Good morning. This meeting of the Public Utility.
Commission of Texas will come to order to consider
matters duly posted with the Secretary of State of
Texas for September 2, 2021. For the record, my name
is Peter Lake. And with me today are Will McAdams,
Lori Cobos, and Jimmy Glottfelty. Before we dive in.
Will has a few words he'd like to say about one of
our long time teammates. Mr. Chairman, with your permission
I'd like to call up a staff member if I might. Just
for a few questions. Darryl Tietjen, would you step forward
please?
Good morning. Commissioners. You're catching me by
surprise. Good. Could you state your name for the record?
Yes. Darryl Tietjen, Rate regulation division. Thank you, sir.
Darrell is it true that you've worked
for the Public Utility Commission for more than 30
years. For better for worse. That is true, Mr.
That is true. And you've testified previously
on a lot of high profile cases, as I remember, rate
cases. Sale transfer merger cases, securitization cases.
Yes, sir. And I believe you've also been
a leader in adopting a lot of our existing rules. So
is it fair to say that the modern utility code interpretation
is somewhat through your mind? Commissioner, are you
perhaps you're not trying to imply that I was responsible
for the winter storm, are you? I don't want to be deposed.
Course responsible for the storm is one thing
responsible for the existing rules. I guess is
another. I have worked on a number of rules yes, sir.
That's my understanding as well. You've always also
mentored and trained a fair amount of the Commission
staff over those decades. A lot of the people in high
profile positions from the PUC that are now leading
the industry, sort of grew up under your tutelage.
Is that fair? Well, when you have been here for
over 30 years and started and I did start when I was
10, so I guess that's an accurate characterization.
Yes, sir. Okay, well, for those reasons, I called you
up here, a lot of people apparently think a lot of
you, and they have recognized
the influence that you've had on both the Commission
and the industry as such. And I wanted to take the
opportunity with the chairs permission to announce
here in front of your colleagues and the public
that you have been selected to receive the 2021 Gulf.
Power, Gulf Coast Power Association Pat Wood Power.
Star Award and the award as those in the public
should know, is one of the most prestigious awards
that can be achieved by someone in the industry
or in the regulatory body that works with this industry.
And I think due to your years of service, it's well
deserved. And I just wanted to take a moment to say
that. Well, here here. I definitely appreciate that.
Again, I had no idea why you were even calling me up
here in the first place. I didn't know if I did something
wrong. You know, just yesterday I asked Connie, I said
Connie, I said I got this registration for the GCPA
conference coming up later this month. And I said
I guess, did you just want some sort of representation
from all the divisions? She said yes. So typical
in the past the GCPA has sometimes
addressed issues that I do not ordinarily get involved
with too much. But anyway, now I understand Connie.
But I definitely appreciate that. Of course I was here
back in the old days when Pat Wood was here and I
know Pat of course. And as we all know, Pat's
a very intelligent guy. He's a visionary, certainly.
And I graciously accept his award that has
his name on it. As you are, Daryl, a visionary in rates.
Well, I appreciate it very much. Thank you. Congratulations.
Thank you. Sure. Okay.
The only other item we have that is not quite of
such import but close is recognizing Mr Journay's birthday.
Happy birthday sir. We don't need to get into the
calculus of it, but I will say, I think
everybody up here can agree that your wisdom
is as timeless as your wardrobe and we're grateful
to have both. Yes sir. I'm older than rocks and dumber
than dirt. That's why I'm sitting here. You can date
him by the vintage of his Magellan fishing shirts.
We don't need to get into the...
Happy birthday sir. Could you take us to our Consent Agenda
for the day?
Good morning, Commissioners, by individual ballot, two
items were placed on your Consent Agenda, item 10 and
item 15. Okay, is there a motion to approve the items
just described for our Consent Agenda? So moved. Seconded. All in
favor say aye. Motion passes. At this time, we'll
open for public comment. Oral comments related to specific
agenda items will be heard when that specific agenda
item has taken up. This is for general comments only
speakers will be limited to three minutes each. Mr.
Journay, do we have anyone from the public signed up
to speak? There's nobody on the list, sir. Fair enough.
Public comment is now closed. Understand we will not
be taking up item 25 today. So with that we will start
with agenda item number one.
Item #1 is Docket number 52004, petition
of D P S L P. I've renamed them to alphabet soup
limited to amend the AquaTexas certificate of convenience
necessity in Montgomery county by expedited release.
Before you is a proposed order filed on July 15, exceptions
were filed by a memo. The ALJ filed on August 2nd, recommended
no changes in response.
Thank you. I think the proposed order makes a lot of
sense. The only issue I would have is the lack of notice
provided to AquaTexas. At the end of day, I think
they were eventually provided notice but want to
remind stakeholders that notice is a fundamental component
of our process. Any other thoughts, comments?
I agree. Agreed.
Considering that, is there a motion to approve the
proposed order with a modification to note that we're
we are granting a good cause exception to the applicants
notice because AquaTexas did receive actual notice
of the application with a reminder to stakeholders
to make sure to adhere to the process going forward.
Second. All in favor say aye. Motion passes.
I don't think we have anything on item two that will
bring us to item number three, Mr Journay.
Item three is docket 512080, it's the
application of Commission staff to review USF support
for the Briggs exchange. Before you is a revised proposed
order that was filed on July 20 and I have a memo
in this matter. It's fair to say this seems straightforward
and I certainly want to be supportive of telecom in rural
Texas. Is there a motion to approve the proposed
order as modified by Commission Counsel Memo? So moved. Second.
All in favor say aye. Motion passes. Item number four
please, sir. Item four is docket 51289 is the application
of Commission staff to review USF support for the Water.
Valley exchange. Before you is a proposed order that was
filed on July 22. Corrections were filed. The ALJ accepted
those corrections by memo filed on August 9.
Thank you. This one's a little more complicated.
One of the big issues at question is
if TUSF Support should be on a ETP
basis or per wire basis. My sense is, a wider center
per wire centre basis. My senses wire center but happy
happy to hear other thoughts on that. So I just like
to highlight the the high level crux of the policy
that is both in the statute and the way PUC
has attempted to move forward is to provide, maintain
and provide that essential service. So in this case
because the criticality of the entities that were
being served. I think that's key to that public
interest determination. We're fortunate to have that
latitude to make that. So I think this case hinges
upon that fact. Absolutely. The telecom provider
that has five access lines in this case is providing
services to county emergency medical providers and
that is critically important. So I think I would be
in favor of modifying a proposed order and proving
it based on a wire centre basis given the facts
of the services that are being provided by the telecom
provider. At least one of them in that wire center.
Great. I'm in agreement. To do so. To change the proposed
order, to accommodate that adjustment, I think
we need to modify ordering paragraph one and delete
ordering paragraph two. Is there a motion to approve
the proposed order with those changes to modify ordering
paragraph one to provide TUSF support to the entire wire
centre and delete ordering paragraph two. So moved.
Second. All in favor say aye. Motion passes. Item ♪5
Please, sir. Item five is docket 51475. The application
of Windstream Sugarland to revise customer service
tariffs. Before you is a proposal for decision filed
on July 7, that would dismiss the application for
failure to prosecute and for failure to amend their
application. No exceptions were filed in this. Think
it's pretty simple. It's an abandoned application. That's
a way to put it. Yeah. Yes. Yeah. Is there a motion to
adopt the proposal for decision? So moved.
Second. All in favor say aye. Motion passes. Item number
six. Item 6 is Docket 51626. It's the application
of Blossom telephone company to true up. They're
receipt of Texas USF or reductions in federal USF
before you is a revised proposed order filed on July 22.
And there you go. Thank you. Mr Journay. This
is yet another even more nuanced USF case relating
to what TUSF funds are eligible for related to
federal USF funds. There's a big question about broadband
and how that syncs up between the federal
and the state version. We've got several previous dockets
that consider this. I know there's a lot of different
elements of this, but it is certainly worth considering
going back to establish a position of previous dockets
before we get to this one. But obviously hear thoughts
and comments.
I think we need to request information in this case
to determine what specific amounts if any are tied
to federal funding for broadband service. Broadband
versus normal telephone communication. Exactly. And again, I agree with
you, Commissioner Cobos. I think that drives at the heart of
the policy that has been heavily debated in the legislature
and here at this dais about what these funds
ultimately statutorily should be used for? You know
so we are somewhat constrained, and no, we're not somewhat
we are constrained in how those funds can be used.
And so we've got to be clear and so I would support
going back and finding out, getting more information.
Yeah, I think it's just a matter of due diligence to
be able to to get more information to distinguish what
the funding was for while we await action in the
other two cases that are addressing the same matter.
Fair enough. I'm good. I'm agreed. Is there a motion
to remand this case the docket management to obtain
that clarification from Blossom on whether projected
or actual federal USF reduction that includes support
for broadband service. So moved. Second. All in favor
say aye. Motion passes.
I don't have anything on #7. That'll take
us to number eight, please. Mr Journay. Item eight is
docket 50997. It's the application of Southwestern.
Electric Power Company to reconcile fuel costs. I will
note that Commissioner Cobos has recused herself from
this matte. Before you is a proposed order filed on
August 12th, reflect an agreement files in this case.
Commission staff filed some corrections. Those were
accepted by the ALJ by a memo filed on August 25.
Thank you sir. We've got a unanimous settlement in
this case but with an open question of the rate case
expenses. They're clearly recoverable but they're in a
black box and we can't see what they are or have
any backup information about, and we don't have an attorney
affirming the reasonableness of those fees. Thoughts?
Sorry. My thoughts are that SWPECO should have known
better. This is, this is not, this is a rate case
101, it's been in the rules for a
long time. They should know this. We should remand it
back and have them submit the documentation. I expect
they have it but I need a lawyer to do so to
follow our rules. Fair enough. Makes sense. So just
to understand, in these cases, the staff need to have
an attorney to verify this? And let me ask this
does staff and Rachel, you might, we might hear from
you on this, do we have the expertise on staff to do
that?
Darrell or Rachel?
Daryl's putting his work in today.
I may feel a bit inadequate after what happened earlier
Darryl Tietjen on behalf staff. Commissioners
if you're referring to staff attorneys opining
as to reasonable, staff attorneys opining to the reasonableness
of outside, of other parties legal costs, I can just
tell you that historically, that is not something that
staff has done. If ever, I think as I recall.
Good morning, chairman and Commissioners. Rachel Robles
on behalf of Commission staff and I can confirm what
Darrell was just saying about, we historically have
not done that, but that's something, if that's something
that you would like for us to look into, we're happy to
do it.
So yeah, it was, me personally, I am not an attorney
I do not have expertise in billings, so you know
so I wouldn't presume to do that. However, as for the
letter of the rule, are we confining this to the
way the rate case is filed and thus the petitioners in
that case? Is that kind of how we're putting this in
a box.? That's what that's what I believe. Okay.
And I would and I would follow suit on that. I'm just
trying to clarify in terms of proceedings for
staffs purposes, what we need to have in there and
okay. Yeah I think like Jimmy said this is rate case 101.
And we need more than just a CPA from
another state. Good to go. Alright. Is there a
motion to remand this case to Docket management to SWEPCO
to supplement the record with competent
evidence as to the reasonableness of its rate case expenses?
So moved. Second. All in favor say aye. Motion
passes. Thank you. Thank you.
Next item please.
Just to note, Item 10 was consented. Item 11 is the.
Item nine? Oh well sir, it's
my birthday. Free pass granted. Item 9
is Docket 51580, application of TMNP for a approval
of its wholesale distribution line service tariff. Before
you is a proposed order that was filed on July 16th.
Thank you. I think the proposed order broadly makes
sense. There's a question of date and all things considered
I don't see a lot of reason to move off of our
35 days as required in the rule. Total agree. Just to
confirm. So that will be January 7? January 7. Correct.
All right. Is there a motion to approve the proposed
order with modification to ordering paragraph one to
set the effective date to January 7, 2021? So moved Second.
All in favor say aye. Motion passes,
10 was consented and that will bring us to item number 11.
Item 11 is docket 51984, application of APTexas
to amend its DCRF. Before you is a
proposed order filed on August 13. Proposed corrections
were accepted by the ALJ by a memo filed on August 24.
Thank you sir. Again, I think the cost recovery seems
reasonable but it's another question of the
rate case expenses and the amount and reasonableness.
Again, lack of visibility, even more so in this case
and given that these expenses by definition end up
on the ratepayers, I would think we want to ensure
we have visibility to ensure that those rates are
costs incurred are reasonable and it's not a blank
check, blank check to burden consumers with costs. Agree.
Absolutely agree. And the parties need to comply with
with the rules with the statute. That would be a good
general principle. Right.
All right. Is there a motion to remand this case to
docket management to allow the cities to supplement
the record with evidence as to the reasonableness
of rate case expenses? So moved. All in favor
say aye. Alright, motion passes. I don't know if
you plan on taking up 12, 13 and 14. I've of course recused
myself. No sir. Not at this time please.
Alright, item 15 was consented. I don't have anything
for 16. Can I say something under 15 although we consented
it? The one question that I had which was I
was happy to see that staff had put something in there
about in our order about asking with these.
EMS systems, how well do they react in an emergency
situation? How can we understand better about cutting
off load and utilities can do this in times of
emergency. We know that this just happened but AMS
systems ought to be part of that solution and we ought
to have a better idea to understand why. So, I think
the fact that that question was in here is a really
good thing to say, to tell everybody that look, we want
to look at this through a lens of reliability and if
there's a reliability piece to it, we want to know
about it. Well put, another reminder that this
is the new lens through which we look at everything
is in the context of reliability and also a chance
to mention that you are taking a interest
and will be launching or taking the initiative on improving
segmentation of loadshed and granularity of response
during scarcity events. So, thank you for that. Alright
that takes us to Item 21 where I think we've got an
update from market. And then both Commissioner McAdams
and Commissioner Cobos have updates on their special
projects.
All right, good morning, Commissioners. Christie Hobbs,
Vice President of Corporate Strategy and PUC Relations
for ERCOT. Thank you for having me back to keep you
updated on what we've continued to see on the grid
this summer. Both from a demand perspective as
well as a generation performance perspective. First
thing we like to do is take a look back to last
week. We've continued to see a trend where we see higher
demand and wind output earlier in the week and then
we see that both start to taper off as we continue
through the week. Last week, our peak demand was in
the lower 70,000 megawatt range over the week and then
it dropped into the mid 60,000 range as we got closer
to the weekend. The renewable performance at beginning
of week, again at seasonal expectations. But we
did see that drop off towards the end of the week.
Where solar was, although solar was at 6000 each
day except for Sunday, where it dropped off because
of showers. From a thermal generation outage perspective
we've continued to see in the 4 to 5000 megawatt range
on outages throughout the week this week to date. You
know, we often talk about the tools that we have in
our toolkit as we were looking ahead to Monday, we
saw potential for higher than expected demand and lower
than expected renewable forecasts. We did call that
one of our high variability days and procured additional
reserves to ensure that we could adequately meet the
needs of Texans over that day. On Monday, we saw a
demand in the mid 71,000 range and wind was only at
the 3000, which was lower than seasonal expectations.
So using that tool in our tool kit did prove to be
beneficial. On Monday, as we moved into Tuesday the
last day of August, we actually saw the highest demand
of the season thus far on the system at 73,475.
At that time we saw about 5000 MW of wind and about
5000 MW of solar during the peak period. Yesterday
moving into the first day of September, we actually
hit an all time September peak. That exceeded our
previous peak, which was in September of 2019 by a
little over 3000 MW. And so that peak was 72,213 for
yesterday. Thermal generation outages so far this
week. You know, we've been in about 3 to 5000 megawatt
range, so consistent with what we see in the past couple
of weeks. As we look ahead to the next seven days in
our forecast today, we're expected to be in the mid
72,000 range for a demand perspective. Again, we've
got a little bit higher wind and the 9000 range and
about 5000 solar. We'll continue to see that trend
down as we get again closer to the weekend. And
as we get to Monday, which is a holiday, we're expecting
the load to be in the mid-60s, but then kind of come
back up as we get further into the week. From a
renewable perspective, we're also seeing that taper
down as we continue out through the week. So today
we'll see about 9000, we'll get into the 4-5,000 range
over the weekend. And then as we move into next week
actually, we'll see a low on Tuesday in the about the
2000 megawatt range from a wind perspective. From a
solar perspective, we're expecting to see anywhere
from 5 to mid 6000 range as we look over the next seven
days. So as I close out again, you probably tired of
hearing the repeat button, but we commit to you
that we're going to operate the grid more conservatively
to do whatever we need to do to make sure that we're
ensuring a grid reliability for the people and businesses
of Texas. Whether that's securing more reserves
or we're bringing them on earlier. So that we ensure
that the grid is reliable. I wanted to look ahead
to future reports. I know your memo, Commissioner Cobos
had us coming back the first open meeting in October
to kind of give you a look back a summary of the
summer performance, but recognizing that we're still
you know, in the higher range of demand through,
you know, the next several days at least in September
would like to offer if you'd like me to come back to
your September 23rd open meeting can give you an update
again as well, similar to what we've been doing and
then to also see if you know, whether you would
prefer to get that summer wrap up at your first meeting
in October or if you'd like to look to one of your
later October meetings or we may have some additional
data available as we look back and analyze this summer.
Yes. And thank you Christie for asking those questions.
In response to your first question, Yes, please
come back for the September 23rd open meeting and give
us a grid update. With respect to your second question
on the summer performance review I think it would
be best to come on the October 7 open meeting to
give us the review and and some highlights of the summer
but also to have market staff provide us with a
update as we enter into the shoulder months and
we have maintenance outages and there's sort
of an operational update on what we're looking at
as we enter the shoulder months and how ERCOT plans
to be prepared during that season.
Questions, comments for Christie? I just had one question
and that was on thermal outages, were with the roughly
5000 MW was most of that planned or how much of
that was planned versus unplanned? Those are unplanned.
Those are all unplanned. For context. I think 4-5,000
is what we saw this last weekend this week. That means
that the thermal fleets are running at 95%
of installed capacity is running. For context
4 to 3000 of wind to 5000 of wind is 10
to 20% of installed capacity for context. My thought here is
obviously, you know, the renewables were subjected
to the environment to produce those and thermals were
not you know, I know these are complex machines
their maintenance schedules since I'm
new to the Commission, I don't know what the maintenance
schedules are. I hope we are, you know that they are
doing preventative maintenance, they'reon maintenance
schedules that don't affect the market as much as they
can. If we can prevent some of these maintenance then
perhaps we won't have 5000 MW in the wintertime or
in the summertime offline during the weeks that we
need it. So I think mine is an appeal and an encouragement
to make sure that these companies stick to their maintenance
schedules, do predictive maintenance, make sure that
these plants are ready and available for the people
of Texas because we need it. Absolutely. I know Commissioner.
Cobos is focused on that issue as well. So I think
we, the rest of us fully support,
intense focus on maintenance
in sync with reliability for sure
and I know you mentioned this, Christie but it bears
repeating that the forecast variability reserves that
have been procured as a new change. And one of the
primary ways in which ERCOT is managing the grid more
conservatively as opposed to the past we're now taking
real time conditions, weather conditions into consideration
instead of relying on whatever reserves were just set
a year ago. That's a tremendous difference
in the way we're managing the grid and as you said
has made a difference in stabilizing Texas for the
summer. Thank you.
Thank you. Thank you.
All right. We have Commissioner Mcadams and Commissioner.
Cobos, updates on their projects.
I'll kick her off. I know you have a robust presentation
so I'll let Will go first. So in line with
that, not to steal too much of the thunder from the
upcoming workshop I think I want to highlight that
much of our discussion over the past months has been
focused on the supply side of our reliability equation
in ERCOT, how to incentivize new generation and what
the mix of generation we actually need is. I believe
it would be also beneficial for the health and reliability
of ERCOT market to look at the demand side of the
equation and hence our DG look. At the September
16 workshop as I said we're gonna take a deep dive
into it and have good panelists to discuss a lot
of the issues that I'll cover at a high level here.
First there are two categories I believe of operational
demand response administered by ERCOT. First there
are over 600 industrial load resources that participate
in ERCOT's ancillary services and real time energy
markets. And those resources account for around 7000.
MW of registered capacity. This is a resource that
I believe we need to continue to foster. They
can participate in huge chunks and provide real time
tools for ERCOT to call upon. Additionally, the Emergency.
Response Service Program procures about 1000 megawatts
of qualified loads and generators to make themselves
available for deployment in an emergency situation.
Now of that 1000 MW, 300 of this is provided by distributed
generation resources which we'll hear more about now.
We've seen a number of comments about ERS recently
and appreciate the input from stakeholders and those
comments. I think it behooves the Commission and
we need to evaluate section 25.507 of TAC to determine
if waiting for EEA conditions is the right time
and the appropriate way to deploy ERS or if in the
interest of maintaining a reliable market as we have
repeatedly said they should be deployed earlier.
And this is kind of a broad policy topic. So if we
want to engage right now and just sort of talk about
it war game, you know, we can do that but I
think this is one of the significant policy issues
that we're gonna be considering going into November.
Especially right now as, I keep on referring to this but
we're kind of at war with the army we have. So it's
a significant tool. Second the TDSPs administer
load management programs to reduce demand during the
summer peak for commercial customers that have chosen
to participate in the program and have signed up. Typically
these programs make up about 400 MW available to ERCOT
for when grid conditions tighten. I believe the Commission
and the TDSP should consider potentially expanding
these programs to the rest of the year and reevaluate
what the threshold for deployment is. It's currently
an EEA 2 and I think it may be beneficial to
deploy them earlier. Again with that theme toward
reinforcing our reliability conditions before we get
to physical scarcity. I also think we should take a
look at energy efficiency
cost recovery factor programs currently administered
by the TDSPs. Now I'm not gonna go
into detail on these because we have several dockets
that are gonna be before us potentially in the near
future. But I will say this consistent with the
theme we've repeated throughout this market design
process. I believe we should encourage performance
from these programs. Finally there are additional
categories of economic demand response that are not
administered by ERCOT. These include customer driven
demand response and cost avoiding load reduction programs.
Both play an important role in maintaining reliability
of the grid and have accounted for ballpark 3000 MW
of reduced load on peak days. So all of these categories
are going to grow in importance as demand inevitably
increases in Texas. And I know I've had meetings both
with stakeholders and staff and I'm sure the rest of
you along the hallway have as well. But data centers
and cryptomining organizations are growing exponentially
in Texas and they, I mean we're talking about sites
that have 3000 megawatts of load that can be turned
off almost, you know, instantaneously when called upon
and that's going to be a tremendous resource for ERCOT
as the resource makes changes and evolves. So we need
to be watching that mindful of it. And when
we consider things that give them economic and capacity
signals. So then I'll kind of walk into DDG, what
we're finding there. The reality is that even before
the winter storm, homeowners and business owners in
Texas were already in installing distributed generation
resources like solar, rooftop, solar batteries,
gas and diesel fired generators at an increasing rate
and since Yuri, those numbers are only increasing
exponentially. I mean, I think we're gonna have some
astounding figures from ERCOT in the next year, two
years on what's on the ground out there as they
register these things. We have the opportunity now
to figure out how to best deploy these resources
along with batteries and all other DG resources in
a way that enhances reliability and flexibility for
the grid operator. Now this comes with significant
challenges and I'll just sort of articulate what kind
of buckets those fall into. Compensation obviously is
gonna be one of these that we need to look at.
How homeowners and business owners are paid for choosing
to deploy these resources on their roof oor their backyard
and how the transmission and distribution service providers
the utilities are compensated for managing these resources
on their systems, and this goes for ERCOT and nonERCOT
utilities. Same conditions apply. We've also
heard that I'm sure we'll continue to hear from stakeholders
about the need to clarify and reform the interconnection
process for these resources. The devil is always in
the details. We've asked staff to open rule makings on
the topic and and they are moving forward on DG,
and I think establishing an interconnection template
through this process is going to be very useful.
As a part of that proceeding and we're gonna have several
meetings with non ERCOT utilities in the coming weeks
to sort of gauge what they're, what they must have and
I think it's going to be consistent with what ERCOT
is already talking about that, command and control capability.
Aggregation, as to the question of how to aggregate
how to employ those aggregated resources and even who
can aggregate is going to be something that we're gonna
have to address in the coming years. ERCOT has been
looking at these issues already and we'll need to
continue that process and finally command and control
as we all said in the recent workshops, we need to be
able to fully take advantage of opportunities of DG
and we need ERCOT to have the ability to predict
how they're going to perform and when they're going
to be available. And then that will feed into the
programs that we develop in the near future. Ultimately.
DG should not be a replacement for existing generation
but it should act in concert and complement the generation
fleet that we have, and as I said, we've asked staff
to open rule makings on the topic and we're looking
forward to the input from stakeholders that are rolling
in even now. Now, let me just before I turn
it back over to you sir, let me give you a high
level overview of Southwest power pool. So SPP manages
an electric grid and I know it's very familiar to you.
Commissioner, that is a wholesale power market in the.
Central US. SPP has 14 states currently and I'll lay
those out. Arkansas Iowa Kansas Louisiana Minnesota
Missouri Montana Nebraska New Mexico also North Dakota
Oklahoma, South Dakota and us and Wyoming. Now in July's.
SPP board meeting, they approved the terms and conditions
of a potential expansion into Western states that
which may occur in 2024. And that expansion will likely
include the members of Arizona Colorado, Montana Utah
and Wyoming. And this is in a renewable resource
rich belt of the US where transmission costs are, I
mean, Commissioner Glottfelty can talk about this
ad nauseum. I mean, it's a major issue. It's
also setting up regional divides, load versus resource
who pays all the same kind of issues, how to reliably
administer the variability of the new resource
rich regions. Now, like most ISOs SPP is conducting
thorough reviews of how to do that. They even as part
of a winter storm Yuri, they sent recommendations up
to FERC that very much mirrored Senate Bill 3 and
the various components of that legislation and how
to address reliability, and in system wide outage events
although it has a lower percentage of renewables in
the generation mix than Texas, 33% compared to our
50% here in ERCOT or close to 50%. I don't want to
cross any magic thresholds on anybody today. The
tension between intermittentcy and dispatchability
is of concern there as well. And many of the Member
states have strong wind production profiles as I mentioned.
Towards this concern, SPP has undertaken an initiative
to study the effect of requiring intermittent resources
to offer a certain minimumum level of commitments related
to their forecasted generation output in the day ahead
market and I have proof. And towards this end SPP.
Market monitor performs some initial analyses and found
that when intermittent resources cleared their day
ahead positions closely to forecasted amount
the SPP market benefited as a whole. Now again
it's not apples to apples and I'm not asserting that
here. There are unique elements to SPPs market
design that are distinct from ERCOT and they are also
solving for issues with price divergence which they
have which we don't necessarily have. Our forward market
day ahead market projections pretty closely conform
on an average basis in ERCOT. However, I believe
it will be worth monitoring this initiative because
they're gonna be conducting a lot of similar analyses
on how these resources perform and could comply
with a broad high level policy requiring intermittent
resources to participate and they had market
at a minimum level and thereby encouraging them to
hedge some of their risk. They're intermittentcy
creates may well be a viable path to addressing
concerns that a high degree of intermittentcy creates.
And with that Mr Chairman I will turn it back over
to you.
Thank you. Commissioner Mcadams. That was thorough
and informative. That's very helpful, appreciate
the work you put in on that. You touched on some
very very important topics. Obviously the SPP
efforts to reconcile renewable with reliable are similar
to ours, different mechanisms how we get there, but
a key issue for them as well.
I'd also highlight what you mentioned at the top
of your presentation regarding ERS and TDSPs
reserve deployment being constrained within EEA
And I think that's a relic of our crisis based business
model that we certainly need to move away from. I realize
there's some contractual obligations around those existing
programs but going forward, I've absolutely believe
we need to move those reserves out of EEA. So we
don't, we get away from this position of not being able
to access the reserves we need until we are deeper
in crisis. Yeah, I fundamentally believe that, I believe
that's the instruction from the legislature of the
policy makers that and the people of Texas that
they work for and thus we work for. I believe we've
got to move our tools out of this very sequestered
you know, paradigm into, in a preventative
mode, you know, it shouldn't change the ultimate outcome
for resources in a competitive market. It should simply
take physical scarcity out of the
mix. Okay. And there's nothing in the laws of economics
or physics that says scarcity, physical scarcity should
should be the driver of price. You know, you can
create that artificially and I know people are gonna
wig out and get very uncomfortable about that concept
but at the end of the day, ERCOT was always predicated
upon there was gonna be physical pain on the other
end of these prices. But you can signal to
the consumers of Texas that they need to
turn down their thermostats through high prices. That
was a driving force in many of the policies that
we've considered over the last 15 years, 20 years.
So I mean, if that's through the scarcity pricing mechanism
that conversation, I know that ERCOT is in
a little bit of a, you know, they're transitioning
to the new board structure, the new governance structure
stakeholder processes are gonna try to conform to this
new governance body that they have. But I think we
need to start this conversation sooner rather than
later because it's going to be important in the shoulder
months going in and it certainly will be in all of
22. Absolutely. Thoughts? So appreciate your
research, your input, your thoughts on this, I think
you're saying the right things leading us the right
way, these are issues that we have to address again
reliability. First, the beauty of demand response
and energy efficiency programs are they affect price
also if they're used at the at the most opportune time
which is the highest peak, then guess what? They solved
a reliability problem and they help the price problem.
So they're really good. This transition in this electric
industry has been going on for about 30 years now.
The original demand response programs were interruptible
rates that industrials had that was it. And we
use them very infrequently. But as this
market has grown to different players, different
financial models, we can call on them, we can call
on the residents, we can call on the aggregators, we
can call on all of these different entities that
are, that can provide a demand response as
long as one thing happens and that is ERCOT knows
that it's there and we can't put ourselves in a position
where we give them the tools to call something that
never shows up. And I don't think that's the case
I think those that want to play in the demand response
market will play in the demand response market and
they will be there. It's an economic decision. It is
valuable, and the same thing
with distributed generation, it's obviously coming
it's here, we gotta adapt regulatory rule
makings and such are many times way behind the market
and moving forward with adapting that, whether
it be interconnection or you know, visibility.
It's critically important I think that we
get a better understanding of how the system works
for reliability, the people of Texas and
DGs here. We just got a better understanding and
make the rules adapt to something that can provide
value again on an economic basis and on a reliability
basis. Thank you for your work. Agreed. And to echo
what what you're saying Commissioner Glotfelty.
DGS here, demand responses is also here and I think
in order for ERCOT to be able to use it effectively
they need to have visability into the benefits of
both. And as we know ERCOT operates at a transmission
level basis but getting, gaining more visibility
into the distribution system and perhaps the D. G.
Interconnection standards will move us in that direction
to gain that visibility so that ERCOT knows that those
resources are there to count on for reliability and
then also to Commissioner Mcadams and a great job at
extensively looking at all those very important issues
and with respect to the ERS program and the TDU
load management programs I think it's important to
evaluate how we can use those earlier in our
operations and we've received feedback on E. R. S to
some degree and really trying to understand what moving
it up and gaining the benefits from using ERS earlier.
Also the TDU load management programs. I'm glad you
touched on that. That is a directive on SB3 that
the legislature wants us to look at to see how we can
better utilize those programs during times of tight
system conditions and even an emergency. So I'm
in agreement. We need to start taking actions that
are preventative rather than reactive to were already
in the brink of emergency procedures are literally
in them. And so thank you very much for your update
I think you highlighted some very important information
that we need to continue to to look at.
Well put. Well, thank you for the hard work and I
know this effort will continue with our next work with
the upcoming work session and I know you'll be deeply
involved in the preparation and that session given
the work you put into this and I appreciate all of
your comments about the fact that we need to embrace
these new capabilities that we didn't have 30 years
ago, embrace the technologies that enable us to be
more reactive while also establishing the same metrics
of reliability and accountability on the demand response
side, that we're in the process of establishing on the
supply side. Thank you again. Commissioner Cobos?
You're up. Yes. So thank you, Chairman Lake. So
per your request at the July 29th open meeting, you've
requested that I evaluate options to accelerate transmission
development to address congestion and ensure reliability
in the state, including exploring DC ties to our neighboring
regions. Over the last few weeks, I have engaged in
numerous discussions with a number of stakeholders
and done some extensive evaluation of these important
issues and also gathered information at our work session
that we had in July with the transmission distribution
utilities that I think was very helpful to address
this. This very important issue that you've highlighted
that I think has been the directive from the legislature
and also in the Governor's letter. And so as I tackled
this project for, there's sort of the acceleration
of the regulatory timeline issue and what we can do
as a Commission to shorten that regulatory
approval timeline process and then also ways we can
address the concerns that I have heard from the transmission
distribution utilities out there, with respect to
the timeline between when transmission is built and
when customer load is cited, which is often referred
to as the just in time transmission development issues.
So I will touch on those two pieces and then also
address
Senate Bill 1281 which contains some very important
matters in there with respect to evaluating economic
and reliability criteria and move over to specifically
addressing the Rio Grande Valley which I know has been
about most importance and attention from
ercot and others. And then give you some broad information
on the DC Ties, so with respect to the regulatory approval
timelines. Before you dive in just for the record, you
filed the memo on this. I did file a memo, yes.
That's what we're referencing. Yes, thank
you for noting that. So I filed it under agenda
item number 21 and so, essentially as you look at
the regulatory timeline as it operates today, projects
that require a CCN are tier one and tier two
projects and tier one projects are transmission projects
that are equal to or greater than $100 million. And
Tier two projects are projects that are less than $100
million but still require a CCN from us, from the Commission and that's
typically when you're right of way is needed. And so as
a tier one and tier two project, you will go through
the ERCOT regional planning group process which is
a stakeholder group that evaluates these projects.
It's a nonvoting consensus based group that evaluates
the project, studies the projects and with respect to
the timeline that that study review is conducted in
there are some efficiencies that can be gained there
with respect to having the TDUS, the transmission service
providers rather and ERCOT conduct the studies in parallel
to save time or having ERCOT and the TSP's conduct
the studies together. ERCOT has explored a concept
of sending ERCOT staff to the TSP's locations to work
in concert together, to develop the studies. However
obviously the pandemic and staffing issues have kind
of put some impact on that concept, you know
ERCOT I think has staff resources of transmission
planning group that is dedicated to working on these
matters. But you know they, in order to speed up this
process from an ERCOT individual independent review
standpoint, I feel that they feel that they need more
resources to be able to speed that up even further
than it is right now and then also with the studies
you know to parallel or do joint single studies. So
those are the sort of efficiencies that can be gained
there when projects are
evaluated through the RPG process at ERCOt. Now projects
don't have to go through the ERCOT RPG process. The
Commission has statutory power under PURA to order
the construction of transmission. There are specifically
three different provisions in PURA that allow for the
Commission to take that action and one specifically
applies to the exact issue that we are looking at
right now which is to order transmission distribution
utilities and electric utilities to build transmission
projects to ensure safe and reliable service in the
state and reduce transmission rates at ERCOT.
So can't skip the ERcot RPG process altogether and order
the construction however, those projects will still
need a CCN. So with respect to our timeline whether
the transmission project goes through the ERCOT RPG
process or not, CCNs to be issued under PURA
for these projects and there are three timelines,
it's within one year from the filing of the date of
application for regular reliability, economic and even
D. C. Ties and for projects that are deemed critical
for reliability, that is 180 days from the filing date
of the application and projects that are deemed critical
for reliability by ERCOT, there is no set procedural
criteria rather in the protocols or guides. It's
basically determined by whether or not the project
needs a CCN. The project is reliability driven and
without that designation of critical for reliability
that line wouldn't be built in time to address the reliability
need. So but with respect to our broad statutory authority
under PURA to order the construction of transmission
we would issue out of CCN within 181 days from the
filing date of the application. So those are the timelines
that are associated with the regulatory approval process.
So once a utility files a CCN application at the Commission
then there are additional efficiencies. Procedural
efficiencies that we may want to consider to shorten
that approval process. And so as you see, I've listed
some examples of procedural efficiencies that would
help shorten that time line from our CCN approval process
to more efficiently and expeditiously process the
CCN application. So I've listed some eight examples
that I think are worth considering. They're allowable
under our procedural rules and there are other
aspects to efficiencies that we can explore. But these
are the main examples that I think I just wanted to
kind of stick to for now.
And I can work with Commission Advising and you know
look at what we can do here. But basically essentially
the goal would be to for the Commission to take more
of a hands on direction on the procedural schedule
when we refer those cases via an order or referral
to SOAH. inserting more direction so that SOAh
inserting more directions at SOAH< so that SOAH can develop
a procedural schedule that complies with our directives.
So to clarify, basically put shot clocks on SOAH.
Put deadlines on SOAH, put guard rails on SOAH
Because typically whenever we refer a case
to SOAH it's just an order referral and the parties
developed the procedural schedules, right? So we would
have a more proactive role in our order referral of
putting parameters as to when we want things done and
obviously, you know, working with Commission advising
and would have to engage with SOAH and work with SOAH
so they understand what we're trying to get done. Obviously
they have their own schedules and how they address
matters over there. So they would need to hear from
us and we would need to to work with them in trying
to get them to work with our expectations. So what
does that look like? Just, you know, I don't want to
spend too much time in the details here, but that is
essentially requiring prehearing conference dates
to occur earlier, with a certain number of days
after the order referral. Maybe it's a week after motions
to intervene. Typically that, well, the deadline is
typically 45 days from the filing of the application.
Shorten that down to maybe 30, having technical conferences
so that the utility can address common RFI responses
shortened discovery deadlines, short briefing deadlines.
Just a host of things that we can do to make the
process more efficient, essentially. And how we do that
is plugging that into our order referral. And you know
that's that's one way to tackle this issue from our
standpoint and I can, if you all are comfortable
with this work with Steven and his group and
determine, you know, where we can add these obviously
in the order referral, but making sure that, you know
from our standpoint, we're also comfortable with these
timelines. And Stephen is looking at me kind of interesting
on, on his birthday with his mask. So I did, it seems
like I really do need to work with Stephen on these.
So that's essentially how we can
tackle the regulatory approval process. Either you
know, we can make some tweaks have ERCOT, give
some directives to ERCOT on study efficiency
making sure they have enough resources, we can on our
end, on the CCN approval process, have more directives
on our procedural direction in our order referrals
to speed up to gain efficiencies there and shorten
help shorten that timeline which are the little knobs
we have or we can utilize our broad statutory authority
and order the construction of transmission which would
still need a CCN and we could still turn the procedural
knobs to hasten that process so that's the acceleration
of regulatory approval process aspect of my memo in
response to your request, Chairman. And I'll pause there
to see if you have any questions before I move on to
this next topic. Thank you, Laurie. I think the most
important thing I heard out of a lot of good information
was the ability of this Commission to utilize its broad
statutory authority to develop transmission sooner
rather than later to solve those bottlenecks that we've
got in this system. I think we got very clear and robust
direction from the legislature and the Governor to
use all of the tools at our disposal to solve these
problems sooner rather than later. So I think that
is incredibly important point. Thank you for highlighting.
Yes. So in consistence with Governors bullet number
four order ERCOT to accelerate the development
of transmission products that increase connectivity
between existing or new dispatchable generation plants
in areas of need. So the reliability condition is clearly
clearly conforms to that direction. Shot clock's
yeah, timelines, whatever, going back to my telecom
stuff. Yeah, no problem with it. I mean, clear expectations.
I think it would benefit us to have a set structure
for these reliability designated projects.
Within the parameters of that need. So I think we would
get a lot of juice out of that.
It's an authority that the legislature gave us, provided us
and I'm not sure it's been exercised at all or very
minimally in the past. And it specifically states that
ordering transmission construction to ensure safe and
reliable service and to address transmission constraints
if they are not being addressed through Chapter 37
the regular CCN process and out of ERCOT through
stakeholder process. So I thought that provision was
very, very much focused on what we're looking at right
now. It sounds like we need to start using it. So all
right. So moving on to the other important topic.
Senate Bill 1281 which was passed this past session.
It contains various provisions that I think we need
to consider with respect to timing and direction to
market. The bill contains new economic criteria
test. And so it's essentially what most people are
calling a new consumer benefits test. And, one point
of discussion I wanted to have with you today was whether
or not we wanted to move it based on your statutory
interpretation or whether or not we wanted to move
forward with directing market to start using that criteria
before rulemaking is conducted at the Commission and
I know staff has it for discussion at the beginning
of this next year. And I'll also add that, you know.
ERCOT did say as they communicated to me, was that
if they were directed to start using that new economic
test, that they would have to make some adjustments
to the model and train some staff, but they could do
it within, you know, 23 months and be ready to use
it while they await the Commission to put in the rule.
However, they would have to have 2 questions answered.
And that is whether the Commission would want ERCOT
to continue to use both tests, both the existing production
cost savings test and the new consumer benefits test
going forward. Or does the Commission want ERCOT
to just use the new consumer benefits tests going forward
They're currently reviewing projects under the existing
production cost savings test that's in, well, that's
required by the statute but specifically described
in our rule. But they would like to know from
us what our expectations are on the test and then also
how many years of benefits with the transmission
project need to show to be able to pass the test, the
new consumer benefits test right now. On average
for the production cost saving tests, the project
would have to show about six years of benefits for
it to pass the test. And so they would need to know
the timeline for the benefits for that new test.
I'd like to hear your thoughts on this. Which part? Start
at the top. Broadly, but then also on this kind of flow
chart decision that we've got to come to. Well, I
guess I have a lot of thoughts and
first of all, Commissioner Cobos, I want to say a great
job. I mean, I think we don't have all the tools in
the toolbox, but the ones that we have, we need to
use and we need to use expeditiously and I think that
all of us agree with that and it's really how we're
gonna make that happen which is kind of the critical
path item, both on projects that have been filed and
approved and ones that are, you know, sitting here
or sitting at ERCOT. I won't pick on ercot, but
I've historically thought that ISOs and RTOs
are places where transmission projects go to die because
their projects-- At least I didn't say at this time. Right.
They take too long. Just in time transmission is like
highways, you know, we're in Austin, everybody knows
just in time Highways on I-35, it doesn't work. It's
if you want to sit and park there and there's an economic
and a reliability consequence and how we exercise this
authority to order transmission built, I think is a
great tool to have. I think we need to have some deep
discussion about how we find what tools we use to figure
out what we want to order. Is it modeling congestion?
Is it a reliability report from ERCOT? Is it
entities coming in here and telling us what they
think we need that may be economic, there are lots of
different ways, and it shouldn't just be, in my
opinion, it shouldn't be just ERCOT telling us one
thing. They have a perspective, a bureaucratic perspective
at times and we want to hear from everybody
in transmission development in a lot of places
around the country, time is of the essence.
I think the legislature basically made incumbent the,
gave them their role to build transmission in this
state and where competitors in that space can play
I think is pretty limited and that's their decision
not ours, but for rates, we gotta make these process is
quick and predictable. And there are some things that
they do at the federal level in terms of environmental
reviews where you file a lot more information up front.
And they have predictable time frames
and the proceedings are understood and the outreach
to affected landowners is early in the process, not
late in the process. All of those things are really
good and make it more predictable for us to meet that
timeline to get these projects through the CCN process
quicker. So those timelines I think are absolutely
right. You know, we gotta hold the CCN applicants
feet to the fire to make sure that the notifications
are done accordingly, that and I'm not sure how
many routes have to be filed if there are alternate
routes for these projects, but sometimes in different
regions you have to file a preferred route and an alternate
route and that makes things harder. The
fact is that we have control over the rulemaking
process that, I'm sorry the CCN process that
we ought to make it, we ought to make it fair,
predictable and have a very, you know, the outcome
when it's going to happen and give predictability
to the industry so that we can we can make that happen.
I think the one other thing that I would say is
well, two other things. First of all we're gonna get
into DC ties and I think that's a little bit of a
different animal and I look forward to that discussion
as well. But there are also things that can help expand
our transmission system that are not just new transmission
lines. So there are new technologies that are actually
getting older, technologies that deal with dynamic line
rating and things like this, that are technological
sensors that can be put on conductors to determine
heat, wind speed, you know, how much throughput can
happen right now, it's done through an algorithm, you
know, how much based upon contingencies, how much energy
can flow through a line reliably. If there are
technologies out there that can ensure more throughput
we should encourage the utilities in our
state to look at them, to utilize them to report to
us on how they work and that's a valuable. It's
not building transmission lines, but it's better utilizing
existing transmission lines and existing resources
to their fullest extent. And then the one last thing
that I thought was part of this memo, you know
I don't know how much transmission has been built in
this state within ERCOT that was built for double
circuits but was only constructed to a single circuit,
it might be a very, very good exercise for us to
better understand that it might be nothing, it might
be a few miles, it might be a few 1000 miles, but
if you're not buying new rights of way and you're not
forcing a landowner to get into that engagement
and it really is putting additional conductors on existing
towers, it might be something that we can expedite
quickly. And there may be some other bill that's
necessary, but that's not too hard. You're still
building mostly on existing rights of way
and as we want all of our resources to be available
all around the state, that's what increases reliability.
You can probably tell I'm kind of a transmission construction
guy. I like transmission because
it provides reliability and it increases, it lowers
economics, it is the highway for commerce of electrons
and many, many years ago when the utilities vertically
integrated, utilities were building nuclear plants
and big coal plants, they were always chastised for
building for gold plating their system, they were putting
in higher voltage transmission lines than they needed.
They were building too much lower voltage transmission.
The fact is that none of that is gold plated today
100% of it is used.
So gold plating a system maybe a buzz word of the past
but it's all gone. We have to think forward looking
we have to think about higher capacity lines, maybe
you know, I know Ercot has 345 lines, but 500 kV
lines, 765 lines. There are huge values to those technologies
that we should continue to look at. And anyway,
I'll get off the soapbox, but I think you've
done a great job and you know, I agree with the
way that you're going, knowing that we need to use
the tools in our toolbox and we need to be expeditious
about doing it. Thank you, Commissioner Glotfelty.
I really appreciate your perspective, I know you
have extensive experience in the transmission construction
industry and so, you know, I heard a few things
from you and I think one is, you know, economics and
reliability. I think it's it's very important to note
that as we look at economic transmission projects that
we address those in an efficient manner because if
we don't address the economic aspect of transmission
construction development, then these projects ultimately
turn into reliability projects. So that's something
that it's just the fact. Right? So, you know, and that's
why I wanted to bring up the economic criteria test
the new test that was passed by the legislature.
Because I want to make sure that we are thinking about
whether based on the statutory interpretation, that
of that language and that was passed in SB 1281 that
we are thinking whether we should be addressing whether
we should go ahead and have ERCOT start reviewing
those projects without a rulemaking, move up the rulemaking
make sure that we're thinking about the economic
test and how were how the new one and how, when and
how we're going to use it, so that we can
start looking at projects under this new criteria that
the legislature directed us to utilize. So, one
thought on that, I mean, the consumer benefit test
which is now part of 1281, it wasn't a foreign concept
I mean, they had done this in the past. I mean, it
changed during the Great Houston import project battle.
And so it's not like this is an alien thing that ERCOT
would consider. So I think now again with the overarching
policy goal of reliability that we needed. But there's
also this happy medium. I mean Texas consumers, I think
we recognize costs are going up. I mean energy costs
are gonna go up. Load is growing like crazy, everything's
electrifying. You know we're gonna have more
security within our system and and I'm saying we're
not going to have a capacity market but I am saying
that costs are going to go up but they need to go
up in a managed way, in a prudent way, transmission
costs included so that consumer benefit test harkens
back to another day of ERCOT to where they did have
it, they did evaluate it, they could employ it. Now
me personally, I think I would, you know say move forward,
you know if this is the choice before us, use it,
start employing it and then we'll we'll formalize
the rule. And so ercot would prefer to be able to use
both tests to continue to use the production cost savings
tests and the economic test because they accomplished
two different. They do accomplish two different but one is a weight.
I mean one is that kind of-- Well one of them I
guess there's there's a production cost savings tests
and that's just moving around cheaper generation to
other parts of the state. So that would address areas
like West Texas with the constraint solar and then
the new consumer benefits test is a way of addressing
helping high demand areas get cheaper generation.
Dallas vs west Texas. So in one hand production cost
savings, addresses generation slash congestion pockets.
And on the other hand, the new consumer benefits
tests or consumer cost savings test, however you want
to describe it would address load pockets. So they
accomplish two different tasks.
So their preference would be to keep the consumer,
keep the production cost savings test but then also
start using also use the consumer benefits test. And
that's something that they would like. That's
their preference but they want to know from us how
we want to move forward. With both tests or just one
test? I'll tell you what I'm, as both of you have been
going through your presentations and the spirit of
moving as fast as possible, per legislative direction i'm
making an action item list and one of the items is
to if you're willing to work with ERCOT to come
up with a menu of the different versions of analysis.
One of the tests only, both of the test, the other
tests only, pros and cons of each or any other options
that are out there. So we can evaluate that as the
Commission and see the full range of options, know
that, get some insight on what works, what doesn't work
on each one and make a decision from there. Does that
make sense? Yes, as long as it doesn't take too long.
As long as the market analysis doesn't take too long.
No, no, both the laying out the menu of analysis tools
and about the next. I trust Commissioner Cobos that
won't take too long. No, I'm sure I will work with
them to determine that information to get that information
from ERCOT for you and I can report back on the
next meeting. I don't think it's gonna take too long
to get it from the, or sooner, the work session
if you, as soon as you can get that menu of different
options on how we can evaluate these new transmission
projects, the sooner, and if you want to, as soon
as you get it, feel free to follow a memo.
So we don't have to wait an open meeting for the rest
of us to see it. Right, right. I mean, and to be
fair, I think really, how do you address that? There's
two ways of looking at transmission projects. It's
either the reliability lens or an economic lens and
the economic lens, you have economic criteria that
you look at it right now. It's production cost savings
and then the new tests that got passed by the
legislature. So there's really just two lenses to look
at economic transmission projects that exists today,
one that's already in rule that coincides with the
past statutory language and then one that is new because
1281 passed. So
that's pretty clear cut for me. So I'm not real sure.
So we're going to do both of them. We want to use
both of them or do we just want to use the economic
reliability or the economic criteria? If we're going
to use both of them, how do we weight each of those?
Are they equally weighted? Are they one weighted more
than the other? So there's a spectrum I think of how
we implement these and run that analysis. So let's
let's get the fine print from ERCOT on what the pros
and cons of each one of those scenarios look like.
And I don't, I don't know off the top of my head
what any every one of those scenarios is. But let's
see the fine print. So we can evaluate it. We
want to do that quickly for Jimmy's point, but let's
make sure we've got the full spectrum and stuff. Maybe
a version of those tests that we're not thinking about.
Okay, it would be good to see that. And then we can
move quickly from there. Yes. Okay. And I look forward
to hearing their reasoning behind this. I mean
at the end of the day we're not in the business of
protecting little generator fiefdoms in these
these pockets. You know, we need to relieve this
pressure. We need to get cheap power and frankly it'll
be better for reliability purposes as well for us to
be able to have a fully well integrated system that
can be managed, you know? So yeah, I'd like to
hear their rationale behind this. Okay, I will work
with you to provide additional information on that
issue. The other portion of that legislation I think
we need to address is the additional reliability criteria
that was included in there. And I think that language
is straightforward in terms of load forecasts, historical,
actual and additional load forecast. And we need to
consider whether we want to try to start utilizing
that now without a rulemaking, and also to add that
a couple of things to that that I wanted
to highlight that addressed the customer load forecasting
issue. And that is to highlight that ERCOT currently
has boundary thresholds that are based on weather zones
throughout the state. And what that means is that ERCOT
comes up with a customer load forecast. A TSP comes
up with their customer load forecast and if the TSPs
customer load forecast falls within certain
percentage range ERCOT will use theirs. So,
throughout the state it was five and recently in the
last couple of years ERCOT increased that percentage
from 5 to 7.5% for the far west Texas zone, all the
oil and gas development that was going on out there
and what that allows is for by adjusting that percentage,
you're able to account for what the TSP's are seeing
on the ground versus what ERCOT sees. So, that's
something to consider, I just put that out there
in terms of, if the Commission wants to give ERCOT
a directive to look at those issues because
right now, as I noted, it's 7.5% for the far west Texas
zone and I put it on a map in my memo to
highlight how the different zones are broken up throughout
the state, to see if that boundary threshold
should continue to be 5% in certain weather zone throughout
the state. Do we need to increase those so that
we can sort of help manage the disconnect between transmission
development and customer citing. So it's my understanding
that when they increased the 7.5% out in far west Texas
that did actually send some additional transmission
construction. So have ERCOT include that in the menu
of options and how we integrate that into the analysis
of new transmission projects, pros and cons of what
different, those different metrics, different
recipes on how those can be combined and integrated.
It may be multi step, one test first and another. I
would love to see some options and suggestions and
I would even ask them to go one step farther and pick
an existing or a proposed transmission project, whatever's
most ready baked-- --as an example-- --as an example and run
through each of the analysis scenarios. So we can see
a real example of how those different tests would
work on a real project in real life. So yes. And
one thing before I move on to the next highlight
is that as I visited with the numerous stakeholders
obviously took a tour throughout Texas, two different
service territories of the TSPs, what
I learned is that there are certain TSPs out
there that within their service territories that have,
that are experiencing tremendous customer load growth.
I think in general our whole state is, right, but
obviously the most populous areas are with respect
to just customer business citing. Industrial customer
citing. And so perhaps as we have ERCOT evaluate these
boundary threshold issues is to maybe focus on certain
areas that are experiencing tremendous customer growth,
load growth and see what what a tweak would do to
a tweak on that percentage would do to foster the
transmission development that needs to occur out there
actually makes a difference. Sure. Does anybody
know where ERCOT gets their data for load growth? I
mean where they come up with-- No, I'm sure we can get
that. But yeah I mean I wonder if there are
lots of different organizations that do these but I
just I wonder what their data source is. Is it similar
to that of other agencies, you know, that we use your
your old board, the water development board, they've
got a pretty critical role and, and population growth
is a, you know, I'm sure part of it, Yeah, big part
of it. So I just don't know the answer to this
but, I wonder if there's something that we could
look at and help and and massage in that regard that
has them using the most realistic forward thinking,
I mean, I think, you know, our population is growing
we know that, the economy is growing here because of
our low taxes and our business friendly environment,
and we've got to prepare for that, you know, expeditiously.
Absolutely, I'm sure Christie and ERCOT team can get
that information to our office at the earliest convenience. Commissioner
Cobos, question on this. Again, our wifi is so efficient
here at the public utility Commission. I can't pull
up PURA. But somewhere in Senate bill three at the
end of it, I recall there was a committee, it's not
TERC, but there was a group that was sort of modeled
after the formulation of the Statewide water plan.
That's kind of the way I read it, to look at
reliability issues around the state or, you know, the
policy goal was to prioritize state policies toward
reliability and I don't know if affordability was in
there, might have been, but in any case, is this something
that that entity might be harnessed for to and
I'm invoking the CREZ model and everybody calm down
but to clarify how we designate zones or areas, weather
zones of Texas that have high load growth and can
look at that and give us some focus on how a
new expedited model might apply moving forward into
the future. Again, not with any type of rubber stamped
by the Commission, but to where, you know, it falls
within the parameters that they create the need based,
falls within the test that ERCOT is statutorally
directed to apply and then, and then we could afford
an additional tool from an expedited CCN process.
Is that a mechanism that might work moving forward?
Not that it would slow the process down now, we clearly
need some of this now. Okay, potentially, and I say
potentially only because as we look at transmission
development to address reliably and economic issues
throughout the state, I think it's really important
that, you know, we have that expertise that we
need to look at, the technical, the engineering expertise
to look at the transmission development throughout
the state. I don't know how that, I think that that
body that you're referring to in SB3 how, what
kind of membership it's going to have, and I think
in the spirit of trying to get things done quickly,
I think this is, my initial response would be
that we take control of, you know. And I totally agree
and I'm not, that's why I have a lot of caveats in
that statement, but just in the long term as we experienced
this vast load growth, you know, in different parts
of Texas and it's shifting around south Texas, is the
issue du jour today west Texas was that, you know,
still going on right now? But depending on where
these crypto miners settle and stuff like that, it'll
be new, new constraints, but this body, if we
just have an extra set of eyes that has more of a
comprehensive plan akin to an infrastructure model
that, you know, the chair's all too accustomed to how
that plays into this. So it might be something as you
ask ERCOT and go into it. Is that something we
should consider as the rule opens up and we build around
that? Two good things to take away from that.
Let's see what the current version is and two as the
appointments come in for the TERC and the other committee
that's something we can coordinate with those folks
on. I know those are
being worked on as we speak. Okay, so I wanted
to highlight a recent planning guide revision
requests that ERCOT filed, (indistinct) 095 which
essentially ERCOT filed to that addresses the Governor's
directive also with respect to bottled up generation
and essentially what what this pigger does, What it's
intended to do is to allow for the full dispatchability
of dispatchable generation. And so ERCOT through
this picture will be modifying its transmission planning
process to ensure that dispatchable generation is
fully dispatched and can get out, it's not bottled
up, so maximizing the dispatchability of dispatchable
generation is what I believe the Governor asked
us to also look at in his letter to the Commission.
So I wanted to highlight that, that is initiative--
In process. Absolutely. And then as you mentioned.
Commissioner Mcadams, Yes, I did note the Rio Grande
Valley, that is an area that has been very important
much of discussion recently. And so I have spent
some time looking at that area and especially as a
result of that TDU work session we had, where we discovered
that there are, to your point earlier, Commissioner
Glotfelty, 345 WB transmission lines that are double circuit
capable that only have one line on them. And so if
you look at the map, there's there is a, basically a
transmission, existing 345 transmission line that
runs from San Miguel literally all the way down to
Palmetto. And so that entire line is 345KV.
Double circuit capable with just one line. And so I
think it is important for the Commission to look at
whether adding that second line will create additional
transmission capacity and operational reliability benefits.
I see this as near term solutions that can be taken,
addressed by the Commission to ensure that there is
more transmission capacity, into the Valley and
so and out of, import and export. And so we have
two options here, I think, I think, you know, ERCOT
would like to, we can direct ERCOT and the TSPs
that own those lines to study the reliability
and operational benefits of adding that second line
to the double circuit lines. And also another piece
is that, that sort of a shorter line is to create
a new 345 KV line that would essentially connect Palmetto
back to North Edinburgh. That's something that I
think they probably should study. It's a short kind
of a shorter line that closes, closes the loop down
their new build and have market and the TSP study
those transmission solutions that I believe are
near term low hanging fruit that we could at least
look at to see if there are reliability operational
benefits and based on their studies, then
you know, determine whether, you know, it's a
good idea to move forward with the transmission build
out, that's what the process would look
like. Of course we can get additional information
from ERCOT and we can order them to build.
You were reading my mind, your very important point
earlier about this Commission's ability and its broad
statutory authority to direct the construction of these
lines. What is in the spirit of taking action
to solve these problems on balance? Why wouldn't we
use, I'm sure there's some existing studies that provide
some analysis. What, why wouldn't we use that authority
on what you said is low hanging fruit? I wanted to
bring this to your attention and get your input with
respect to taking action, directing ERCOT to conduct
the studies or utilize a broad statutory authority.
One thing I will note ERCOT said that you know you
do, if you do have those lines being built it is important
that those that the outages are managed because it
is a very sensitive area. That the new lines, their
preference would be for those lines to be built without
serious compensation because of the interaction between
the doing generation and serious compensation on those
lines that caused some problems already. So just
things to consider.
Because I would just say in light of what we've seen
in New Orleans and what's going on with New Orleans
with Louisiana and their transmission system, you
know having multiple lines that are going in and out
of the Valley improve reliability, and you know if
the line that you're talking about where you hang a
second circuit gets done, that may not preclude another
line from being built. We may need both, if a hurricane
comes through south Texas, we may need
all of the resources to get that part in the state
back up and running. And I just think that we should
think of those as all part of the solution. Not just
one of them solves the problem, it might solve the problem
today. So I think we've got near term solutions,
we've got long term solutions and ERCOT has in fact
developed a new proposal for a new transmission
build out into the Valley and they will be providing
that proposal this month at their regional planning
group meeting, and their goal is to have a transmission
build out into the Valley that's hurricane resilient
and also addresses the import and GTC issues in the
area. So do we want to wait for that or is
this question of, and to your point is it a question
of ordering an expedited study and analysis? You know
that shows weight to the need, because again, we
have the abilities through the broad authority we
have to speed things up, so do we want to do that?
I think our default setting needs to be action to get
results sooner rather than later and if we need to
tap the brakes, we can do that. But my action list
is growing. I would say and if you're willing
in conjunction with your effort to get
a menu of analysis, transmission, new product transmission
project analysis, in addition to that, would you as
part of working with ERCOT, would you get,
one the, I guess all the fine print and a process
of what we need to do to get the two projects you
just mentioned, the double circuit or the double
line, down to Palmetto and then the Palmetto to the
Rio Hondo to North Edinburgh. But what does it,
well, you and your staff working with ERCOT, aggregate,
give us every step we need to take to put those wheels
into motion and move that forward and we'll, including
existing analysis, existing study, and if we, then
we can assess that, if we need to do additional studies
expedite studies, we can assess it at that point.
But let's see what information analysis we've got now
on both of those projects and what it would take to utilize
the Commission's
overarching authority to order the construction of
these lines as soon as possible.
Got it. Thank you. Appreciate the feedback. Anything
else?
Thank you. You put a tremendous amount of work
in this and this is a hugely important part of enhancing
our reliability. Absolutely. And I have one last piece
that I don't want to take too much time on. But
you know, you had also asked me to look into DC ties
and I wanted to highlight that currently we have three
DC ties that are in operation. 2 to SPP Oakland
Union and east, the East tie. And then one the Railroad
tie from Mexico in the valley. And I included some
just general background information as to you know
how much transmission capacity they both carry, the
year they were built and what region they're going into.
And the regulatory steps that would need to
be taken if you were to evaluate a transmission
a DC tie from market to a neighboring ISO
RTO and also from ERCOT to Mexico. And also
noting that you know with respect to, you had asked
me to look into a tie from ERCOT to MISO. That ERCOT
has conducted a study in the past and has highlighted
to me that there are cost allocation and modeling differences
between ERCOT and MISO. That just basically different
market rules that would need to somehow be made consistent
to facilitate such a construction. So you know obviously
protecting our first jurisdiction, you know protecting
our ERCOT market from FERC jurisdiction is been
the most important for the Commission, historically
continues to be getting a FERC disclaimer of jurisdiction
is key obviously to any future DC tie construction.
Also if you the line would be going to Mexico
you would need a presidential permit from the Department
of Energy. And we would need the cost allocation
and modeling differences reconciled with Miso for an
enhancement to the DC tie or a bypassable, a bypass
line, sort of this circuit breaker type you know idea.
I'm just talking about a traditional tie. Traditional
DC tie because again that would be commercial use. Commercial
and reliability. I mean it depends how this D. C. tie
is built and what our direction is. But ultimately
and I do want to touch on that a bit
because no matter, you know whether the DC tie is
going from ERCOT to MISO or ERCOT to SPP or even
to WEC, we gotta make sure it works with the market
rules in terms of cost allocation and modeling
for it to be a reliable line at the end of
the day or with the senate investigate. Right? So
I just want to highlight the regulatory steps that
that have been taken to build these lines from ERCOT
to our neighboring regions. And also to highlight that
you know, we got to take into consider reliability
versus costs. You know, these are a little bit
more expensive of transmission facilities and to note
that these ties can be used to import power during
emergency conditions. But if our neighbouring regions
are also experiencing emergency conditions that the
ties are cut off as we experienced during winter storm
Yuri with all three lines, 2 to SPP and the 1
to Mexico, but just to take into consideration as we
look at DC ties as a reliability solution to help
enhance reliability. You know, you want to keep that
in mind as well, as we move forward. Fair point. Are there
any DC lines that we've approved that have not been
built either going east or west or south? Yes, the
southern cross transmission project has, in fact, it's
a merchant tie. It's a merchant dc tie that is being
built by I believe, Pattern and Garland and the PUC
issued a CCN. There was legislation that was passed
in 2015 that requires the PUC to issue of CCN
for DC ties and so with respect in response to that
legislation that was passed, Southern Cross got
a CCN from ERcot and given the direction in that
CCN order they are currently working with ERCOT as
you've probably seen through your board meetings or a
set of directives that puc included in their order
to ERCOT to help accommodate that tie. And that's
what they've been working on for the last several years
there, they have also received a disclaimer of FERC jurisdiction.
important. I think the optimal words that you just
said was for the last few years, which is
you know, these processes, if we want to use our
authority, we can't let them get bogged down in
a multi stakeholder process at ERCOT, it just
takes too long. Everybody needs to have their say
it's a big market, but we have to hold their
feet to the fire to get these things done, if we've
approved it and we've allowed, we've received
a letter from FERC, you know, just claiming jurisdiction,
God forbid, let's go. It may not have solved the problem
in February, but it may solve the next one. I mean
we can't look at these weather events as static, one
time, build transmission one time, they are going to
happen again and again. And I think that as we build
a more robust system that has optionality to it, we
are increasing reliability to consumers. So I'm a fan
of DC lines, I'm a fan of DC ties. I think they
add, the newer technology can add a tremendous
amount of voltage support and support to the
transmission elements, and that's great. And
you know, if we want to continue to be the best place
to do business, we're going to have to have, you know
that type of a system that is technologically advanced
and reliable and economic. And if DC lines, which I
think should be part of it, we should, we should be
part of it and get that one as one of them, you
know, across the finish line and, you know, that's
my view, but, you know, hold the feet to the fire,
hold the ERCOT, get the things done and get on with it.
I also think it's important to draw a bright line nuance
between an economic DC tie which can be used for
economic purposes and a bypass reliability tie that
both ISOs get resiliency out of and FERC
and in the event of a black start scenario. So
I think they're not intertwined right now, and do
not need to be intertwined. It's like, it's
not mutually exclusive. And so I think we need to proceed
with that in mind too, especially when you start talking
about because that's where it bogs down is the commercial
when the ISOS get into the negotiations between
SPP or MISO when they have to approve, like okay how
does this work when we get into scarcity conditions?
And again if we're moving forward on our price,
economic scarcity versus physical scarcity, that nuance
it's gonna get real complicated real fast. And
so but I do think we need to approach this from
that Yuri view, it's like look at the end of the day
we need a way to build around this in case you
know the one and 200 year event happens just in Texas
to where we can draw other resources in and work through
a partnership agreement with those ISOs, not necessarily
for commercial applications. Well I will note
that even for like the railroad tie for instance is
a reliability tie. I believe it was rate based as a
reliability tie, when it's not being used for reliability,
there are commercial transactions that are being taken
on all the DC ties. So I think that's just one
component that that is just part of the DC tie
build out. But to your point economic versus reliability,
I think that just goes directly to whether or not those
costs are able to be recovered by a utility.
It's my experience, what you know what happens
when you build export projects is folks internally
are afraid that prices are gonna go up. You move excess
power out of the region and prices respond. I think
that's normal. That's probably normal economics.
If again I use the word static, if the power system
is static but in our queue, in the interconnection queue, we
have almost 100,000 megawatts of resources. Hopefully
we get more dispatchable resources in there that are
adding more. Then what's, I mean our DC ties across
the system are you know, not that many megawatts, anyway.
I want to just give the recognition that there's a
price sensitivity component here that I hope we don't
upset too much. But you know that is
I think solved with more resources. Sure it's a
very fair point and I think it's worth noting that
while we are clearly demonstrating a bias towards action
and enhancing reliability as soon as we can in as many
ways as we can, we're not gonna do it in a foolhardy
manner with a blank check that burdens consumers with
undue costs. We will pay a little more for reliability
and to your point about the concern of letting energy
leave Texas and therefore bringing prices up for Texans.
That's what markets do in a well functioning
market, the cure for high prices is high prices. That
will drive more development which is, which is what
we want driven in a competitive framework that
delivers over the long term, lower prices in the most
efficient manner, most efficient manner possible
for Texans. While maintaining Texas autonomy. The more
commercial activity you throw over those lines, it's
become a nuanced view on the part of FERC, so I would
point that out. Well thank you so
much for your feedback, I was responding back to
your action items as soon as possible and get
that information from ERCOT and I do want to
echo your statements Chairman Lake, my memo
was purely geared at addressing your directive to accelerate
the transmission development in the state for reliability
and address congestion issues and it's a comprehensive
task, and my goal was to bring back discussion
points that we can discuss and maybe take action on
today or in the near future and, all that, all that
being said, as you said, it is truly a balance
between maintaining reliability and cost for consumers
because if the goal is reliability and also costs
may have to go up, but we also have to take into
consideration the consumers in the state and the fact
that that also impacts economic development. So,
that being said, thank you for your time today.
Thank you for the tremendous amount of work. Very, very well
done. Thank you. And you've put us at a spot where
we're well positioned to move forward quickly. I think
with line of sight on some pretty decisive action very
soon. Thank you Commissioners. Before we move on, just
real quick as as a reminder, the legislature actually
put a rider in our budget that requires us to look
at the interconnections with the East West in Mexico.
So that's something staff will be doing with ERCOT
over the next two years. Good point. Thank you.
You've got a pretty full dance card from
my action item list, so I'll switch to this side of the
dais. Please do. jimmy, you had a number of goodJ
points. Appreciate. And to the extent you have, I know
you've got a full plate as well to the extent you
have bandwidth, you mentioned the new technologies
that can be more dynamic and less, I guess more digital
and less analog in voltage in utilization of existing transmission.
I would love to see some concrete examples of what
those technologies are, how they could be implemented
within ERCOT and as much information as you can
get in terms of timeline cost, road map on how to
do that. That would be tremendous. And to your
a very good point about Southern Cross and the fact
that it's in process but that process is multiple
years
and especially given your federal experience, would
you take a hard look at that and see how we can
expedite that project? What barriers or obstacles or
red tape is in the way that we can we can get
out of the way fully and feel free to offer slash and
burn proposals on how to move that forward. Absolutely.
With the assurance to Commissioner McAdams that you
know, I know they have a disclaimer for jurisdiction
but we will make sure that that is loud, clear, real
and fast and hard. Belt and suspender that part.
All of our benefit. Yes, that's right. Not just Commissioner McAdams
we all got to make sure of that. And wrapping
up our action item list, Commission Mcadams, I know
you've got a thank you for this presentation. I know
you will be playing a key role in our September work
session, obviously overlaps with your presentation today.
We have just issued or will issue guidance, Commission
guidance on that. Will you take a, I mean, a lot of
this is going to be, it's gonna materialize
in that work session. Will you take a lead on the comments
and feedback we get, we'll all be reviewing it.
But given the amount of time you put into this expertise,
take a lead on looking at those comments and at some
point that in work session offering your thoughts
on highlights, good ideas, how that bad ideas and
what that syncs up with, biased towards action.
And how that syncs up with key issues you
highlighted today and the opportunities we have ahead
of us. Appreciate it.
Right.
That concludes the business for item 21. I don't have
anything on item 20 to 24. 25 is not being
taken up today, that brings us to item 26. We'll get an
update from our Executive Director Mr Gleason.
Thank you, Mr Chairman, Commissioners. Just two items
to discuss this morning. First to kind of close the
loop on something from the last open meeting. So ERCOT
and the PUC both submitted their self evaluation reports
to the Sunset Commission yesterday. So that's definitely
a good thing, kicking off our review and I'll continue
to provide you updates as that review really kicks
off and we start making progress throughout
the interim over the next year and a half. So
I want to, you know, once again, acknowledge the abundance
of work that was done by our staff and by ERCOT staff.
These are large reports and were done in a really
short timeline. So just acknowledge that work that
was done. And then secondly you all reference TERC
the Texas Energy Reliability Council. So staff
is working to finalize the process to solicit receive
and ultimately approve applicants for TERC. Hope to
have that done within the next two weeks and have
you all approved that and get that going. So we're
required to appoint eight members. So quite a large
task as well. So we want to get that going.
Good point. And as Commission Mcadams added, there's
already working on some items for them to consider
and there will be a clear area of value for them or
scope of value for them to address. And to your first
point about the Sunset self evaluation. That is both
to PUC staff and ERCOT staff. That is a tremendous
amount of work. I know people hear about the Sunset
Commission and hear about the Sunset process but I
know we've all gone through that report. So a big thank
you to both ERCOT and PUC staff for what a big
effort it is too. Put that together and do it in
such a short amount of time when everybody's already
running at 110%. So thank you.
I don't have anything for items 27 or 28.
That will bring us to close session. Having convened
a duly noticed open meeting Commission will now at
11:26 a.m. on September 2, 2021, hold a closed session
pursuant to Chapter 551 of the Texas Government Code
Sections 551.071, 551.074 and 551.076.
We'll be back.
Alright closed session is hereby concluded at
1157 am on September 2, 2021. The Commission will resume
its public meeting. No action was taken will be
taken related to matters discussed in closed session
and having no further business before the Commission.
This meeting of the Public utility Commission of Texas
is hereby adjourned