the voltage is really the limiting factor
in the valley so and I'm gonna talk about the load
in more detail here too
but I just wanted to kind of set this up
to give you a flavor of
how much that valley import capability can vary
and then also the fact that the majority
of that generation about half of it is wind.
-: Yeah so the for the 2800 megawatts of load in the valley
peak presumably if the wind's not blowing
only say 60% of it of that load is dispatchable.
-: Well of the 4000 megawatts of generation
about 1500 is directly dispatchable out of 4000.
-: Right so the 1500 out of the 28 you need 2800.
-: Yes.
-: If the wind's not blowing you only got 1500.
-: Correct.
-: Okay.
-: Yep that's correct and so obviously
you've got X amount of load Y amount of generation
whatever the delta is
has got to come in over those import lines
and there are only three of them
and it can vary drastically.
-: So let me ask you this in order to support that
sounds like Rio Grande Valley is a pretty good test case
for variability in terms of resources available.
What kind of costs are associated on a regional basis
with normalizing that for your system?
What more on this for you what is ERCOT doing
to sort of normalize that to maintain
like constant supply of power at any given time
in the Rio Grande Valley, what do you have to do?
-: Well short term we can ensure that
the conventional units are available.
-: So you wreck them.
-: Theoretically they're also there's a possibility
that they're on forced outage unavailable
or they may be scheduled for maintenance
during off-peak months.
There are from a long-term perspective
there could be market design issues
that y'all may be looking at to incentivize
dispatchable generation in specific locations.
-: Okay and then you probably also
do you regionally kind of apply ancillary services there
as well to?
-: Ancillary services are purchased on a system-wide basis.
-: On system-wide basis right okay
but do they help you normal
because again the valley is sort of self-contained
at this point it's almost Islanded
to a certain degree, right?
Because of the import restrictions
that you would experience.
-: Yeah I mean I would just it's a constrained area yeah.
-: Yeah okay so please go ahead.
-: I would also, I apologize, I would also note
if everything's in service
we don't have any problem at all.
I mean import capability of 3500 megawatts
and generation of 3900 megawatts
to serve 2800 megawatts of load,
that's not the problem,
the problem is one of the transmission circuits off
because of some issue one of the combined cycles is off
because of some issue ex cetera
and that's when you get down into these operational issues
that always seem to be a little bit more extreme
than what we see in the planning cases
'cause the planning cases start with everything there
and say well what if you lost one thing
I would also say because of the distance
that the valley is from the rest of the system
there's kind of a stair step of declining system capability
for the loss of either a transmission line
or a generation unit and those stair steps to my view
are bigger in the valley because of the distance away
from the system
and the small number of units that are there
if you lose one unit in the Houston area
the system doesn't really feel that reliability impact.
You lose one unit in the Rio Grande Valley area
and it has a significant impact on load serving capability.
-: And what's the age of those existing units?
-: I believe they're well the two that I'm thinking of
are combined cycles Magic valley and Hidalgo
they're probably 10, 15 years old I'm not exactly sure.
-: Yeah I was gonna say 20 but yeah.
-: 20 years old okay so that would be an older vintage
for a combined cycle unit.
-: Okay.
-: Okay let me go to the next slide
and I really wanted to to focus in here a little bit
on the load this first graph
and this valley specific load forecast
is a couple of years old but illustrates the point very well
you see the black line
that's the weather normalized load forecast
and then the little band of colors
shows the 50, 50, 70, 30, 90, 10 and 99, one load forecast
and what that means for example
the 50, 50 load forecast says that there's
a 50 chance that the load could be higher
there's a 50 percent chance it could be lower
and as you go up in probability
obviously you're getting higher loads with less
of a probability that the load would exceed that level
but you can see there in the Summer
yeah there's a spread not too severe
but there is a bandwidth
when that makes sense around those different probabilities
and then you can see the green line
as it's tracking relative to the forecast
the green line is the actuals
pretty good, pretty good the actual load followed
the load forecast pretty well.
Now I want to contrast that as we go to the next slide
this is the same graph but relative to the Winter peak
in the valley and the first thing I wanna point out
you see the green line is the actual peak load
relative to the weather normalized forecast that existed
the black line, it's all over the map,
it is highly volatile
and you see that as well when you look at the colored lines
on the right hand side if I had a pointer I'd be pointing
but the colored lines show that same 50, 50 to 99, one
load forecast look at the spread.
The load in the valley particularly in the Winter time
is highly volatile and a lot of that is because
of the penetration of resistive type heating
and when the temperature falls to a certain level
in the valley everybody turns their resistive heat
on which is highly inefficient to begin with
and it causes the load to spike
this is really unique about the valley
and so we're sitting here talking about a situation
where you have intermittent generation is predominant
it's variable right?
You have an import capability
that as we saw is variable because it's dependent on
outages it's dependent on what generation is available
and oh by the way the load's also volatile.
So it's the confluence of those
facts that gives rise to some of the challenges
and the difficulties in the valley.
And here I'm providing a little more detail
about the installed generation capacity
we've kind of talked about that
but as we can see here there's about 2000 megawatts of wind,
1500 megawatts of conventional generation
and as I said the bulk of that conventional
is in two combined cycle gas plants
and they happen to be interconnected to the same location.
So let that soak them in it but basically the bulk of that
conventional was on the West side
interconnected into the same location
and that's the bulk of the conventional generation
which can give give rise to some issues as well.
Next slide this is showing planned generation
again you can see of the plan generation
there's no conventional on there it's all wind and solar
I think Sharylands looking at some batteries
around the railroad location
but primarily wind in terms of plan generation.
-: Let me ask you something on Frontera.
So is Frontera still operating I mean
it's selling into Mexico right?
-: Correct.
-: Switchable as part of that DOE agreement
I know I'm gonna freak some Frontera guys out
but because of reliability we have
the ability to call that back correct.
-: Yap. -: Don't they have their own
private transmission line
that they built to go straight into Mexico?
-: They do yeah and they get a capacity payment, right?
-: Yep.
-: That kind of sounds like a legal question.
-: Okay.
-: Yeah I do recall what you're talking about
I think it may have been linked to
when they made that switch.
I don't know I'm certainly not a lawyer
someone questioned I'm a very good engineer.
-: But that was part of the DOE agreement.
-: Oh come on we like.
-: But I don't know once they switch
I don't know what leverage we had to pull them back
at that point I think it had to do
before they made that switch
yeah next slide.
This is that real import limit I was talking about the
700 to the 3500.
This is over the course of the year
but it just and again this is kind of hard to see
unfortunately I'm not very good at making slides either
I use crayons and so when somebody puts these together
sometimes they don't look too good but
from a load of 700 up to about 3500
but it varies greatly and as I said it's highly dependent on
what generation is online as well which is also varying
so you have varying output of the of the units
which affects the load serving capability in the valley
but then that's exacerbated because it also impacts
the import capability as well.
Next slide so some of the challenges
and honestly in my mind if you look at any single one
of the bullets here on the next couple of slides
and you look at it you go yeah that's not unique
there are other areas on the system
where we could find that
and I think that's true I think the thing in my mind
that makes the valley unique is it has all of them
and so you've got everything there combined together
and then based on what we just talked about
the variability of the import the load and the generation
that makes it a very challenging area.
So I just wanted to list
some of the challenging issues
one as Warren mentioned and we talked about here
it is a load pocket at times it's reliant upon
those imports in order to maintain reliability
during high load periods.
It's also a generation pocket
and I know Sharyland's got some more comments
relative to that but there are export issues there
when the wind is blowing
and the load is at a lower level
we hit constraints there trying to get the generation
out of the valley.
So it's both it is a higher low growth area
I know historically
we saw periods in the valley that were 10, 11%
native load growth it's not that much now
but there's still a lot of interest in large
from large spot load additions industrial type facilities,
we get requests all the time for folks
wanting to locate down there
there's some strategic areas there
as well as the coastal bend area for AEP Texas
some really high value locations and these load requests
some of them are a gigawatt well you start talking about
adding a gigawatt a load at a time
that's a pretty big shock to the system
and we see I mean I have multiple of those requests
outstanding right now in different areas.
Obviously it's coastal environment which has an impact on
facility condition as well as the potential for hurricanes
obviously that impact the area
there's a high penetration of inverter-based resources
which really there I'm talking primarily in the valley
about the wind
and I won't talking about getting down in the weeds
I'm getting down in the weeds here
but I'll just say that that there are some characteristics
of the operation of those wind
or just inverter based resources in general
that when coupled with the fact
that we have series capacitors installed
on some of those 345 KV transmission lines
creates problems issues because the two interact
so that's-
-: Frequency issues.
-: Yep so not necessarily singly unique
about the valley but again another one of those things
that layers on complexity in the valley.
-: I have a question to follow that
and I'm about to take you further into the weeds
and you can probably can imagine
and I'm gonna blame Warren for that because
I even learned about these concepts because of him
during my time at Ricotta.
-: Absolutely.
-: You mentioned there's a voltage issue that's causing
this issue into the valley
and you mentioned reactive equipment
and now you've mentioned series capacitors
can you sort of tie all that together and okay.
-: I will try so series capacitors effectively reduce
a component of the impedance of the transmission line
and so you can take a transmission line
and the amount of flow across the line
is impacted by the impedance of the line
how much is the line pushing back against power flowing
you put a serious capacitor install it on the line
it effectively shortens that transmission line
it improves its load carrying capability
improves its voltage performance
and so that's really the purpose of those series capacitors
they were put there to help improve that import capability
that we talked about
and be able to serve more load in the valley well
then subsequent to that,
we had the explosion of wind wanting to connect down there
and oh it just so happens that the equipment
on the wind turbines can interact
with those series capacitors so that can create an issue
from a voltage standpoint as far as that being the limit
what I mean is if you look at the sum
of the thermal capability of those transmission lines
it's much greater than the ability to import
power over the lines and so what happens
and if I had a whiteboard I'd probably draw a picture but
as you import more power into the valley
those reactive losses increase voltage will start to degrade
you reach a point where the voltage,
when the voltage degrades the reactive devices
produce less reactive power
which then causes the voltage to degrade even further
and you reach a point where you simply
can't recover from that there's just not enough
reactive capability at that point in time
to be able to recover and bring the system back up
and so that's really the limit for the valley
at this point in time is the voltage capability
and interestingly enough what we found
out about the valley is that you can add
dynamic reactive capability which we've done
we've added some Statcoms there
that can continuously adjust reactive power
in real time to help offset that
but there's a limit to how much you can add
and we're about there we've added
dynamic reactive capability
we've added it in the valley
and what happens you reach a certain point where that
voltage limitation becomes a transient stability limitation
where the valley actually starts to separate angularly
from the rest of ERCOT and we're about there
from a reactive standpoint.
-: What is that penetration percentage
I guess when you say we're there.
-: Yeah so it we don't think about it that way
we think about it more in terms of what you'll see
in operations is there's as you get more and more
flow on the line there's a kind of a degrading of
the voltage conditions
and what happens is normally it kind of goes like this
and so you can have as a rough rule of thumb
when you get to a certain voltage level
you're getting close to that
as you get more and more of this
dynamic reactive equipment you can hold the voltage up
but then what tends to happen is that
the cliff gets actually steeper and steeper
and so once you get to that point
from an operational context it becomes
almost uncontrollable because you can't tell
how close you are to the edge of that edge of that cliff.
-: So you don't want to go over?
-: You certainly don't want to go over the cliff yes.
-: In terms of the current trajectory
and kind of have how you've seen that phenomenon evolve
over the last few years
what that sounds like a major regional stability problem
that we are seeing evolve.
-: The voltage and the frequency.
-: Combined.
-: Yeah.
-: Because they're interlinked to a degree, right?
-: I'm not sure finish your.
-: Okay so and there are a couple things that
we can do to solve that we need more stable forms
of generation in key places around the state
would that be accurate?
-: It would support the valley
if we had more synchronous generation.
-: Or we need more transmission is that accurate?
-: Transmission is one of the levers that yeah.
-: That we can pull.
-: We currently have access to yeah.
-: You got to realize I'm a transmission guy so.
-: Sure I get it.
-: When all you've got is a hammer
the whole world looks like a nail
but we need more transmission in there.
-: I've heard that.
So my question is geared toward
what is our timeline as regulators as people
ERCOT especially to try to solve the reliability
forecast reliability issues
that the valley will face
and what are you seeing right now
are we gonna have major reliability issues
within the next year the next two years?
We're seeing it already now but in terms
of sustained reliability events?
-: Yeah I'll start maybe with your last question.
I think the last RPG filing that we made
we were showing about 200 megawatts of headroom
and again this is a planning study
based on averages deterministic planning criteria
which as we talked about the world down there
is highly probabilistic
but we had about 200 megawatts of headroom
I think the latest ERCOT study that had increased
where I think the load serving capability now is about 3300
is what we were seeing in a planning study
so there's you know three to 500 megawatts
I would say of headroom but the question is
are we gonna have a problem well going back to that
load forecast it depends
because the load is highly volatile
could we have a problem down there we could
if we have a cold weather event
that causes the Winter peak to spike
we could absolutely have problems
if it doesn't then we'll probably be okay.
-: And to some extent to add on to that,
to some extent you're asking
how are we gonna roll the dice
because if you look at everything in service
no we're not gonna have a problem
but will we have a hot day or a very cold day
when one of the generation units is out
and maybe one of the transmission line trips
if that were to occur we would likely have some sort
of an operational issue in the valley.
-: Well no I'm looking at it takes six years
to build a transmission line according to your timeline
and eight years in the valley apparently
for some reason or another
and then we have no forecasted base load generation
in the queue really to any real degree
and so I'm wondering
when are we gonna start to see real problems
in the Rio Grande Valley
which happens to be a very economically
dynamic part of Texas.
-: I mean operationally we see issues in the valley
about once a year.
I mean last week the tropical storm came through last fall
and that led to some load issues down in the valley
so from an operational perspective
we continue to see operational events down in the valley
the February 2011 event load shed on the system
lasted around four hours
load shed in the valley lasted two days,
two and a half days
I can't remember exactly what but just because
of all of this resistive heat down there
and the extended cold conditions
so I mean I think we get to the end of this conversation
I think the time for building transmission is now.
Will that prevent an operational event in the meantime.
I'd have to say no.
-: Right.
-: And how do we shorten that six years?
-: I don't now.
-: One way to do it is well I guess
there's two types of projects right
there's reliability and economic
and given the unique circumstance that
the Rio Grande Valley is under right now,
perhaps reliability projects would be a more efficient
manner of building transmission into the area
versus economic especially because
we still need to implement the Senate Bill
for the economic criteria
so when you have a situation like this that has
presents a reliability issue I think reliability projects
are a little bit faster.
-: Correct.
-: And about how much faster can
you kind of give us a timeline?
-: I mean it's a little faster for us to do the analysis.
I would also say that for certain reliability projects
and this would be something
that we would want to consult with the Commissioners
and with staff we can designate it as critical
to reliability unfortunately that reduces your time
to review that project from 12 months down to six months so
we would not take that critical designation lightly
then it kind of falls back into the hands
of the various transmission service providers
and admittedly we also have
a right writer first refusal requirement
so when we designate what that optimal project is
the end points would determine
the the actual transmission service providers
that would be involved in the in the construction process.
-: What would you reduce
from 12 months to six months specifically sorry?
-: The the CCN analysis if we designate it as critical
when the transmission service provider brings it to you
I think under your rules
and again I'm not an attorney so I don't know if
the exact stipulation but the timeline is reduced
from 12 months to six months.
-: Yeah and just because that processes the existing process
doesn't mean we need to adhere to it
we can change that as well.
-: That may require some real changes
role or protocol changes to shorten the timeline.
There's a one avenue right we have it.
-: We can do that.
-: Yes sir.
-: And while we're on the on the subject of timeline
if I could and you're probably aware of this
but I talked about some of those large load requests
that we have that's true in the valley
it's also true in the Coastal bend
area around Corpus Christi, port of Corpus Christi,
Port of victoria very strategic high value,
high interest location, we have a lot of interest from
very large load customers who come to us and say
what would it take primarily how long would it take
for you to be able to service well
we very recently signed two load customers
about a gigawatt a load
and made the filing got endorsement
to move forward with those upgrades
we had about 25 megawatts of headroom
over and above once those upgrades were in place
we have about 25 megawatts of headroom
well there's eight other people waiting in line
we've done everything we can to ring
what capacity we can out of the system
back to that timeline if it takes,
if I have to build major infrastructure
in order to accommodate that request
five or six years they want to be connected
in 18 to 24 months
and so some of these customers are like
sorry I'm gonna go to Louisiana
or somewhere because I can get hooked up a lot quicker
it's really an issue so I don't know
what we can do I you know it seems to me
and again you guys poke me if I'm
if I get in trouble here but would it make sense
in some of these locations
let's look what infrastructure
would we need to put in place where we would have
an extra gigawatt of capacity in some of these strategic
high-value areas prior to having somebody say go
and sign on the dotted line but having some excess capacity
in the areas because we're gonna lose some business
because of that and it just takes a long time to.
-: When you say capacity
are you talking about transmission capacity?
-: I am.
-: Okay so aside from 345, 138 and 69 KV lines
what other solution do we have?
-: No that's it but it just takes five six years
if we have to build a 50 mile 345 KV line
to provide enough capacity
by the time we we do the study
we submit it you know six months to get
ERCOT endorsement through RPG
we've got eight months to a year
to do environmental analysis,
routing analysis to prepare the CCN
six months to a year to get the CCN approval
depending on whether it's critical or not
and then move forward to actually acquire the right-of-way
and build a facility that whole timeline is lengthy
and a lot of these guys like I said 18, 24 months
they want to be up and going.
-: So to the chairman's point earlier
we obviously are in the position to modify rules
and aircraft protocols and criteria
and that could definitely have short
could potentially shorten the window
but from a transmission an electric utility
transmission planning, building perspective
how much flexibility do you really have to shorten
the build out of the 345KV line I mean
how long does it take you once you get a CCN
how long does it take you to build a line.
-: Depending on what it is but we can put a 345 load serving
station in probably 18 months
and then depending on the line 24 to 36 months.
-: So still about if I'm counting right.
-: We're getting close though
we're getting close.
-: Two and a half years.
-: Depending on the line if it's shorter we can do it quicker
I think West Texas.
-: I'm over here I'm right.
(members laughing)
-: Yeah okay actual actual construction time
on far West what were.
-: So I can't recall but it was 18 months.
-: 18 months.
-: It was superhuman.
-: Yeah.
-: I was gonna say Warren I don't want to steal his thunder
'cause he has his last act is about the Permian basin
but the TSPs that own most of the infrastructure out there
and therefore have most of the obligation to build
have been chasing our our tales on this for several years
and over the last 24 months I guess it's been
'cause COVID was sort of a pause
we developed a number of strategies that we thought
could meaningfully shorten the time between
what transmission do we need and transmission is built
and energized those range from what criteria
could ERCOT use to determine need
and does 'cause traditionally ERCOT either thinks
there's organic growth or thinks there's a contract sign
and in the valley as in the Permian
they can go to market in 12 to 18 months
and we're still trying to figure out how
we're gonna serve them.
There are parallel studies that can be done
by the utility and by ERCOT at the same time
so that rather than sequentially studying those projects
we're doing it in tandem.
There is the six-month urgency designation
and there is a fair amount of flexibility
frankly already in place at the Commission in terms
of how you all want to process those CCNs
and so we've been holding off on sharing all this with you
because you have a lot on your plate
but there are some very concrete opportunities here
to go faster.
-: Please don't be shy feel free to share those
as soon as you're comfortable.
-: Yeah and Warren just one last question
about the ERCOT processes
so RPG I mean I'm just thinking back to Houston import.
-: Sure.
-: It was heavily litigated
and obviously there was some need there
Houston was growing leaps and bounds still is
and of course that that was heavily fought over
within RPG was it not I mean it was RPG
was here at the Commission it was everywhere
was it the legislature.
-: We heard a lot of noise at RPG
but RPG is not a voting body.
-: Okay but it doesn't slow it down
or anything like that.
-: It doesn't necessarily slow it down
except to the point where someone raises something
we look at and go yeah that's a really good point
and then we might have to go back
and I think that did happen with with Houston
where there were a couple that's why they were raised
we went back and studied it a lot of the litigation was here
where we actually had two different
contested cases associated with that.
-: That's correct okay.
-: I think I saw a rabbit across the road
and got us off a little bit but I wanted to kind of continue
here some of the challenges in South Texas
we can go to the next slide.
Multiple generic transmission constraints
which we could probably talk for a while about
what those are but essentially back to that
voltage stability issue it's a stability issue
that cannot be directly observed in real time
by the operators
and so you have a group of transmission elements
that are defined
and that grouping of transmission elements is then used to
adjust or limit flows between two geographic regions
you calculate those limits kind of offline
and then convert those back into an equivalent megawatt flow
that the operators can actually see
and manage the system with so
out of I think 16 GTC's in ERCOT seven of them
are in the Rio Grande Valley
so that's again another thing
that makes the valley really complex
and difficult to manage some of those GTCs
have now started to overlap so you have a GTC
within another GTC nested
and the solution for the GTCs
the GTCs are considered economic constraints
because you do have the ability to mitigate it
through redispatch you just turn the generation down right?
And so you reduce the generation you reduce the flow
therefore it's considered an economic constraint (coughs)
excuse me and so you have conditional exit plans
associated with those GTCs
but I've got a bullet later I think I said
4% of the load in the valley
and 40 of the ERCOT load in the valley
and 44% of the GTC's.
It's a very complex area.
Talked about difficulties and delays
associated with permitting inciting
new transmission infrastructure
and so I've listed some of the issues we've had
we had a project here that was just put in service
this Spring and so I talked to the gentleman
who was working on that project like man
why it takes so long?
What is it and so I've listed here
some of the issues one is that some of the areas are just
very highly congested it's just difficult to find
a transmission route that's available
through some of those areas.
Numerous Commissions and agencies that you have to work with
which I've listed here as well as the county
and city government's irrigation,
water canals, pipelines, wells
there are other infrastructure improvements down there
to meet the growing load that already planned like highways
that they've already got those those routes planned
and so it makes it difficult then
to try to cite new transmission.
The other thing and this isn't in and of itself unique
to the valley but there is some aging infrastructure
particularly some of the facts devices
some of those dynamic reactive devices
that we talked about.
Those are nearing the end of their lives
on the AEP Texas system
and so we're gonna have to make some decisions
really quickly about what do we do with those.
So a lot of challenges
some of my takeaways from all that
and I've been beaten on this but
obviously the majority of the generation is
intermittent subject to environmental conditions
the conventional generation is really comprised primarily
of two large combined cycle plants import
capability can vary significantly
and that import capability is dependent upon the resource
reactive capability what's online
and able to be dispatched in the valley.
Valley load is highly volatile
particularly in the Winter time
and then just in general when you go
back to that very first slide
with limited connectivity with the rest of ERCOT
the margin for error is just less down there
and you think about you lose one combined cycle plant
down in the valley
and that's what a third of the load,
fourth of the load I mean it's a significant impact
and we just don't have enough ties back to the rest of ERCOT
to give us the kind of margin that we really need.
Next slide, yeah last major 345 KV path
and that's the one over on the west side of the valley
that was placed in service in 2015
at the same time we reconducted the two 345s
on the East side of the valley
and we actually had to do that
while they were energized
and the reason for that is we just
didn't have enough redundancy
in the valley to to get the clearances
to be able to reconductor those lines
we had to do it energized which
obviously adds to cost and safety concerns and so forth
and even those upgrades were really triggered by
a load shed event that we had after
a Winter temperature event.
Takes a long time in some areas to construct
a new transmission
Warren talked about the six year time frame
it can be longer than that depending on where you're trying
to route the new the new transmission line
I talked about the head room in the valley
and then as I said 4% of the of the load 44% of the GTC's.
Recommendations take a more proactive approach it
seemed like in my 25 years of working
in transmission planning and in particular working on issues
in the valley it just seems like
we're always trying to catch up
it's just never have we ever
I certainly haven't felt like
we've ever we've caught up we've gotten ahead
we're ahead of the problem
we're always trying to catch
it seems like we're chasing it.
Part of that I think has to do with the
fact we talked about the time frame
some of these lines that you have to
build are really long over 100 miles
and it takes a long time to get through
that process and build that infrastructure.
We're studying and planning the system based on models
that are typically about six years out
when it takes maybe longer than that
to build the infrastructure.
So I really think we need to be more proactive
we need to think about off into the future
the serious caps that are there they're
gonna reach the end of their life
eventually we're gonna have to retire
those as well as the conventional generation
and so we really need a good long-term
plan for the valley
that has shorter term actionable steps
that we can take to get us to that ultimate state
because there are some big changes
that will be coming in the next 10, 15 years down there.
I think we can also look at the studies
that we are performing
look at some of those input assumptions
I know warren has some ideas around that as well
and really what I'm talking about there is
what load scenarios are we using when we plan the valley?
what are we assuming for output
from those intermittent resources
and is that really appropriate?
What outages do we consider whenever
we're planning the system for the valley?
And I continue to say I think
from a transmission planning perspective
when they're operating the system,
they're always operating the system looking to see
what's gonna happen when the next contingency occurs
when I lose the next transmission line?
I want to adjust the system
so that I have everything all my voltages
and thermal loadings on the lines are within their ratings
after I have the next contingency
we don't plan the system that way
we plan the system on a deterministic basis
we don't look at N minus one minus one
which is really after you lose the next facility
are you sure that on that a subsequent loss
of a transmission line that we're gonna be within
all of the criteria we don't plan that way
and I think we should and then again
the proliferation of the GTC's at some point
I continue to say those GTC's at some
point are gonna become reliability issues
and that's something I think we need to sort of wrestle with
and then ultimately as I said we need
more transmission to the valley short and simple so.
I said a lot I drug you into the weeds
I told you I would I apologize for that.
-: Lori might have pushed you a little bit.
-: Yeah I'm sorry.
-: No it's good. -: I was just going back to.
-: I did include some of that 25 years of history
I included at the end of my slide presentation
I'm not gonna go through that I promise
but it's there it's kind of interesting to look through
so thank you.
-: Thank you and yeah I was kind of take a trip
back in memory lane with ERCOT transmission planning.
-: That's good so those are important elements.
-: Real quick question GTC's discussion of trap generation
during legislative hearings,
what kind of generation was that wind
was it both wind and gas that was trapped
during the Winter storm due to the GTC's?
-: Yeah so not sure quite how to put it
but I mean to me that those export constraints
a megawatt is a megawatt is a megawatt
in terms of the resource type
so I don't know that we really distinguish
the way you typically would reduce the generation
in order to get the the flow back to
or below that limit is you adjust the generation down
that provides the most benefit.
So you look at which unit will reduce the flow the most
and that's what you back down regardless of what type it is
so hopefully I answered your question.
-: Yeah I guess I was just kind of curious
I mean just we heard some discussion about that
and I was just interested in knowing a little bit more.
-: Yeah maybe if I can add,
my understanding of the analysis coming out of the valley
is that there was some limited amount of generation
that was trapped but it was fairly limited
in the hundreds of megawatts over a short period of time
and my understanding is that it was wind that was being
constrained at that time.
-: Okay thank you.
-: All right Sharyland.
-: Good afternoon Michael Queen on behalf of
Sharyland utilities thank you for the opportunity
to speak the workshop.
So I recognize most folks don't immediately throw their
(clears throat)
assets up on the screen that's different
than where everybody else has been but
when we start talking about the lower Rio Grande Valley
that's where we are Hidalgo Cameron county
that's exactly the area that we serve
and so Sharyland is a transmission owner operator
in that space, next slide please.
So I won't be labor or try and recap all the facts that
we just went through.
The quickest summary is it's a distant part
from the main ERCOT there's lots of GTC's
in fact over half almost half of the GTCs in ERCOT
are required to keep reliability down there.
We agree and appreciate ERCOT's acknowledgement
in their 60-point plan that we have to have more
transmission but I'll give you two invocations
from my perspective that a rebalancing point
in the planning process is necessary
and in the 10 years
and certainly Wayman's been struggling with this longer
than some but in that 10-year
past 10 year period there's only been a handful of projects
that either passed the reliability criteria
or the economic and so that's where he said a rebalancing
needs to happen there
but an operational challenge that we see and face every day
we had a construction project it's ongoing still
but we had to have a transmission line out
and the return to service period
for that transmission line was so short
we brought in a fair amount of Capex cost
directly related to having to have that transmission line
that's out of service and being reconductured
back in service so quickly
and so the only place I've seen that obligation
is West Texas
and our return to service window is just really tight
and so that's an operational challenge that we face
day in and day out, next slide.
Went over reliability economic test
just a couple thoughts on that process
the essence of the economic test is to me pretty simple
from standpoint of what's the cost of new transmission
compared to what's the higher cost of having
more costly generation serve that load due to constraint
and that's the essence of the economic test.
That economic test can address inter-valley congestion
but it also can in fact address the export issue
that we were just talking about.
I've heard different numbers bandied about
since February as to was it 4000 megawatts
was it several hundred megawatts of trap generation
I don't have a number to bring to the Commission today
but what I what we are advocating is
let's evaluate whether we can economically deliver
that to the load
that I guess that that's our ultimate ask.
Senate Bill 1281 we acknowledge
and respect the Commission has a rule making
implementation plan that concludes
approximately June of 2022 followed
on by ERCOT's implementation through the protocol revisions
and that stakeholder process however we understand ERCOT
is not going to be reviewing any economic projects
that are brought forward during this 18 to 24 month plan
and if we only have two criteria or two tests
we're struggling to see why we would potentially
want to pull one of those down in this interim period
when I think the Commission in the last 30 minutes has said
sooner or later is our bias to addressing
the Lower Rio Grande Valley
and so we're gonna suggest actually a parallel path
type scenario where (clears throat)
we certainly let SB 1281 go through its normal process
but we're advocating that the Commission
gives ERCOT the authorization it needs
to continue with what we think
is a very straightforward process
to evaluate economic projects in the interim
so next slide.
So we're asking that we keep both tools
on the table at this point where we do
in fact evaluate reliability projects
but we also evaluate economic projects.
We do in fact have economic projects in cue right now
that we'd like to bring forward
and have at least reviewed during this interim process
we believe ERCOT is well equipped both technically
and experientially to work this process
we think the intended language is clear enough
that on a case-by-case basis
and I think ERCOT would agree that
there's not a tremendous number of economic projects
that get brought forward
so we're not thinking this is a tremendous burden on them
in this 18 to 24 month period.
Additionally we look forward to working with ERCOT
and broaden that reliability test to include
different scenarios alternative criteria,
cost savings and time to market
and so I'm sorry I don't remember who asked the question
of how do we solve this sooner first later
and how much time do we have
and I'll give you two examples
of how we solve it sooner or later.
I'm not suggesting these are the epitome
and the one bullet to solve the whole scenario
but we have facilities down there that are 345 transmission
that are double circuit capable.
The right-of-way is in place,
the transmission structures are in place
but the other circuit's not home
so if you want to try and truly shorten transmission build
utilize the assets we've got down there today.
Same thing Commissioner McAdams asked earlier
and very delicately about HVDC.
The HVDC facility down there that we own and operate
is capable of 300 megawatts that's its maximum capability
that's what it was originally built for
the conductor that goes to Mexico the five miles
its capability is 300 megawatts.
What isn't being said is the other side of that structure
is not being utilized there's a complete another path
so to expand the HVDC if that's the appetite
of the Commission that's again a shorter path
we see to try and address some of these valley issues.
-: The DC Ties 300 megawatts right now of total
transmission capacity how much more can you expand?
-: So I haven't done an analysis say hey in
that footprint we can bring another 100, 150
I'm suggesting let's if we have appetite
for additional HVDC let's truly gear up and say
if the other side of that transmission tower
is available and we have three acres to that side
let's work with the vendor community and say
what can we put in that that footprint
to get us additional import and or export capability.
we do not have immediate expansion capability
beyond 300 in the footprint
in the equipment that's in place today
maybe a more direct answer to it for you.
-: All right thank you sir.
Warren you're gonna bring us home.
-: I have one more slide if you could go back.
Well actually go back to the GTC slide
I just wanted to kind of show those
I had one point to make about the GTC to add
what no go down one more there you go
stop right there okay so getting back to Commissioner
McAdams I think raised the issue of
exporting on the GTC's.
Circling back to your comment before
about dispatchable generation
recall that whenever the GTCs
these Generic Transmission Constraints
are limiting export from the region
that means that the wind generation down there is very high.
If the wind generation is high and the ERCOT operators
and these security constrained economic dispatch
have to ramp those units down
in order to maintain the reliability of the system
that means that the power prices in the valley
now are being set by these curtailed wind assets
and so that becomes an economic disincentive
for new dispatchable generation
to move into that area
so the in a way the Generic Transmission Constraints
are limiting the development
of dispatchable generation there
as well as wind generation.
-: No 'cause it's captive intermittent generation
that's just bottled up there
that is suppressing well it's providing a ceiling
on economic dispatch correct so-
-: When the wind's blowing.
-: Well we go the opposite way as well, right?
-: Right?
-: Because if you.
-: That's his point.
-: Yeah and then when the wind stops blowing then we have
the import constraint down into the right development.
-: Into the opposite presumably the opposite
effect on prices the LMP.
-: Theoretically yes yeah yeah
so then the price is being set by
the generation assets that are there the gas assets
and then obviously if there's a reliability issue
beyond that then you would get some sort of
scarcity pricing in there.
So if you go to the next slide this is my last slide.
So we talked briefly about the Permian basin
and Liz gave kind of a brief statement about
some of the lessons that we've learned there.
Two of the actual planning considerations that we changed
specific to the Permian Basin.
The first there's a gas plant out there
that has four different units
and we look at the loss of one generation unit at a time
from a planning perspective
so we call it G minus one the loss of one unit
unfortunately there are certain environmental considerations
that theoretically can affect all four
of those combustion turbines
and as a result of that from a planning perspective
we decided in the Permian Basin that we would take
all four of those units out as a single contingency
so we started doing that late last year.
Another thing that happens in the Permian Basin
is you have basically 24/7 oil and gas demand
you have a significant amount of solar capacity.
So we started planning with the understanding
that we needed to serve this load
when the solar wasn't available.
So we made specific planning assumptions
associated with variable generation
for the Permian Basin
and we've been using that for about the last year
or so in the Permian basin
I think it's appropriate for us to use similar
criteria for the valley specifically
the two combined cycle units that sit very close together.
We were tracking earlier this year
growing drought conditions down in the valley
theoretically now we've gotten rain down there recently
so the drought conditions have alleviated
but we were concerned that in the not too distant future
there could have been a combined impact
on both of those plants from a drought consideration
also they are right next to each other
now I don't have a way today
I wish I did but I do not have a way today to understand
what the contingencies on the gas system are
that could affect both of those plants
but it is likely that there is some infrastructure
that serves both of those plants
from a compression perspective
and again I don't have any way of
defining that right now again I wish I did
but I think it's reasonable because of
the potential for drought in the area
and from a gas delivery perspective
I think it's reasonable to consider
the two combined cycles as a single contingency
as opposed to a double contingency
the way we look at it today
I think that would put us from a planning perspective
closer to some of the operational conditions
that they see.
In addition we talked about solar in the Permian basin
there's a significant amount of wind in the valley area
and Wayman touched on this before
we when we do our planning studies
we are fairly conservative on what the output
of those units are we typically would ramp those units down
to about 10% but there's a cut-off there at 10% below 10%
they do not have to provide reactive support
and some of the units cannot provide reactive support
which means that they no longer support
the voltage in the valley
that makes a significant difference
in the planning results that we see and so going forward
our study is now looking at the
potential for the wind to be below 10%
and not providing reactive support
either of those two by themselves put us in a position
where we're ready to endorse
a new reliability project down into the valley.
In addition Senate Bill 1281 also has consideration for
extreme weather conditions
Wayman talked about the two 345KV lines
that come out of Corpus they are fairly close together
in their Northern extreme
a hurricane or tropical storm coming through
could have an impact on both of those circuits
which would make it very difficult if it were
high demand in the valley for us to be able to
reliably serve those demands
so I think Senate Bill 1281 specifically directs us
to make recommendations exactly like this
so we're in a position where we are gonna be working
with the transmission owners to finalize
an endorsement of a new reliability project
down into the valley.
Now admittedly that's a six-year timeline.
-: Just to maybe tag on just a little bit
and I know we're focused on the valley here
but I made the comment earlier
and in particular when you look at the GTC's
it's kind of like a drop of water on a paper towel
it starts to move outward
and some of those constraints have moved further out
further North and now encompassing a larger area
in South Texas I mentioned the Coastal bend area
there around Corpus
I don't wanna completely leave that
out of the discussion as well
when we talk about some of these
changes because that area has gotten larger and larger.
-: I was gonna ask yes maybe after the fact
but so Corpus is experiencing ramifications
from these Lower Rio Grande Valley events.
-: Well the the GTCs in particular
when we look at the impact of those GTCs
and potential upgrades to mitigate those
we're now looking at potentially making connections
transmission connections North of Corpus Christi
in order to fix some of those.
-: And that plays into your scenarios
that you're looking at right now?
-: Yeah I think our recommended project
is going take into account the GTC's
and alleviating the the extent of those issues.
-: Your recommended project is that
an existing project that you're reviewing
in the RPG process right now?
-: Well we have had several both AEP
and the South Texas electric co-op
have brought to us specific proposals
now admittedly these were originally designed
to serve some of these large industrial customers
down in the Valley
but we have been looking at this with
the transmission service providers
for about the last two years
looking at different alternatives.
In addition ERCOT is required to produce
Generic Transmission Constraint exit strategies
and so we have those studies also done
or we have another study that's
about to be completed that will inform that as well
and we just like Raymond said we just
had reliability analysis in the Corpus area
so that'll be a part of that recommendation.
-: Mr. Quinn you mentioned utilizing existing transmission
infrastructure are you talking about
infrastructure that that goes into the valley
or is in the valley that maybe is double circuit capable
but it only has one line right now?
-: Correct there's a 345 line that
starts at the Palmetto Sharyland station
and goes on up through Stewart road
and into North Edinburgh.
It's approximately 100 mile transmission line
that's double circuit capable
that has one circuit on it presently.
-: Yeah we actually AEP Texas actually AEP
the line on the West side of the valley
that I showed you the two on the East
one on the West the one on the West was originally built
it's double circuit capable single circuit strong
now we've strung a lot of the open position hooking up
wind farms honestly but it's still not a complete
contiguous path you have to be a little bit careful
because typically in a planning environment
you would consider loss of that double circuit
as one contingency because it's on the same towers
so you just have to keep that in mind
it's not something you have to take into account.
-: It is without a doubt it is a risk reward scenario
but we're trying to I think that
the ask was is there ways to do
this in a more expedited fashion.
-: Absolutely.
-: That's what I suggested it's not a silver bullet
to solve everything but utilizing
or capitalizing on part of the infrastructure we have
immediately available is a potential solution.
-: That seems like a solution, a near-term solution
maybe not a like you said a silver bullet
but an incremental near-term solution
I mean you have CCN that was approved by the PUC
that allows you to build that infrastructure
as double circuit capable.
So is there a reason why you would make a decision
not to add that additional line
or is it just what,
how do you I guess make a decision to only put one line
and then later put in the other line.
-: I'm not a planner but it's my impression
that basically there are certain criteria
and Warren talked about this earlier
in the valley there's certain criteria in planning
for all of ERCOT
and it's a you either are above the line
or you're below the line
and it doesn't matter if you're just below the line
or way below the line
if the project isn't you know either economical
or based upon today's planning criteria
doesn't meet the reliability needs
it doesn't get built
and so that's why I think that the notion of expanding
the reliability criteria for the Lower Rio Grande Valley
is important step in the right direction.
-: Can you shed a little bit more light on that Warren
because when you and when ERCOT endorses
a transmission project
and the utility comes over to the PUC to get a CCN,
the CCN that's provided is for a certain project
and it's double circuit capable
if you've already labeled it a reliability project
or an economic project I mean
is there an like you have to review that additional line
that's being added under reliability or economic criteria?
-: Yeah I think you're falling into
the most cost effective project to solve the need
so if we see a need
and we determine that a single 345KV circuit
will serve that need
it's lower cost to the consumers
for that project to get built.
So we have a significant focus on trying to
minimize the cost of the system
while maintaining reliability
and I think you run into that situation here
and unfortunately I've gotten a little bit
older and orner if that's a word
and I find that situations where we build a single circuit
and then when we start talking about
putting a second circuit onto that
double circuit capable tower we realize
that the maintenance window to take the
circuit out of service to put that
second circuit is so short
that it becomes increasingly difficult to do that
and that's Raymond talked about the
maintenance window having to work on
those other two circuits hot energized.
I've gotten to the point now
where it almost feels reasonable
if we're going to build a circuit
let's just go ahead and build both circuits
and not put ourselves in a position where
two years later, three years later we realize hey
we'd like to have that second circuit
but from a maintenance perspective
just getting it in is gonna be difficult.
-: And whenever a transmission project is built
to be double circuit capable,
is there I'm just wondering if it's you get a CCN
you get recovery and at the rates
and you've already paid for something that's double circuit
capable but you're not using it it's like buying
I don't know how to compare it to,
an iPhone that has a lot of capacity
but you're only using half of it
but you've already paid for the entire phone.
-: Well I've got opinions but let me let Liz go first.
-: So there are two things I mean one is
we arguably have been pennywise and pound foolish
and not adding that second circuit on the one hand
adding it later is incrementally less expensive
than having to build a second line
on the other hand there's this historical
predisposition to against pulling the circuit
until the need is absolutely clear.
I will tell you in far West
we actually certificated a project
and ERCOT had authorized it to be single circuit
but double circuit capable
and we brought the second CCN for the second circuit
before we had even finished building the line
because the need was so great.
Now the last piece is the Commission's own rules
provide that subject to the cost tiers of the RPG process
that a TSP can go in and put the second circuit in
without another CCN proceeding if it is 138 or 69 KV.
If it is 345 KV we have to come back for
an additional CCN process
and so as you have through the day asked
what could what could you do differently or more efficiently
I think that's pretty low hanging fruit.
-: Thank you for that clarification now that makes sense.
-: Not everybody wants to read the CCN rule
as closely as we have.
-: Non thank you.
-: All right thank you panelists anything else Warren.
-: Thank you.
-: Thank you all very much.
That will conclude that portion of our programming for today
item number four I do not have anything for items
five through 19 either of you?
-: No thank you.
-: Yes ma'am.
-: We will meet in closed session today
so having convene and duly notice open meeting Commission
will now at 2:09 pm on July 26th 2021
hold a closed session pursuant to
Chapter 551 of the Texas government code
section 551.071, 551.074 and 551.076.
Closed session concluded at 2:36 p.m on July 26, 2021
Commission will now resume its public meeting.
No action will be taken by the Commission regarding matters
discussed in closed session
and having no further business
this meeting of the Public Utility Commission of Texas
is hereby adjourned thank you all.
-: Thanks sir.