Good morning. This meeting of the Public Utility Commission of
Texas will come to order. To consider matters that have
been duly posted with the Secretary of State of Texas
for January 26, 2023. For the record, my name is Peter
Lake and I'm joined by Will McAdams, Lori Cobos, Jimmy Glotfelty
and Kathleen Jackson. Ms. Cisneros, would you please walk through
our consent agenda today? Good morning Commissioners.
By individual ballot, the following items were placed
on the consent agenda. Items 3 through 7, 9 ,10, 11,
14 ,16, 17, 19, 20, 21, 22, 25, and 34.
Thank you, ma'am. Do we have a motion to approve the items
just described by Ms. Cisneros?
Motion and a second. All in favor say, aye. Aye. None opposed, motion
passes. We will not be taking up Item 23 today. So
we will begin with the first item on our agenda, Public
Comment. As always, oral comments related to specific
agenda item will be heard when that item is taken up.
This segment is for general comments only. When we get
to oral comments on specific items, stakeholders should
not approach the table. Unless oral argument has been
granted or they have been invited by a Commissioner.
As usual, speakers will be limited to 3 minutes
each. Ms. Cisneros, do we have any from the public
signed up to speak? Yes sir, we have 5 people that
have signed up for Public Comment this morning. All
right, let's start at the top. All right. I'll call
the first person up, Angela Cervantes.
(silence)
Sit right here.
Just sit. This is not a good start.
Bad omen?
Good morning, welcome. Good morning. Excuse the nerves.
(item:1:Angela Cervantes concerning CenterPoint substatation) Good morning, my name is Angela Cervantes and I am
a resident of the Red Oak Acre subdivision in Seabrook,
Texas. I'm speaking today on behalf of the entire neighborhood.
Against a substation that CenterPoint is planning
to build inside of our one way in, one way out subdivision.
Sandwiched between established homes as close as 50
ft from a resident's home interior. Furthermore adding,
this land has been zoned residential since it's purchase
by HL&P in 1960. We have received support from
Representative Dennis Paul, who in a meeting realized
that CenterPoint misrepresented the location and impact
of the substation. The city of Seabrook, who is vocally
against the chosen location, but believes their hands
are tied due to imminent domain. In Harris County, who
realized the gravity of this location choice, and pulled
in a team of site engineers to facilitate a new suitable
location for the substation. Harris County's progress
failed because in Harris County's words, CenterPoint
moved the goalposts and tightened their requirements
and ultimately, it was deemed that there was no available
land in the limited acceptable area to CenterPoint.
Because CenterPoint also stipulated that the subdivision,
the substation had to be within Seabrook's boundaries.
CenterPoint has stated repeatedly that this substation
is critical due to rapid growth in the Seabrook area.
I will point out that Seabrook is landlocked. In according
to recent data only growing at a rate of 1.2% with
a less than 2% population increase last year. Cities
just south of us, such as League City are growing at
a rate of 2.5, 2.56% annually with an increase
of 8.9% population. In Nassau Bay, at a rate of 2.39
with a population increase of 7.5. CenterPoint refuses
to answer the question, what percentage of Seabrook
will this substation benefit? But repeats the mantra
over and over that Seabrook is rapidly growing and
needs the substation. We provided CentrePoint, the City
of Seabrook, and Harris County, a spreadsheet of 6 properties
that CenterPoint owns along the 146 corridor. To consider
instead of inside are developed subdivision. Why were
these not considered? According to Harris County, Center
Point even seemed agreeable, agreeable to construct
the substation on the east side of 146, which is plentiful
of undeveloped industrial property. With these revelations,
it is obvious Center Point is not acting in good faith,
and abusing their power. CenterPoint admitted in the
community meeting, that they have not done an environmental
assessment of the property. This was criteria that
Heather Caramanica from CenterPoint, listed as a
land requirement to Harris County. The house directly
adjacent to the proposed substation location has foundation
issues. The home directory directly across the street
has foundation repairs, as well as two homes around
the corner. If we have issues with our soil and land
composition, why wouldn't CenterPoint? Further adding
our subdivision is in a flood zone. And CenterPoint
has stated dependency on are currently taxed ditches
as drainage overflow along with the retention pond.
We asked CenterPoint how many substations have been
constructed inside of a fully developed subdivision?
And they could not answer. All examples provided were
neighborhoods built around a substation after the fact.
These homeowners paid the price accordingly and accepted
the risks associated with the proximity. This risk
is being forced upon our residents. Three CenterPoint
substations have caught fire within the last 5 years,
one as recently as July of 2021. The placement of this
substation 50 ft from a residence is in one word, negligent.
Ma'am, your time has ended. Go ahead and wrap it up, one final thought. Thank you. We understand CenterPoint
feels that this substation is necessary for growth
in the area. But we do not understand nor has it been
explained, why inside of an enclosed established subdivision.
When there is a vast supply of undeveloped industrial
properties nearby. By allowing them to construct the
substation in fully developed and close subdivision,
with one way in and one way out. Is risking the livelihood,
health, safety and well being of this neighborhood
and our kids. We are pleading with you to intervene
on this project before something goes wrong. This is
negligent of them and the risk is way too high on us
to be on the losing end when something occurs. We matter
too and we need your help. Thank you so much for your
time.
(inaudible)
The next speaker is Jose Cervantes.
Good morning, I'm not as good as her. I'm just speaking
on behalf of the wildlife in our area, in our neighborhood
basically. (item:1:Jose Cervantes, CenterPoint substation wildlife concern) So I said with that said, good morning
my name is Jose Cervantes and I live in Seabrook, Texas,
and I'm here to address the environmental impact. That
a proposed CenterPoint substation in our small neighborhood
will have on our local wildlife. I provided pictures,
I don't know if you guys have that. That's, these are
all recent pictures. Um, the land that CenterPoint is
proposing to build their electrical substation is heavily
wooded, and butts up to Armand Bayou Nature Center Reserve.
Because of its close proximity to the Nature Reserve,
the wildlife in that area is well protected, abundant
and thriving. There is families of deer, armadillos,
migratory birds, hawks, migratory butterflies and even
a bald eagle that frequents that tree line. That Center
Point is proposing to build on. Our concern is that
CenterPoint in order to build a substation. Will
need to cut down most of those trees, which will greatly
impact their habitat. Forcing them closer to a nearby
highway, uh to a busy highway. And please I plead, I
plead with the PUC to help us protect the wildlife.
And with my children here, who I woke up at 4am.
to get here. Uh, they would love to see that there is
people like yourselves with, with powers and responsibilities
to change things. To have the courage to be heroes and
protect the earth's natural habitats. All it takes
is for you guys to pause for a moment. Reevaluate
the impact of this substation will have in our small
neighborhood, and the wildlife that it shares with us.
Because we feel like, we moved into that area because
of those trees and and everything that came with it.
So thank you guys. Thank you. Ya'll have a good day. Point out, that's a picture of a bald
eagle.
May I ask you a question, sir? Um, there are two um, pictures
in here. One of them has the substation, kind of at
the back of the neighborhood. And one of them has it
at the front of the neighborhood. Do you know which
one it is? Uh, no sir. That's, that's just so, our neighborhood's
like a circle. So uh, my home it says home. It's, it's
to the corner of that. That's where it's proposed to
build. To the left of that, where it's just wooded.
That's the second proposal to build. So there are multiple sites, potential sites. So the way I see
it, it's in the neighborhood, there is no. If it was
like towards the back of the neighborhood, I probably
wouldn't be here. You know, like where I couldn't see
it. Got it. But, thank you. Thank you.
(laughter)
Each, each one of these gets better. You did great.
Next up, Ms. Cisneros. All right, the next speaker is Marcus Phelps.
(item:1:Marcus Phelps, CenterPoint substation health concerns) Good morning. I bet ya'll can't guess why I'm here. Uh,
my name is Marcus Phelps. I live at 2526 Loganberry
Circle in Seabrook. I'd like to also speak regarding
the health concerns with the proposed substation in
the Red Oak subdivision. Uh, first of all, I am a 100%
disabled vet. I served 21 years in the United States
Navy as a Radar and Communications Systems Technician.
I have an intimate knowledge of electricity and
EMF. I used to take light bulbs and hold them up
in front of the radar and watch them light up in my
hand. With that being said, this proposed this proposed
substation is 134 ft from my front door. I completely
understand the need for electrical power with the uh,
you know the freeze last year, and with the growth that
we're experiencing. But, EMF is something that's
real. Uh, typical substation generates about 0.5 micro
tesla of EMF out to about 300 ft. This level
is affected of course by shielding and, and things like
trees that they want to cut down. Currently, Texas
has no regulation of shielding or distance from homes
for power lines or substations. The PUC claims it uses
a de facto prudent avoidance per its March 1992 study
titled, "Field Effects of Exposure to Power Line Frequency
an Electromagnetic Fields." To determine the
safe distance for these from homes and residents. In
this study, the PUC references several federal and
state agencies such as the CDC, The National Center
for Health Statistics, and OSHA. That state there's
no definitive proof that EMF has health effects.
But the same report also states that there's no proof
it does not, and further study is needed. That was
30 years ago and no studies have been conducted since.
So my question is, what is prudent prudent avoidance?
Uh, there's several articles out that talk about the
safe distance from a um, substation. The number that
keeps coming up is 300 ft. Sir, you have one minute. Okay.
Uh, with that, like I said I'm a disabled veteran. I suffer
from PTSD back in 2012. They did a study where they
took mice that had PTSD and they introduced them to
an electromagnetic magnetic field. Uh, then they turned
those mice loose into a field and to see what would
happen. The mice that were not exposed to the EMF,
froze to death. The or the vice versa. The mice
that were exposed to the EMF froze to death. They
lost their fear. The electromagnetic frequency caused their
fear to be canceled. Those who had not been exposed
huddled up and found safety. So my question is there's
22 veterans a day that commits suicide in the United
States, per VA uh report. I don't want to be a guinea
pig. To find out if EMF makes me more vulnerable
to suicide or not. I really don't want that. There's
children that live in this neighborhood, that are gonna
be less than 300 ft away from the substation. EMF
has been proven to show, cause childhood leukemia.
So we're just asking you to look at all the factors
that are involved in this substation, and where it's
going. Thank you. Thanks for being here.
Next. Next speaker is Stacy Gaona.
(item:1:Stacy Gaona, concerning CenterPoint substation) Morning. Welcome. My name is Stacy Gaona also live at 2526
Loganberry Circle in the Red Oaks subdivision. And I'm
here to talk about the proposed substation. I know
uh, Mark mentioned some articles that were written by
a person called Jordan Mitchell. Uh, Jordan Mitchell
is a certified EMF Consultant and her research
and findings are available on a web, her website beat
emf.com. Uh if you, we have documents that
we are happy to provide to you guys after this meeting.
If you want to be able to do more reading on what
we're bringing up. Uh, he also mentioned a case that
Klein ISD had against a CenterPoint, when it
was HL&P. And in that case a jury and
a judge, found that CenterPoint had a blatant disregard
for the health of children in a proposed substation.
That they had and they put a stop to it. And I
know that Seabrook is a small city and our subdivision
is extremely small. Uh and there's a handful of children
that live in the subdivision, subdivision as well as
a daycare one street over. Uh, so I know that Klein
ISD is a big school district, but we feel like
we matter uh every, every life matters. And uh, we also
feel like CenterPoint has really misrepresented this
site to the Public Utility Commission. Uh, they talked
about the, my neighbors talked about the exponential
growth to put numbers to those percentages. In 2010,
the Seabrook census, we had 11,952 people in our city.
In our 2021 census, 11 years later we, our census has
13,560 people living in our city. So that is an increase
of less than 2000 people, where CenterPoint has called
an exponential growth. And has said that they don't
have any other viable options for this substation.
However, they are also on record as telling our city
and our subdivision. That the substation is mainly needed
for power to the North and South of Seabrook. Ma'am, you have one minute.
One minute, thank you. Um again, my front door will
be 134 ft from this. We also have this tree
line not only protects us uh, as far as you know providing
the wildlife and stuff. But right on the other side
of the tree line, we have the highway, railroad tracks,
and a Geon Plant, a chemical plant. So at the point
that CenterPoint removes all of that. Our neighborhood
will, we will no longer be living in a neighborhood,
we will be living in an industrial complex. And if
you look at the research on property values. A research
study that was done by an appraisal group in Wisconsin
and presented to the Public Service Commission, Commission
in Wisconsin. They found that there is a 30-40% decrease
in property values for homes where a substation is
constructed close by. Part of that study include, they
referenced a study done by a man in the Houston area,
David Bolton. Where he said that their property values
in the Houston area were also 30% lower. Again, we
can follow up with further documentation. But we ask
you to please look closer at this and please help our
neighborhood in our community. Thank you for your time.
Thank you for being here.
All right. The last speaker is Cyrus Reed.
(item:1:Cyrus Reed, Sierra Club on energy efficiency) Hello, good morning Commissioners. Cyrus Reed, Sierra
Club. That's a hard act to follow. I'm not gonna talk
about Seabrook, but appreciate them coming today. Um,
I'm really here to praise the Commission. Um, for opening
up a stakeholder dialogue about energy efficiency.
Uh, starting this week and going through March 9th.
There'll be a series of workshops and meetings being
led by your, your team by Tetra Tech. Um, it's all been
filed in Project 38578. If you didn't sign up for
the one of the working groups, you're too late to participate
directly. But you're not too late to give input and
listen in. And so I would urge any stakeholders interested
in energy efficiency around all of these issues. Uh,
to look in that project and, and participate and provide
input. And I appreciate your leadership in this issue.
You know, it's an important issue to all of us. Uh, and
Whatever we do on the on fixing the grid. Making sure
that the programs and projects we have are as efficient,
and well done as possible is gonna be important. So
public service announcement and thank you to the Staff
and, and Commissioner Jackson, thank you. Thank you
sir.
I believe that concludes our public comments, is that correct?
Correct. I know uh, Commissioner Glotfelty has always been
a big advocate for getting more transmission out of
the same space. That's right. So, we'll always look to him for issues
like that. That brings us to Item No. 2, on our
agenda. Ms. Cisneros, could you lay that out for us?
(item:2:49242, Commissioner McAdams on TX Water Utilities) Yes sir. Item No. 2 is docket number 49242 is the
application of Texas Water Utilities, LP. For a pass
through gallonage charge. A revised proposed order
was filed on December 1st, and Commissioner McAdams.
Commissioner McAdams, would you like to lay it out for us. Certainly Mr. Chairman and thank you. Uh,
members I filed a memo in this docket, I know you saw.
Recommending that we remand this case, for the parties
to provide clarification. Um the, the application is
for Texas Water Utilities to increase its pass through
rate from $0 or cents to 69 cents per 1000 gallons.
It's a straightforward application, but it has taken
a while in our processes. Um, because it was abated twice.
Bless you. Um, it was abated twice to work on related
pass through issues for the utility and other dockets.
And in early 2020, Commission Staff filed an agreed
final recommendation. To increase the pass through rate
from $2.27 per 1000 gallons. And also to decrease the
Texas Water Utilities approved gallonage base rates
by a dollar uh, 68 cents per 1000 gallons for all tiers
of their usage. It appears Commission Staff was trying
to ensure that all pass through expenses are recovered.
Through the separate pass through charge and not in
base rates. The silver lining in uh, to the many delays
that was experienced over the years. Is that the docket
um, is that these issues previously identified by Commission
Staff were resolved. In the recent base rate docket
for Texas Water Utilities, which we handled. Um, that
case was resolved by agreement of the parties pass
through rates were one of the issues the party specifically
addressed in the agreement. And the Commission approved
a tariff for Texas Water Utilities, including the pass
through rates. So during the base rate case, this pass
through docket was abated until the final related
pass through rates issues were finally resolved. And
in the meantime, extensive turnover had occurred within
PUC Staffs. Which ultimately appeared to affect the
recommendation not being updated. So where does that
leave us now? It seems that the remaining issues are
limited. First, approving the pass through rate of 69
cents from the date the application was filed until
the date interim rates went into effect in the base
rate proceeding. And then second, the refund owed to
customers of two water systems, that Texas water Utilities
agreed to. On remand, I believe the parties can confirm
this or clarify these issues, if there are is something
I may have missed. Otherwise, my memo lays out my concerns
and recommendations. I don't believe this is the fault
of any of the parties including Staff. I believe this
was just a disconnection that occurred because of Staff
turnover. And a number of years it took to ultimately
process the proceeding. Uh, and Mr. Chairman, I'm happy
to take questions. But I have, I would move to remand
consistent with the memo. Everything you said, made
sense to me. Welcome questions, comments or a second
to close motion? A second and motion. All in favor say, aye. Aye.
Uh, none opposed, motion passes. Thank you sir.
Next item, please ma'am. (item:8:53373, Commissioner McAdams on modifications/additions to memo) The next item is Item No.
8. This is docket number 53373. The complaint of
Andrew and Sarah Fossum against Undine Development,
LLC. A draft preliminary order was found on January
19th, and Commissioner McAdams also filed a memo
on this docket.
Yes sir. I would frame this as a bit of housekeeping.
Uh, in regards to uh, questions to be asked. To be brief,
I filed a memo in this docket making some modifications
and additions to the preliminary order. To better understand
the facts surrounding the dispute in this complaint.
I believe the questions added help provide clarity
for us, as this comes back to us. Uh, pending any questions,
uh, I'd move to approve the preliminary order as modified
by the memo. Second. Got a motion and a second. All in favor say, aye.
Aye. None opposed, motion passes. Efficient work, Commissioner McAdams.
Continues. Next up, Ms. Cisneros. (item:12:54041, Commissioner Glotfelty & David Smeltzer, Commission Staff) Believe this brings us to Item No.
12. That's project number 54041 - Review of Chapter 24 -
Substantive Rules applicable to water and sewer service
providers. Commission Staff filed a memo and a proposal
to readopt the Chapter 24- Substantive rules. Welcome
Mr. Smeltzer. Thank you, Ms. Cisneros. Thoughts,
comments? Yeah, I would like to just say something
real quick about this. Um, to me the uh the industry
has put forth a lot of good ideas within this um, filing
for ways to streamline the docket or streamline the
CCN process or the administrative procedures. Um, system
improvement charges um, expedited releases, harmonizing
the CCN process with TCEQ. All things that I think
um, if the words are right and the process is right.
That's what we want in this administrative procedure
here for us, and for the industry to be efficient. And
I know we've, we've talked to uh David about uh, about
why these things weren't incorporated. But I just want
to ask you hear publicly. These weren't incorporated
because? So, according to uh Texas Register posting
requirements. Uh, you know, we would have to post hundreds
and hundreds of pages of rules to be able to make changes
and do public comments. And so the way that we structure
our rule reviews is sort of a gathering of ideas for
future rulemakings. Um and you know, a lot of times
we'll get to those and we keep a backlog and a list
on Staff. For when we open rules, we can make updates.
And uh when we have additional bandwidth and we kind
of go back and see what the most pressing suggestions
were that we can we can get to. So, that's great in
my opinion, I mean clearly having a list of ways that
we can create an efficient rulemaking process or things
to do. And I hope that, you know, as we continue throughout
this year. Um if, if this if the uh water and service
rule Chapter 24 gets reopened. We consider these things
for uh discussion within that uh that process. We certainly
will. And for, for watchers who, who say, oh I know they
collect these ideas and never get to them. And you know,
we've only actually had a rules division for uh, you
know, a little over a year and a half. And so the
we fully intend to be going back and mining the old
rule reviews. For stuff to do as time permits in a
way that wasn't done in the past. Well this year has
been extraordinarily busy with rules so uh, you get
a pass this time.
I appreciate, appreciate the entire Staff. And, and
the process that you laid out for us. You get a pass
plus a gold star for all those rulemakings. Uh Jimmy, that's a good
point that these are foundational concepts for future
rulemaking, is that fair? Yeah, absolutely. That's
that's a good way to incorporate them and aggregate
a large, large number of ideas. Any other thoughts,
comments. No. All right. Is there a motion to approve the
proposal for adoption?
Second. Got a motion and a second. All in favor say, aye. Aye. None
opposed, motion passes. Well done, enjoy the gold star
Mr. Smeltzer.
I don't think we have anything on 13. Where, what does
that bring us to, Ms. Cisneros? If there's nothing on 15, I believe
that brings us to Item 18. Alright, would you lay
that out for us? Certainly. (item:18:52728, Commissoner McAdams & Commissioner Cobos, on College Station wholesale transmission service rate increases) Item No. 18 is docket number
52728. This is the application of the City
of College Station to change rates for wholesale transmission
service. A proposed order was filed on November 17th.
The ALJ filed corrections memo on December 6th and
the Commission Council memo was filed with proposed
changes to the order.
Uh, certainly some, a variety of elements in this one.
Uh, eventually some gaps, we'd love to hear ya'll's thoughts
and comments on, on this docket. Well uh, I hate to
do this. I'm a good Aggie, um but. That's why I let
you go first.
Um. Well played Commissioner Cobos. While I appreciate the efforts of the parties uh,
to come to an agreement. I believe that we need to
either remand uh, this for the parties to continue working
on it or to deny the application altogether. There
are two major issues within the settlement and the
proposed order. First, uh I recommend that we find
College Station was not entitled to recover any of
its general transfer payments or payments in lieu of
taxes to the City, including in its interim wholesale
transmission proceedings. Interim T cost proceedings
are reserved for changes in invested capital, not payments
in lieu of taxes or other transfer payments. To be clear
these payments are not an interim transmission investment.
Nor are they a federal income tax as we clearly see
or other associated taxes. Because by their very name
and definition payment in lieu of taxes or transfer
payments are not a tax at all. So by including these
payments in the interim revenue requirements. College
Station has been improperly increasing its rate of
return above what was approved by the Commission in
its last comprehensive wholesale transmission proceeding.
So therefore, it is my view and I don't expect anyone
to share this at this time. But in my view, I believe
it is appropriate for College Station to refund the
entire $31.5 million dollars. From transfer payments
consistent with the Staff's original recommendation.
Now, second um, now that College Station has filed
a comprehensive T cost application. I believe that
we should allow some general fund transfers going forward,
but not at the 9% level. And that is because PURA generally
requires that a utility that owns and operates transmission
facilities must provide wholesale transmission service.
At rates and terms including terms of access that are
comparable to the rates and terms of the utility's
use of its system. So, College Station should only
be allowed to recover general fund transfer fees. That
can be justified by a specific rationale related to
the actual cost of the provision of service, and not
just just compensation. The city's financial policies
state that the transfer includes, but is not limited
to, and in lieu of franchise fee consistent with the
franchise rates. Charged to investor owned utilities
to operate within the city. But according to College
Station, it charges investor owned utilities 5% franchise
fee, uh, to operate within that city. And I agree with
Staff's assertion, that the remaining 4% did not appear
to be supported by an express rationale. And so College
Station did not provide justification for including
the 9% general fund transfer in return, uh, in the
return calculation. So therefore, I believe that the
9% fee should be reduced to 5% of transmission operating
reserves. Given these two thoughts, I believe that
we should either remand this proceeding, as stated. For
the parties to reach a settlement consistent with our
direction. Um, and that is reasonable to this Commission
or if the settlement cannot be reached, ultimately
deny the application. I'd welcome any thoughts. Well
put.
I agree with Commissioner McAdams position in general.
Um, I think we need to reject the proposed order, remand it
back for additional settlement negotiations or processing
of the hearing and, or denial ultimately. College
Station violated the Commission's order and docket
number 15762. By including in its interim T cost updates
general transfer payments slash. You know, payments
in lieu of taxes on the invested capital set in 1997.
The Commission approved the transmission river, the
Commission approved revenue requirement, transmission
revenue requirement. It did include payment in lieu of
taxes or any taxes, the tax expense in fact allocated
to transmission, that case was set to zero. So the
general transfer payments were not included in the
authorized rate of return in the case. And then subsequent
to that, you know, by including these transfer payments
in the interim revenue requirement. College Station
has been effectively as Commissioner McAdams strongly
noted. Increasing its rate of return above what it was
approved in their last comprehensive rate case. And
these are significant increases 16.62%, 16.82%, 13.34%.
That's the effect of including payment in lieu of taxes
in the interim updates. And um, so I think with respect
to the refund, you know, the Commission requires that
any amounts resulting from an intern update. That are
found to be unreasonable and necessary. Plus corresponding
returning taxes shall be refunded with carrying charges.
So with respect to the amount um, you know, the the
little bit over $3 million. I know it's a black box
settlement, there's carrying charges in there somewhere.
That's not enough. And I, I lean towards where Commissioner
McAdams is with the $31 million. That's a lot of money
that's been, being added. And, and we're kind of in a
tough position with these muney rate wholesale transmission
rate cases, in general. I mean, they haven't been in
in 26 years. We had a similar situation with a prior
docket then. And, and that's something that we, you
know, need to consider and I know that, you know, all
the non-ERCOT utilities are on a schedule. Um, to come
in every four years. Um, we only have jurisdiction
over the city's transmission service rates. The wholesale
T cost, that's uplifted to all ratepayers. And so this
puts us in a bind when, when, you know, cities don't
come in for 20 plus years. And we're having to clean
up at the back end and all kinds of, you know, updates
are made in between. And we're dealing with complicated
issues. And so it's just something to keep in mind.
Um, I know we have submitted our Legislative recommendations
to the Legislature. And asked for the ability to seek
interim rates for the cities. But you know, these are
rates, these wholesale transmission cost rates are
uplifted to all ERCOT ratepayers. And we must be diligent
and we, we need it. I feel that we should be on
some kind of schedule. Maybe it's not four years because
of the amount of work that would um, impose on all
of us, but maybe it's six years. I don't know what
it is, but I feel like, you know, when the city stay
out that long. It has a tremendous impact on ratepayers.
And we have to come in at the very, you know, 20
years later and clean it up.
Good points all. Any other thoughts, comments?
Anybody have a motion? I mean, what I'm hearing is that this
this needs a lot of work. Needs this proposal clearly
needs to be rejected and the docket remanded. So the
parties can uh. Reach a settlement. Digest what they've heard, uh, at the
diose today. And come back with a dramatically improved
settlement. Is that consistent with ya'lls thinking?
Yes sir. Yes.
Unless you want to a. Uh no, I'm happy to let you take
that because uh. On behalf of Commissioner McAdams, I
so move.
We'll let the horned frog take that. Well, he is wearing
near maroon, so.
And I would second. All right. We've got a motion and a
second. All in favor say, aye. Aye. None opposed, motion passes. Next
item please. (item:24:53860, Chairman & Commissioners on software proprietary information & costs allocated) I believe it takes us to Item No. 24,
docket number three sorry, 53860. This is the application
of Hanover RS Construction LP. For approval of a method
for system billing for heating, ventilation and air
conditioning. There was a proposed order filed on October
14th,
and that's what's before you. Thank you ma'am. Uh, interesting
dynamic in this one. Um, with a kind of interesting technology
angle. Any thoughts, comments? I think we. Go ahead.
Well, I was just gonna, from my perspective. I think
we need to remand the application back to docket management.
So that Hanover can supplement the evidentiary record
with additional information. That specifies how the calculations
are used by the software um are used to determine the
costs allocated. So that we can effectively review complaint
cases in the future. Um we also need to know what data
will be available to objectively verify the accuracy
of the cost allocations. And how historical data will
be retained to resolve any customer complaints or compliance
inquiries. In other words, what's their retention policy
Yeah, sure. Yeah, I agree. You know, I don't think
we want to dissuade um creativity. Um new technology
softwares that will help make things more efficient
when it comes to separating bills in, in multi-unit
um complexes. Um, it's just that we don't have the
foundation understanding of the software. We don't
have the foundation understanding of, we know what
they've told us. But we don't know if the software
works as they told us and in order to protect the the
constituents that are in that uh that space. Um, I
would agree that we remanded it for more information. And
and just for the record, we do have a mechanism for
filing proprietary and confidential information at
the Commission. So the fear that this, you know, discloses
your secret sauce and how you're, you know, making
your business model that much more efficient. We have
safeguards in place for that. But we have to establish
the evidentiary record and the safeguards for the consumers
coming back later on to try to audit this, you know.
Because complaints are inevitable, especially as these
systems proliferate.
I very much agree with your point, Commissioner Glotfelty.
I'm not trying to um dissuade new technologies. I mean
you know, downtown Austin is exploding with multi, a
lot of big buildings. Multi-use dwellings and and you
know these uh commercial developers. Should have
the ability to use modern technology and software packages
to figure out how to build their customers. It's just
we just need more information so we can do our job
at the back end, if we get any complaints. I think it's
incumbent on us at the front as well. Because we need
to understand the algorithm, you know. Not just the
concept so that we can fully make sure at the front
end that it qualifies. Because we're obligated under
statute right now to use a certain mechanism. That's
based on square footage. So I think it's important
at the front end, it's important at the back end. In
case we have folks that come to us and um, you know
want to challenge how their bills are being allocated.
As well as I think it's it's um it's just good operating
practice to have um the information um, retained and
available. So that not only is it available to those
who want to come later and challenge it. But it's also
available for them to go in on an ongoing basis and
audit it themselves. Um you know, they mentioned that
this is, as you mentioned, innovative technology. Uh
the energy savings are actually coming from the implementation
of the new type of of system. And so this is just
an increment on top of that. So, um I think it's incumbent
on us to do, as you mentioned to remand it back. And
I'm glad that you mentioned that we do have a process
in place to accommodate that. And and Commissioner,
I think do your efforts on energy efficiency and then
what we're seeking to do on PCs. We are seeking to
have loads, become more efficient uh in their energy
consumption. And uh so new technologies, new systems
like this are right in line with that, but we have
to know how they work. Um, otherwise we're just not
doing our job. Yeah, good, good points all. Not only
more uh loads, more efficient, but more responsive and
more capable of capturing savings for their consumers.
Um excellent points all. Uh and the only thing I would
add is that we have we have we have a process and
mechanism, proprietary information. But I hope nobody
is hearing a desire for any we we need, we need the
methodology. We need accountability on the front end
and the back end uh for future complaints. But we we're
not trying to put anybody out of business. We've got
appropriate channels. We're not trying to discourage
new technologies using new ways. Uh but we got to find
that balance. Um, anybody have a motion,
motion to remand? I second. Got a motion and a second. All
in favor say, aye. Aye. None opposed, motion passes.
I believe we're going to go out of order at this point.
And take up Item No. 31 and then return to Item 26,
if that works for ya'll?
Could you lay out 31 for us, Ms. Cisneros? (item:31:54224, Chairman, Commissioners McAdams, Glotfelty, and Cobos on interconnection agreement & reliability standards) Certainly, item 31 is
project number 54224, cost recovery for service to
distributed energy resources.
Uh, thank you ma'am. I know Commissioners McAdams, Glotfelty
taking the lead on this. Ya'll have any opening thoughts
to kick off the discussion? Policies aren't easy, are
they, David? So opening thoughts Mr. Chairman and I
think we've got a lot um. But ultimately the projects
that affected DESR interconnection um were already bifurcated
into two projects. One entailed cost allocation um
the other entailed interconnection agreements and um
standard interconnection agreements. And in my view
we have a couple of options uh for how to proceed. On
the cost allocation which is by far the most controversial
and complicated with significant implications um for
other policy. So we could table this discussion until
on cost allocation, broadly. Until after uh we create
a reliability standard which should consider both resource
adequacy as well as deliverability of energy, on the
system. And my thinking there is as part of Phase II,
we have determined that we're going to adopt a reliability
standard. That it will account for if megawatts are
actually deliverable in a system. And what that means
is it could be on a zonal basis. It certainly could
be on a system wide basis, but drilling down still
further, there may be implications for PC obligations.
Um to make the system reliable and resilient. As such
um there would certainly be benefit uh for distribution
systems to have interconnections of distributed level
uh energy resources. Um certainly batteries or anything
else that's coming into their system. Because the more
resources you have in a given area, the lower your
uh, the PC value is. And the lower your obligation is
so we reach equilibrium. So that would be a metric
theoretically that Staff could look to in the future
when they're determining cost allocation. To say, well
there is certainly a system benefit uh to having these
resources interconnect at this level um and transform
their power all the way up to uh from distribution
up to transmission. Um so again, table it or uh we
could make a policy cut um and we could consider doing
that at the February 16th Open Meeting. Bottom line
is I know I'm tired and I know you are too after
last week. After the last 18 months. And um and so I could give it two more
weeks of thought. Uh to think about a policy cut and
what that means is um, we could theoretically direct
Staff on a policy direction for discussion draft. And
at the end of the day this all comes down to value
judgments on our part. I believe Liz Jones sitting
out there said it months ago. That this was gonna come
down to a value judgment and it still may uh, on the
part of the Commission. Meaning if we believe these
distributed level resources are uh good for the system.
Um then we may determine that they get, should get
their own uh cost allocation rate, get their own rate.
In terms of uh charging megawatts or uh, you know, wear
and tear on the system that they have to pay for. And
so I want to give you a little bit of history and
remind you of it. This policy has been building for
10 years, over 10 years now. In 2012, Staff recommended
the energy storage resources should pay for transmission
services when charging. And again, they're not paying
for transmission when they're exporting. Because by
definition, legally they are a generator and that's
been well enshrined in law. Senator Hancock, Senate
Bill 415 last Session, said that there a generator.
Um, as a result, just like all other generators, they
don't pay to put megawatts back on the system. That's
baked into uh, the, the public interest that we get
out of consuming those megawatts. But Staff in 2012,
said that they should pay for the charge. During an
Open Meeting, Commissioners supported storage resource
development and disagreed with Staff's position. They
directed Staff to exempt wholesale storage resources
from the wholesale transmission service tariff. So
they made a value judgment that batteries were good
for the system. They're easily deployed um, they're
more granular, they increase system resiliency, all
this was discussed. Staff then recommended that the
Commission clarify that the exemption applies only
to transmission level storage entities. But the ultimate
rule adopted by the Commission, omitted that detail.
So now we find ourselves trying to make this sausage
10 years later. And by the way, that's TAC 25.192,
if you want to look it up.
So ultimately, I think we we give this a little more
time and thought. But um and I think 2 weeks would
help me get with Staff and our Rules Division. And chart
a path forward, but I would say it is Staff's job is
to make the world work. Our job is to think strategically,
about where the world is going.
Oh, he's got a lot of responsibility, this is an important
man. Purple heart. And uh, and the Legislature should know where to
find you. Oh, that was a big (inaudible). That was. Um,
but anyway, I think we've got a lot to think about.
I know Commissioner Glotfelty has thoughts and I'd
welcome any type of deliberation on this matter. Thank you. Um,
I would uh appreciate you laying it out like that.
Um clearly, I think since the, the since this was initially
passed, um the world's changed dramatically. Um it was
uneconomic to put distributed resources at the distribution
level. And probably unheard of for them to think that
they would have a value at the wholesale trans, at the
wholesale market level here in ERCOT. Um I think
we're finding um through economics that that's not
the case anymore, and that we need to address this.
Um, I'm okay with delaying in two weeks. Um, I think finding
the balance. Um quite frankly I, I think um they should
be considered wholesale resources and their cost should
be uplifted to T cost. Because that's where the impact
is. Um I'm ready to have that discussion, you know,
in the broader context. But um I want, what I want primarily
is to do it quickly. Because there are resources that
want to get on our system. There are resources that
we need uh, you know, based upon our market design discussions
that we've had. Um you know, these can add up to to
megawatts that can improve reliability and resiliency,
lower economics. Um so I just want to get it done quickly.
Um and you know, if we move forward with the interconnection
agreement uh and and delay cost allocation for a few
weeks, I'm okay with that. And and I would certainly
uh I would advocate just food for thought. Moving forward
no matter what with the interconnection agreement.
It is the least controversial aspect of the policy.
Um it sets accountability measures on both parties,
both the transmission and distribution service providers.
Um hooking the resources up and on part of the resources
to get their filings in. Do you have thoughts on that
part, David? No, that's just a different project so.
I was questioning whether or not we should be talking
about it. That's a good point and I will stop talking
about it. But what is posted is the rulemaking calendar, which
is posted. And I will say that we have, do not
have any plans to delay that project. No, I know that. Okay. But I'll
stop talking about it. Um so, uh and also to dovetail
on Commissioner Glotfelty points. I want to throw this
out there for consideration. If we, if we are somehow
able to build a rationale and methodology to where
these costs are ultimately uplifted to uh, T costs.
These are distribution level costs that would then
be uplifted to T costs. Um, that is a comprehensive
policy action. But if we make a value judgment that
just makes, draws a cut line in terms of a standard
substation level rate, for these resources. That is
not a system wide comprehensive policy action and that.
But the reason is, is because whether they are paying
their entire contribution in aid of construction and
then getting this price certainty for a monthly distribution
rate. The the impact is still at distribution level.
And this Commission does not touch distribution level
policy of the non opt-in entities. And I'm staring out
there at cooperatives and municipal utilities. And so
therefore, we would be only affecting policy for distributed
energy resources for the competitive areas of the state.
And so you would limit the geographic area where these
resources would interconnect with this type of stable
policy framework. So that's the trade off. And arguably
I would say that in the cooperative areas and the no
areas. There are very viable and valuable places for
these types of resources to be interconnected. And they
can already, there's there are more open pathways there.
In the noise than there are outside the noise right
now. They have more optionality on that right now,
than outside of ERCOT, outside of the outside
of the noise. They get, they get control of some parts
of their policy that we don't touch. Now that's true. They
have universal control over that. That distribution
for sure. Um that could be something to look at in
terms of A-B uh examining what's, what's happening in
some of those areas versus. And how have those approaches
been received? Well yeah, and in terms of the purse
strings that we control, we control the T side of the
equation. Because everybody comes in for wholesale.
I mean poor College Station, just look at what we just did.
Everybody comes in for T costs. Um but DCRF
applies to our the distribution cost recovery factor.
Applies to our competitive areas and um we don't touch
the noise. And um and that's that's a hard policy to
overcome um given PURA. So I think we just need to consider
that over the next two weeks. And and you kind of inform
yourselves on what you're, where you want this to head.
But there there are a lot of megawatts of resources
sitting out there, waiting on this. And
hard to figure out. Um well, these are tough policy
calls, right. And I appreciate the options you've laid
out. I think that ultimately making these decisions
on cost allocation and uplifting to T costs or or the
impacts of different types of um companies out there.
Whether they're in ERCOT or outside of ERCOT, as a co-
op or muni are very significant um policy calls. That
have a lot of different implications for different
types of companies even within those categories. Co-
ops that are distribution service providers versus
some that are transmission and distribution co-ops.
They, so if your DSP that doesn't have transmission
then how do you uplift to the, to the T cost? So
there's just a lot there to consider. I personally
don't know if I can get there in two weeks. I mean
we've been on a pretty long marathon here. And these
are very important issues that I want to spend more
time looking at. And so I don't know if that means
more time to the next open meeting or that means more
time to get our reliability standard.
Absolutely. And, and so I said two weeks just to hold
myself accountable to keep trying to develop this. And
force myself to focus on it. Now that I've got PC put
to bed and the Legislature is considering that. Um,
I'll certainly bear down on it with Commissioner Glotfelty
and focus. Um, it's also Staff resources, um, broadly
that reliability standard is the key to a lot of this
folks. And um, and that's where, why I appreciated ordering
the agenda the way we have, for this discussion purposes.
We have to be able to show the system level consumers
that they are experiencing benefit. And now that we
have adopted a standard where values are going to be
associated with that standard of an obligation on loads.
That's where you show the value of doing these different
things. There's a trade off. Undoubtedly these resources
provide value and we want to unlock that potential. Right.
Um, for reliability resiliency um as you mentioned
um, localized regional reliability. Right. These are essentially
would be like microgrids and we want to unlock that
potential. But I would like to do it in a very thoughtful
diligent way. And I know you guys have spent a lot of
time and still digging through these issues. And you
know, I know I can't get there in two weeks, but I
would like to have more time to really dig in. And maybe
it dovetails into the reliability standard, you know,
sort of discussion. But ultimately I think, you know,
as we move to adopt a reliability standard we'll have
a metric.
And then I'm not sure how we would sort of fit this
underneath, and I understand like the mechanics of
deliverability and their reliability benefits. So
I'm just wondering, um, at what point if we wait for
the reliability standard and how? Versus how much more
time we need to sort of unpack this very, very important
issues? Understanding that we have a lot on our plate.
And you know, we've opened the hood in every direction.
I mean we've opened the hood and we're working on everything
there is to work under the hood. I mean it's, this
is, feels like Christmas and so um, and Christmas wish
list for everyone. Well, to follow on your analogy, I've got parts all over the garage floor. Yeah, exactly. So I don't know.
And so um, you know, in terms of everybody, everybody's
issues are important. There's a lot of things we got
to get done for a lot of different folks. And I just
want to make sure that we have time to look at some
of these issues very diligently and thoughtfully. Um
so that's my perspective right now. I'm not saying
no, I'm not saying anything. But I recognize these
you know, resources are very valuable. I just want
to think about these issues some more and have more
time, and two weeks isn't enough for me. Fair. I'm sorry go on.
These decisions are big enough. That we all need to
make sure that we have time to, to analyze and deliberate
these things. Uh, I know expediency is always important.
I don't think anybody can accuse this Commission of
not moving quickly. On a tremendously wide range of
issues, but nobody's gonna force any of that. We're
not going to force anybody to make a decision before
they're ready, is I want to say. Yeah, I was gonna add that. Um, you
know, we didn't really have to, the Commission
didn't really have to cross this, um, this river. Um
when it came to wholesale generators interconnecting
at the, at the transmission level. Because loads pay
has been the um, the law of the state since we unbundled
in 1995. Um and I think that um, that was a good
policy. I think it makes sense. I think consumers benefited
from that, but you know, uh we could draw this out
for a long, long time or we could do it fairly quickly.
And and I just hope that and I urge all of ya'll
to take your time. But to do it, uh, take your
time to do it quickly. Yeah, you know, I'm not a fan
of paralysis by analysis. But I do agree with like
this, this is a big enough policy decision that we
need to be thorough. Um yeah, and I will assure you guys
that there will be, there will be no idle hands waiting
for the decision. And so uh, Mac and Mariah are gonna
be running running at full speed on some projects. And
so if it's not this, it'll be another one of the priorities.
So whichever, you know, it's not fatal if you need
a little bit more time on this, on this one. The one
thing, one last thing I might say is. That uh like all
of the changes in the industry that we're facing here
in ERCOT, um other regions are facing the same thing.
Um, so these are happening all over the United States.
So there's a lot that we can learn from what's the
pros and cons that they've done in the other regions.
And I hope we take some of that into consideration
as well. Yeah, well put. The 2 thoughts at offer.
One, it's wherever we end up on this can also be a
spectrum. It's not necessarily either or it can be
there's a spectrum of options. Um so just something
something to keep in mind as we dig into this further
Uh and then I think it also is worth noting that uh
like Commissioner McAdams said. I think the the first
decision we need to reach, at whatever time people are
comfortable. Is whether or not this decision is dependent
on establishing a reliability standard. One of the
big points we all made last week is that reliability
standard isn't just system resources. It's the how
they're deployed as well. And they're uh ability to
there's more, it's more than just having supply and demand,
right? That's an important component of it. I don't
know what the answer is right now and I think that's
probably the first fork in the road, we need to get
to. Does that make sense? Or am I missing something? Kinda.
Think on it two more weeks, Peter. All right. Um like I said
I don't, I don't know the answer today. But that was
a good point, I think it's worth consideration. Uh
any other thoughts, comments on this one? Or think we
can. I'll continue to work with Staff as as well as
Commissioner Glotfelty over the next two weeks. If anything
comes up but we'll keep keep working on it. Okay, I don't
think we need any formal action today. Yeah. Which will bring
us back to. Item 26. Thank you.
(item:26:53992, Chairman, Commissioners McAdams & Cobos on Entergy concerns) Item 26 is docket number 53992. This is the application
of Entergy Texas, for approval of rate schedule for
utility owned distributed generation. We have an order
requesting list of issues, parties have filed their proposal
list of issues. However, rather than drafting a preliminary
order, we posted this item for guidance and direction
from the Commission, on how to move forward with this
proceeding. All right, thank you ma'am. Thoughts, comments? Before
Commissioner McAdams tries to punt it to me, because
it's a MISO. I would like to remind Commissioner McAdams
that he filed a memo. I am wanting to withdraw his application so
I'm going to give him the floor first. I am going to pay for that memo for a long time. I can tell. Well played again Commissioner Cobos.
I did, I did um so I think that that's why I
requested we uh possibly order the agenda as we've
had. So that we had the high level um policy discussion
on DSRs, distribution level uh resources. And that was
based in ERCOT, Uh Entergy is clearly non-ERCOT, wholly
located in MISO. And um,
I get back to you need a. If you're trying to
spread the cost of distribution level resources and
again trying to get an entire system to pay for it.
I believe you need to be able to weigh that against
something. So that's why I suggested the reliability
standard was so important in ERCOT and what that means.
And to what degree that reliability standard transcends
down, not just from a system but also to a region. So
and enter Entergy's case you know the orange area. Which
was so heavily impacted by tornadoes, tornadic activity
over the last 72 hours. And so um
by having some type of standard by having some type
of metric that is positively impacted. Uh through the
deployment of these resources then you can justify
um spreading those costs. I don't really have a view
on how we do that. That's why I lean on Commissioner
Cobos and your experience in MISO, on what MISO has
going. I know that for SPPs purposes we have
a broad based reliability standard of 0.1 and 10.
But they are talking about expected unserved energy.
Everybody wants to grow into a more granular reliability
standard. Um to hold uh utilities accountability for
the reliability on a regional and regional basis. So
I'd like to hear from you on what MISO has? What
we can uh peg Entergy proposed policy to? Again, they're
proposing to expand the cost of these uh devices and
resources, to there's the rest of their system. Not just
beyond the scope of the pilot project for which they
are currently uh interconnecting. Um but how can we
how can we justify that? Sure. So some key relevant
facts are, the fact that MISO North. Well all of MISO
relies on a 1 and 10 reliability. The .1
LOLE. And currently in MISO North for the MISO
and North and Central regions. They're at a 0.179
LOLE. Which is approximately one day in 5.6 years
of liability risk. But with respect to MISO South,
where Entergy Texas sits. They are exceeding the 0.1
LOLE. So they're they're not in the same position as
MISO North and Central. And um I know that MISO
in general is looking to uh modify their market design.
They have a sort of capacity market right now. As we've
talked about where they ran the PRA, this past
April and they had a shortage. And um caused the prices
to hit cone in the in the Northern regions. North and
in Northern central and because of that they're looking
to expand to a seasonal construct. And and seasonal
accreditation and have looked at a minimum contingent
minimum capacity obligation. And and all of at least
the seasonal accreditation, the MCO. The minimum
capacity obligation are under um appeal right now. For
approved, all of MISO's filings except the MCO.
The minimum contingency obligation, capacity obligation
which is 50% obligation on LSC. So the whole sort of
broader market construct changes are still in flux.
But today MISO South um the reliability standard is
being met and exceeded. So which brings us to the point
I think what you're asking Commissioner McAdams is
you know what how can allowing Entergy to use these
um distributed resources, natural gas DGE. Through
this uh through their DGE proposal, help with help
Entergy meet their resource adequacy requirements,
in MISO. And so that that's the background I have
on that. I mean there's currently no shortage. And I'm
just wondering if you know as they sort of proposed
to bid these DGE facilities as Load resources into
MISO, through ancillary services etc. You know what
if these costs are going to be allocated to all ATI
customers. Then what is the benefit to the customers
um with respect to offsetting those revenues to what
they're paying ultimately would be responsible for
paying. Because we do know that when there's an emergency
outage, the host customers will benefit from the DGE
facilities, not the ratepayers as a whole. And so
from my perspective there is still some unique issues
in this DGE proposal. That that are issues of first
impression uh from my perspective that I would like
to further um explore. Once we have maybe a framework
in place like what we're trying to do with distributed
generation. As a whole in ERCOT distributed energy storage
resources as a whole. Um the difference here in my
opinion and I'm open to consideration on this. Is we'
re May 12th Open Meeting conversation, to what we're
dealing with here is that. The tariff issue that we
addressed there was underpinned by an existing PUC rule.
We have no PUC rule here. We we you know, per your
memo, we decided to ask the Entergy to withdraw their
application. Because we didn't have a rule and you didn't
want to conduct piecemeal rulemaking. So I'm just trying
to think of what has happened since then to now and
and the tariff issue was raised as a sort of an opening
for that. But I don't see it as apples to apples. And
I'm also wondering that now that there's a pilot. Why those
costs weren't included in the current base rate case
that was filed um not too long ago? Where we could have
started addressing these issues. So these are just
thoughts that and in questions I have in my mind. And
I'm open to hearing what you all think. Well well
put.
I know so Entergy is unique. They are in a hurricane
prone, tornado prone area of the state of Texas. I like
to you, Commissioner Jackson, you grew up in
that area, that service territory. So resiliency is
important to their customer base. Um as we see grocery
stores are interested in this, universities are interested,
hospital systems are interested in this. Um it clearly
for localized resiliency or at least for those, those
campuses and buildings. It will benefit those folks.
Under the tariff, um the current pilot framework. They're
paying for it. But again, if you want mass deployment
of this, you expand that to the broader system wide
tariff. Um but the question is, are we ready for that
at this time? Do we have enough bones in place to to
know what we're dealing with? In terms of the magnitude
of this, this new distribution level resource integration.
I don't know, I don't didn't feel like we do. Um I
think all your points are well taken and I think that's
a that's a good indication that we don't have those
bones in place. We don't have the structure in place
yet to decipher all of this. Um
it's it's maybe a little premature for us to be asked to
make this decision. So, in in terms of a path forward.
Look, we've gone back and forth on this, but we've
also been contemplating a lot of uh wholesale changes
um within the grid, ERCOT or outside of ERCOT.
We we thought we might use this as a vehicle to set
policy. Entergy files it we certainly saw an opportunity
there. Um do we want to go back in terms of the
enormous workload that Staff already has to manage.
And consider a rulemaking approach or does this, does
this have to sit for a time under the existing framework.
Again, there is no downside risk to create uncertainty
on what is the law. House Bill, House Bill 1510 on
what that created uh and what Entergy is currently doing
now. In terms of the constraints on socializing costs.
But that would not change. But in terms of a rulemaking
to establish a long term approach, do we want to consider
that idea at this time? Or are we still dealing with
too wide of a universe to plug this in there right
now? And are we gonna tie our hands in a later rate case?
Correct. Yeah, that's a really good point. Um
I think it's either
we don't want paralysis by analysis. But I think there's
we either need to get to a point where we've put enough
bones and and structure around it, at the comprehensive
level. Um or a rate case. Um either of those would be
the appropriate time to cross this bridge, but neither
of those are today. Or the Legislature could pass a law
and just tell us what to do. That would be cool too. That's
always a good option. Yeah. I can see that what they're
trying to do here and and you highlighted with the
hurricane prone and you know, tornadic, I like that word.
Um tornadic risk, you know, um that is in the area. And
it's just, you know, we're trying to set some kind
of a policy framework here to deal with all kinds of
distributed resources. Right. And, you know, in a diligent
prudent way going forward. And so how do we get there
an efficient manner. I think what what provides me
some comfort is that they currently have a pilot in
place. And they can continue to move forward and, and
you know, build upon that program. And eventually, you
know, we'll either do a rulemaking or they'll come
in for a rate case, when Legislation gets passed. Something
you know, I just feel like we need to have a framework
in place. Because there are a variety of underlying
cost allocation issues, that we need to be mindful of.
Agreed. Um, I mean, I think the right move here listening
to this discussion. Is that we, we definitely don't
want to take any other action the table or, or uh,
I think hopefully Entergy is listening to this conversation.
And recognize that we were not ready to move forward
on this uh, today or even in the next couple of months.
Um, so not in two weeks, probably not two weeks. I think they
should be commended for their forward thinking. And
you talked about a hurricane prone area. Um, you know
the a gas station that's able to um, to start up after
an event. When the rest of the community is devastated,
provides a beacon of hope. And so there's there's certainly
I think in this area is obviously growing. And it's
a, it is a key industrial area. Also provides an escape
route for all those inhabitants in that area. So, so
many, many reasons. And I think, you know, the fact
that they're thinking about this and have come to the
Commission, I think is a very positive thing. That
you know, to your point, um, from a timing standpoint
not to be forgotten and not to be kind of put aside
forevermore. But um, just waiting until we have a little
bit more structure in place. But I think they definitely
are to be commended for thinking about this. Yep. All
right, we're all comfortable with tabling this.
Yes. Yes, for the time being. All right, consider it tabled.
Well, I think we need to give direction back. I mean
based on our conversation with respect to what happens
to the application. Do we ask Entergy to withdraw the
application or send it back? So, that.
Good point. I think we can ask them to withdraw. I'm open to other
ideas. So remand. I'll jump in, yeah. I mean, I would say that
your discussion has been fairly clear. I think Entergy
probably has heard your, that the Commission is not
ready to act at this time. Withdrawal is certainly
an option, um, and then. Leave it to them.
And then it's possible that, you know, in a certain
amount of time the ALJ could take action. Okay, so
we can table for now and in two weeks?
Or do you need a direction to the ALJ now? Oh, I misunderstood then. Do you want to table
it for two weeks? Or did you want to abate this? Or
do you want.
Do we have something more to discuss in two weeks?
No, I'm not. Whether or not
So, so uh is it remand back to the ALJ, with instruction
to uh ask Entergy to withdraw? Or consider dismissal if
Entergy hasn't withdrawn within a certain amount of time.
Certainly. How about remand with instruction to dismiss
within two weeks. There's our two weeks.
You got a motion? So moved, consistent with our discussion.
Second. A motion and a second. All in favor say, aye. Aye.
None opposed, motion passes.
All right, good discussion. Next item please, Ms. Cisneros. All right.
(item:27:21072, Commissioners Glotfelty & McAdams on natural gas capacity concerns) That takes us to Item 27. This is project 21072, goal
for natural gas generating capacity. Commission Staff
filed a memo and a proposed order. Requesting a waiver
of Commission Rule 25.172, and certain subsections.
Thank you, ma'am. I know this is something we've it's
an annual issue we've considered before. Any thoughts or
comments? Yeah, Mr. Chairman, I would have consented
this except for I just wanted to bring up the issue.
That um this goal for natural gas um includes in it
a mechanism. If our capacity for natural gas drops below
50% that a trading mechanism be put in place. And I
wanted to highlight that as a discussion item for us
to think as we go forward, on all of the market design.
That if we have an ORDC, we have a
PCM and then kicks in a natural gas credit system.
What that would look like at some point in time? We're
a ways off from that, uh, drop below 50%. But I just
wanted to highlight that. That is something that's
there. We've talked to Staff about it and I think there's
a discussion, um, you know, that that needs to happen
in the future. This is not immediate. But just a understanding
that there's another mechanism that has already been
put in law in Senate Bill 7. That that considered
the issues associated for the system, if we fell below
50% natural gas. Thank you, Representative Tommy Merritt.
Um, and um, just to highlight that for the, for the
Staff, uh, and the Commissioners. Just point of clarification
is 50% excluding renewables, right. I'm sorry. It's
50% excluding renewables. Yes. Right Okay, so 50% of the
dispatchable fleet? Yes. According to you. Again, that
was my bone of contention the last time I, and uh,
I have the deepest respect for Staff and their interpretation.
But the policy mechanics, uh, that were clearly intended
by the Legislation do not make sense. If you exclude
renewables. I mean, what, what is the point? Um, so
Kathleen, you're new to this. I voted against this
the last time. It was a good joke. Um, at the diose
that day. But if, if the, if the underpinning of the
calculation is that the system requires over 50% of
our capacity to be uh, natural gas driven, and natural
gas powered. But subtract out the renewables, renewables
is the dominant share. So if you're not counting the
renewables, what is the point of what they put into
law? And there clearly was a discussion. I've talked
to many people who were around at the time. And they
agreed, but it's in there. Staff has a good sound reading
and good history, underpinning that reading. I just
disagree. And uh, and I've already voted no once on
that. So I think I'm gonna be a historical no on this
interpretation. As uh, as is your privilege. Thank you sir.
Wonder what, what is our current, uh, the current under
the current interpretation of the rule percent of natural
gas out of our total dispatchable resources installed
capacity.
I think. I think you went around Commission Staff, based off the current calculation
for new generating capacity. That's been put into the
system since 2000 excluding renewable energy technologies.
Um, we calculated that was approximately 88.6% of the
current capacity to put on the system since 2000 was
fueled by natural gas. Um, and we project for at least
the next three years. That's still not gonna get anywhere
near the 55% that is required to trigger the natural
gas energy credit training program. Thank you sir. Of
our dispatchable fleet, we got a pretty healthy amount
of natural gas. We do. Well, not healthy enough. I was
questioned. I thought that was a very good point that
you made, Mr. Chairman. Of the dispatchable fleet and
as always, I'm sure Commissioner McAdams and the rest
of us would welcome clarification from the Legislature.
That would be great if they could ever do that.
All right, another good conversation. Any other thoughts or
comments? Or a motion to approve the proposed order?
Got a motion and a second. All in favor say, aye. Aye. Any opposed? No.
Motion passes. Thank you all. Thanks Werner.
All right. Next item I think is item 30, does that track
Ms. Cisneros?
(item:30:53298, Kristi Hobbs, ERCOT VP, update on a bridge mechanism) We have an update from ERCOT on the instruction from
last week, to bring back information on a bridge mechanism.
And I believe Kristi Hobbs is here to present.
All right. Good morning Chairman, Commissioners. Kristi
Hobbs from ERCOT. So following your discussion last
week, in your direction at the last Open Meeting. We
returned back to kind of start our planning and wanted
to, we filed a memo in the docket for your reference.
And like to just lay that out for you, our plans to
get back to you a recommendation from the ERCOT board,
on the bridging solution. And so what we will do internally
is we have started an effort to start to put together
a menu of options for consideration and deliberation.
We're gonna have several goals that will take into
account as we look at ideas. Look at the pros and cons.
Our first goal that we've laid out of course is retention
of our existing fleet. That's our number one goal in
coming up with a solution. Our next goal would be to
consider incentives that may incent new generation.
To be dispatchable generation to be added to the fleet.
Following our third goal would be uh, do we have an
opportunity uh, to the extent possible to limit the
use of the reliability commitment mechanism. Overarching
all of those goals would be to um look at the opportunities
as we always do in anything we do in our operations,
to optimize cost to consumers. So we'll be taking that
into account as well. What we'll do in the next coming
weeks is we will work on putting together a list, a
menu of options. To have in preparation for consideration
at the February Meeting of the Reliability and Markets
Committee of the ERCOT board, to get direction from
them. Because that will be the first time they will
meet since your deliberations last week. We'll take direction
from them. We would intend to hold ERCOT led stakeholder
discussions. Because we feel it's very important to
get feedback from those that would be impacted by the
changes that we would be making. That would allow us
to bring a final recommendation to the April Reliability
and Markets Committee and board meeting. Where they
could then consider and make a vote in a recommendation
that we could bring back to you all. We would plan
to file that by April 20th. To give you at least a
week in advance to be able to consider that and deliberate
at your April 27th Open Meeting. It's all pause there
to see if you have any questions or feedback on our
plan. That makes sense to me. Thoughts, comments? Just
two clarifying questions. So the options would be focused
on the retention of the existing fleet. And also to
that would also send a price signal for the retention
of that fleet? Correct Okay. And then when RNM
consider finally considers um the options, will that
go up to the full board for approval? Yes, that would
be at the April board meeting. Okay, thank you. Yeah
I like the way the timeline syncs up. Uh the Legislature
is also watching and we'll be able to see kind of what
stakeholder driven options. Because as Kristi alluded
to, it's very important to have their input. On how
we can again to withdraw ERCOT out of that command
and control posture and let that market start to work
again. Um It's very important for the Legislature to
to see that we are in progress, that progress is moving.
And um and to watch the new collaboration between stakeholders,
the ERCOT board, and ultimately the PUC, on such an
important matter. So I think the timing's just right.
And I thought the information that Dan Woodfin provided
at the TAC meeting. Would be very good information
for the RNM Committee to have before them. That
highlighted the number of effective RUC hours that
were conducted in 2021, 2022. And what specific resources
have been the most impacted for RUC. Since the presentation
you provided yesterday, I thought was very helpful
and illustrative. Of the amount of RUCing but also
which how old the age range of the units that are primarily
being RUCd.
Good points all. All right, thank you Kristi.
We've already covered item 31. I don't have any thing
on 32. (item:33:54444, Chad Seely, Senior VP ERCOT & Marcia Hook with Kirkland & Ellis on firm fuel) Brings us to item 33. I believe we've got a
memo from ERCOT and Chad Seely's here to lay out our
progress on the second iteration of firm fuel.
Good morning Chairman, Commissioners. Chad Seely with
ERCOT. Also to my right is Marcia Hook, who's ERCOT outside
counsel with Kirkland and Ellis. Uh, we want to talk
about Phase II of the firm fuel supply service. Um
on Monday, we filed a request for guidance letter but
also attached as Attachment A, our proposed framework
for Phase II. And primarily what we're looking for
today is some guidance on the definition of qualifying
pipeline. I've also asked John Arnold, which is a partner
with Locke Lord. Um if the Commission desires to have
him present for um Kinder Morgan and Enterprise. Because
I think it's highly relevant for the Commission to
hear their perspective around this definition of qualifying
pipeline. Um, but before we engage the Commission in
the kind of the risk management policy discussion around
the qualifying pipeline definition. I thought it'd
be useful for Marcia to talk about the framework document
that's attached to the letter. Because there are fundamental
differences here in Phase II versus what was in Phase
I. Which was resource entities that own the storage
on site or if it was offside, they own the storage
facility and had ownership of the pipeline as well.
So as we move forward to Phase II, obviously we're
interacting with third parties, uh the gas suppliers
and producers here. And it's a different structure as
we move forward. And so I'll turn it over to Marcia
just to kind of spend a few minutes to highlight
the key features in the framework that I think are
important for the overall policy discussion. And then
we'll turn back to the qualifying pipeline definition.
Good morning. Um I summarized in the filing, hopefully
you can hear me a little quiet even with a microphone.
I'm a partner at Kirkland & Ellis as Chad said. I'm
outside counsel for ERCOT with respect to development
of the Phase II FFSS program. So at a high level
the framework document which was attached to the filing
that Chad referenced. Contains certain key requirements
for resources to participate as Phase II FFSSRs. And
we'll highlight four of the key elements. First, the
generation entity that owns the generation resource
or an affiliate of that generation entity must own
and have good title to sufficient natural gas in a
storage facility for the generation resource to deliver
the offered megawatts for at least 48 hours. The generation
entity also must commit to maintain such quantity of
gas in storage at all times during the obligation period.
If the generation resource is selected as an FFSSR
and is deployed such that it's reserved gasses
depleted. It may request permission from ERCOT
restock. Alternatively, ERCOT may direct the FFSSR
to restock. Second, the generation entity or an affiliate
must have a firm gas storage agreement with the operator
of of the storage facility where the gas is being stored.
For sufficient natural gas storage capacity for the
offer generation resource to deliver the offered megawatt
for at least 48 hours. The firm gas storage agreement
must, among other things, have a maximum daily withdrawal
quantity. That permits the generation entity or its
affiliate to withdraw from storage a daily quantity
of gas sufficient to allow the generation resource
to deliver the offered megawatt over a 48 hour period.
Alternatively, a generation entity may use own storage
capacity as long as it has sufficient storage capacity
and withdrawal rights to meet the requirements previously
described. Third the generation entity or an affiliate
must have entered into a for a firm transportation
agreement which is a new definition. For firm service
on a qualifying pipeline. Chad will discuss the qualifying
pipeline requirement later. However, there are several
other substantive requirements that an agreement must
satisfy to qualify as a firm gas storage agreement
or firm transportation agreement that we wanted to
highlight. A particular note to qualify as a firm gas
storage agreement or firm transportation agreement.
The agreement must provide the generation entity or
its affiliate the right to monitor daily balances of
storage capacity or flowing natural gas, respectively.
That is a hallmark on jurisdictional pipelines, but
it is not generally provided in interest state storage
and transportation agreements in Texas. The agreement
also must require that the storage facility or pipeline
operator make available to the generation entity or
its affiliate. A detailed accounting indicating a reasonable
estimate of daily and month to date receipts and deliveries
of natural gas. Again, this is not traditionally a
hallmark on interest date uh agreements. So further
the agreement must contain a qualifying force majeure
provision. This is a definition that we propose to
add. A qualifying Force Majeure provision is a force
Majeure provision that includes certain contractual
language including that before a pipeline. The pipeline
or storage provider may suspend its performance due
to force Majeure. The pipeline or storage provider
must exercise due diligence and must incur reasonable
costs, prevent or overcome the event of force majeure.
Finally, there are a number of ongoing obligations
that would apply to Phase II FFSSRs, notably if a
generation resource selected as FFSSR fails to deploy
due to a force majeure event. The generation entity
would need to provide a report to ERCOT. That provides
certain additional information. ERCOT also would have
other remedies against the FFSSR including but not
limited to the clawback of 90 days of availability
payments. ERCOT receives substantial input from participants
in the electric and gas sectors on the draft framework
and the draft file with the Commission reflects that
input. For example, numerous commenters suggested that
allowing bundled contracts that provide for gas storage
and transportation and one agreement should be permitted.
As such contracts are common for interest state pipelines
in the Texas market. The current draft of the framework
would allow a generation entity to use such a bundled
agreement rather than have a firm, a separate firm
gas storage agreement and firm transportation agreement.
However, the area where received the most comments
was on the proposed definition of qualifying pipeline.
And and that is the key area where ERCOT seeks Commission
guidance and I will turn it over to Chad to discuss
that that request for guidance. Okay, thanks Marcia.
So again, the qualifying pipeline has been a great
discussion with both industries, the electric and the
gas industry. And the way in which we struggle that
structured this is to be very conservative. Because
when we were going in developing this Phase II, we
want firm service to really mean firm delivery of the
product to ensure reliability for Texas consumers. Um
when you look at the interstate construct, the framework
was developed on the Railroad Commission and their
curtailment roll. Under that rule, the generation resources
are secondary in priority to human needs customers
and LDCs. Uh and so in a in most
of our generation resources are going to be connected
to intrastate pipelines versus interstate pipelines.
And so in a weather event where even if you had firm
commitments under that extreme scenario where it played
out in the gas utility. That makes the decision on when
to curtail because of the way in which the Railroad
Commission's role is structured. When they make that
decision, the entity that's going to be curtailed first
in that priority between human needs customers. LDCs
and generation resources is the generation resource.
And so when we defined this definition of qualifying
pipeline, we made it clear that the definition for
eligible pipelines would apply to FERC interstate pipelines.
Because they have a different structure for their curtailment
provisions.And any pipeline that is not serving an
interstate pipeline that is not serving human needs
or LDCs. Because we want that generation resource to
have the highest priority to ensure that the gas is
getting to the resource to provide that service. A
lot of comments came in as Marcia indicated. We have
the workshop in which there were over 100 participants.
On both sides of the industry our resource entity
friends along with the gas industry. Stress that that
if they had a firm commitment that there was a very
low risk that there would be a curtailment of these
resources. But again, you still have to struggle with
the reality with the Railroad Commission's curtailment
role means at the end of the day. And of course every
weather event is different and you can't look at a past
indication of performance to indicate what future performance
would be under that scenario. So we maintain the definition
of qualifying pipeline to be the most conservative
and have filed this request for guidance to to engage
the Commission on their feedback. As we move forward
to try to structure the protocol language and move
forward with this. To try to have a product in place
for the next Winter season. Our goal obviously was
try to get this finalized no later than the June
board meeting. It's possible that we could get the
protocols in place by the April board meeting. But
we stand here today to seek guidance from the Commission
on this qualifying pipeline. Also in the, in the, in
the letter, we asked for guidance on three other topics.
The there was a lot of discussion around the duration
of this product right now under Phase One, it's 48
hours. Of course, everybody knows here in Texas, we
have a lot of gas supply and that they're likely as
the opportunity to have a longer duration product here.
Um similar to Phase One, we would ultimately seek guidance
on the amount of megawatts procured for this Phase
II. And then we wanted to highlight some of the comments
about additional resources participating in this program.
Uh and so those are kind of the core four elements
um which were requesting guidance from the Commission.
So all that being said, I do think it would be helpful
for, for John Arnold uh the Commission so desires. To
come forward and kind of, he, he has a presentation
and kinda highlight the gas industry's perspective
on on this issue around qualifying pipeline. Thank
you both. I think it makes sense to call up Mr. Arnold.
I have (inaudible) this over. We've got five copies here.
(item:33:54444, John Arnold, Partner with Locke Lord on behalf of Enterprise Products and Kinder Morgan Inc.) Good morning Mr. Chairman, Commissioners. For the
record, my name is John Arnold and I'm a partner with the
law firm of Locke Lord and I'm here on behalf of Enterprise
Products and Kinder Morgan Inc. Uh and in
particular, their efforts in support of the development
of the Phase II firm fuel service for offsite gas
storage. Um, Chad has has teed up the issue nicely
and I don't have a overly extensive presentation. Fortunately,
I've had the opportunity to meet with each of your
offices and discuss from a background perspective. In
the early days of developing this product to now addressing
the qualifying pipeline issue. Um Chad has laid out
the concern that the current definition of qualifying
pipeline addresses with respect to the Railroad Commission's
curtailment. Or what I'd like to do is help you understand
the consequences of that definition. But also help you
understand some of the reliability features that we
know from Winter Storm Uri. But to Chad's point about
that's no guarantee of future performance. To also look
at how we have some assurance with respect to future
reliability of delivery. Even with respect to the current
framework of the curtailment. So a few facts, assuming
that the definition of qualifying pipeline continues
to exclude by definition intrastate gas utility pipelines.
You'll hear me use the phrase intrastate gas utility
pipelines. That's the regulatory status of an intrastate
pipeline that delivers gas to customers like generations
generation resources in ERCOT. On page three of the
presentation, so skipping past the preface with respect
to the qualifying pipeline issue. 85% of ERCOT generation
resources are served by intrastate gas utility pipelines. 63%
of the gas storage withdrawal capacity in Texas that's
served by intrastate gas utility pipelines. All of
these pipelines that provide these services to generation
resources. Also provides services to local distribution
companies and local distribution companies, your local
gas utility. And we use a reference to LDCs as a proxy
for the notion that they're serving human needs customers.
The consequence then, is that the current definition
of qualifying pipeline will exclude the vast majority
of gas that is available to support the firm fuel service
um in Phase II of the project. In other words, to
make offsite storage and transportation to generation
resources. In the second phase of firm fuel work to
any intended scope for this second phase or any scalable
phase for future use excluding Texas intrastate gas
utility pipelines. Will create a severe limitation on
the available gas to support the product. Let me use
Kinder Morgan alone as an example of the impact. Kinder
Morgan's intrastate gas utility pipeline served 24,000
megawatts of generation resources in Texas. That's 43%
of ERCOT's gas fired generation resource capacity. It's
gas storage currently in Texas, about 20% of the available
gas storage capacity and it has plans and is currently
developing that capacity to expand. Such that it represents
nearly a quarter of that capacity.
I can also convey some of this data and statistics
graphically. I think you all have seen a map that was
prepared with energy information administration data,
by Enterprise Product and present presented to your
offices. On page four of your presentation you will
see a map depicting the relative locations of interstate
pipelines. Generation resources of two different sizes
as well as the interstate pipelines and available gas
storage resources. And what you notice in this photo
is right down the I-35 corridor, that Central spine
of Texas, there is no available gas delivery. If you
turn to page four, you'll see the intrastate system
which is far more granular. And clearly provides the
the interconnectivity that's required. To ensure the
gas delivery reaches the generation resources that
would be depending on the firm storage and transportation
contracts to offer in this firm fuel supply ancillary
service. Let me talk about reliability for just a minute.
With respect to Winter Storm Uri, and I have spoken
to both Enterprise and Kinder Morgan. And said, okay well
we know what happened in Winter Storm Uri. With respect
to gas withdrawal from storage. Both of these companies
issued no enforcement adjure notices. They provided 100%
of the contracted capacity that generation resources
requested. Neither neither of them curtailed gas to
generation resources when that gas was backed by a
storage product. That's that's an important lesson
from the past. I confirmed that the same was true during
Elliot. So we're seeing some resiliency here with respect
to when you've got a firm gas transportation and firm
gas storage contract. That under the harshest of weather
conditions it's gonna deliver the gas to the generation
resources. What about moving forward? What about how
do we know that this is gonna be effective going forward,
in the face of the existing curtailment order from the
Railroad Commission? Number one we know the underground
storage facilities and pipelines are naturally weather
resistant, they're buried, they are underground. The
new weatherization and critical infrastructures rules
of both the Railroad Commission and the PUC have hardened
if you will. The above ground facilities like compressors
that move the gas. One thing I'd like to highlight though
that's really critical and Chad touched on this. Is
that with respect to the Railroad Commission's new
curtailment order. It is not the Commission that invokes
the order, it was specifically drafted such that the
gas utility pipeline gets to decide if it must invoke
a curtailment event with respect to its gas delivery
obligations. And what that means is it assesses its
ability to meet its firm delivery commitments. Now
remember, this is, let's look back at the track record
from Uri and Elliott. There were no force majeure
when that gas was coming out of storage. It resolves
the fundamental problem of Uri, which was a supply
problem, not a delivery problem. The supply problem
is resolved by the presence of that gas in storage.
It's also important for this Commission to understand
that the gas pipeline and storage market in Texas has
been evaluating this product very carefully. And understanding
that it provides an important incentive to competition
and growth and development of facilities. We've seen
this with respect to Kinder Morgan's market facilities.
We've seen it with respect to Enterprise investing
in greater dehydration so that it has a higher rate
of withdrawal capacity from its facilities. It is a
key incentive that I think is going to bring some market
solution to some of the competitive issues that this
Commission has heard about. With respect to the performance
of pipelines across the state. So, I would urge the
Commission to strongly consider a definition of qualifying
pipeline in the firm fuel service that does include
intrastate gas utility pipelines on that basis. I'm
happy to take any questions. All right. Thank you, Mr. Arnold.
I'm sure we'll have lots of questions and comments
(item:33:54444, Chairman Lake's comments to ERCOT and attorneys)but if you'll allow me I'll lay a little groundwork. I know
ERCOT has been well, first of all, um thanks to the
team and our attorneys. Uh this has been a, as you
all know, a lot of work going into this. Uh and thank
you, John and Kinder Morgan and Enterprise have been
excellent partners. Working through all the different
combinations and permutations of this. Um and as you
all know, as well as anybody, none of this is straightforward
it's all complex and both of those industries are complex.
And even more complex when you, you kind of start working
on integrating a new product there. So I want to say
again, Kinder Morgan, Enterprise have been excellent
partners. Um and Peggy Hague from the ERCOT board has
also really led the charge on this. So I want to commend
her for her insight and expertise on this. Uh and I
know I know ERCOT and Peggy from the beginning have
been working towards defining a performance result.
Not trying to pick and choose which pipelines are included
or not included. Uh nobody in the ERCOT team or Peggy
ever sat down and said should it be an interstate or
intrastate. As Chad alluded to, they said, they started
this entire project, defining what performance we want.
Uh and what uh and what will deliver our consumers
a truly firm product. So that, and that's an important
distinction. And I know, uh, this, this Commission's
intention and, and Peggy the board and ERCOT Staff
have also worked on from the thesis that. We don't want
to use rate pair of money to pay for the same behavior.
We don't want to pay for the same thing and John you
alluded to changes in improvements in competitive options
uh, and so we want to drive behavior. There's a lot
of different ways to do that. There's some on the pipeline
side, like the things John mentioned. There's some
on the generation side like dual connection building
new infrastructure. Uh, so it's, it's, it's on both
sides of the equation, but the ultimate goal is to
put this ratepayer money out in the marketplace for
both industries to compete for. To enhance their reliability
by changing their behavior, their infrastructure, all
of the above. So that's, I know that's an important
foundation uh, that we, I know, I know we've been working
on that foundation from the beginning. Um, there are
still as Marcia alluded to, there's still some open
questions about bundling. And of course John's, uh,
highlighted the qualifying pipeline definition is really
a key or critical sticking point. Um, and I'll be frank
I still, I still want waiting uh, and still have a
lot of answers to be, uh, that I'm waiting to hear
about. And just, and somewhere I know ERCOT has some
open questions from my partners in the gas industry.
So, uh, I'll just tell you all the gates, I think this
is another one that I need another two. I'm gonna use
my two week card to another two weeks on this one.
Um, but but that's all I say that all in the spirit
of of the good conversations we're having with and
dialogue with Kinder Morgan and Enterprise. Uh, one
of the key things is getting more information about
performance during Uri. Certainly commend Kinder Morgan
and Enterprise for the delivery during Uri. Of all their
firm products. Uh, but it's it's an open question and
I think it's an important question asked. Obviously
there weren't as many firm gas contracts during Uri
as we needed. Uh, and so would that, and not just for
Kinder Morgen, Enterprise. But for system wide, our intrastate
pipelines. Would everyone have been able to deliver
that during Uri conditions, if 80% of our gas generators
had those kind of firm contracts? Instead of just 10
or 20%. Um, I don't know the answer, but that's that's
an important question. I certainly hope it's a positive
response. There's also some open questions. Uh, and
and the Railroad Commission has also been very helpful
throughout this. On the difference in uh, the distinctions
between molecule ownership, both in storage, it clearly
need to be the generator, but in transport, uh, the
curtailment restrictions under Railroad Commission
rules. If, if it is a regulated pipeline that is that
owns or is responsible for shipping those molecules
versus the pipelines that's selling the capacity within
to move those molecules. Uh and if the curtailment
rules apply to, for example, a third party shipper.
Uh, an outside party party or even an affiliated element
of a regulated pipeline. Uh and and so that's, that's
still one of the open questions. I think as we work
through that, I think there's some, there's some opportunity
and that's what I think we need to keep digging, keep
working with our industry partners. Uh we clearly don't
have the answer today. Uh, but I think the most important
thing is we keep digging through those issues uh, to
make sure if there is there is a way to capture the
most gas possible. That is truly firm and delivers the
performance to our generators and that's our ratepayers
that's worth the money we're paying. That we should
we should work to find that solution or exhaust every
option. So that's, that's my reasoning behind wanting
a little more time. And again, appreciate Kinder Morgan,
Enterprise for, for all the, all the hard work on this.
Um, they've, they've been very helpful and and done
a good job and we'll continue another ERCOT team will
continue working with them. As we continue to dig through
the options, dig those nuances and exhaust every every
possible option. To make sure this is the best product
possible. And we'll certainly continue to be available
to answer any questions you have about the way that
the business operates. And the way it can best support
the firm fuel services. Appreciate it. Thoughts, comments?
I do, I do have a couple questions. Is there a way
to bifurcate the definition of qualifying pipeline?
Based upon, is a and should this be done or could
this be done? Um based upon where it is around the state.
Obviously, I think your maps show that uh, Gulf Coast.
Obviously you've got a lot of inter and intrastate
and uh in the Central part, the I-35 corridor up to
Dallas. You don't have almost zero interstates and
lots of intrastates. Um is there a way or a reason
to define those differently? My concern Commissioner,
would be with respect to the competitive signal part
of this equation. So with respect to creating a bifurcation
that sets that limiting principle. Have you limited
then the incentives for the growth and development
of new storage facility, new pipelines to serve generation
resources. In other words, making sure that that cut.
And we talked about making policy cuts in the implications
of that. As an outgrowth of that, you may limit geographically
speaking some of the places where you might have wanted
this product to serve as an incentive for growth in
competition. (item:33:54444, Commissioner Glotfelty comments to John Arnold) So you see that a uh, well, that makes
sense unless it becomes a trigger and the growth of
competition in storage types of facilities. In that
Dallas, I-35 Corridor region if competition allows
regulations to go away. And then you get back to a single
definition across the entire state. Um I mean I think
that I think that the maps are pretty obvious. That
uh that if you look at the population centers across
the state other than, other than Houston. We've got
uh you know, an interstate avoid um up the I-35 corridor.
Um uh I think that we ought to find a way to
ensure that intrastates are in this. But um I think
it's it's a very fair question that um on this order
of curtailment. Um we're really putting those that
have gas heat above those that have electric heat.
Um you know, if if human needs are um, you know, considered
the number one priority or the last priority and curtailment
and and we're the second to last. And and that's not
something that I'm yet comfortable with. You know,
just saying that one kind of heat source is different
from another, when it comes to two major weather. Um
It's interesting that you all have 20, that Kinder Morgan
has 24,000 megawatts of gas on their intrastate.
Is are human needs contracts? So is a contract to an
LDC um the same. As a in other words, do
they have firm um resources. They do. So on on those, 20 on
the Kinder Morgan's pipeline system, how many megawatts
of firm gas or transportation do you have for human
needs? It's the breakdown is the LDC represents
about 15%. 15 . Whereas the generation resources represent
about 32% and industrials are 30%. So they're actually
less than half of the total. 96% of the customer base
is served on a firm on a firm basis. Um so that
includes the LDCs but that's only 15% of the total
gas load represented by service from those pipelines.
Okay. And that's one of the questions we're trying
to work through in terms of system wide, right? Because
if it's um you know, if system wide LDCs are only.
You know, which by definition are firm regardless of
the contract says they're by definition of the Railroad
Commission rule, their firm. If that's only 10%. And that
will vary. It's it's a it's a good question because
it will vary from system to system. That's not, you
know, we don't have a gas delivery system, so to speak
within Texas. We have a bunch of different gas pipelines
that provide service to customer bases that they designed
those pipelines to serve. As opposed to operating on
an integrated grid like basis. So it will vary from
pipeline pipeline. Right. But for our purposes we need
to know how the whole system comes together. If LDCs
are 40 or 50% of total of the senior stack essentially
that's one thing. If it's 10% that's very different.
But this is the, these are the kind of questions were
continuing to dig through. Can I put you on the spot
here? Have you not already? Not like this question. Uh oh. Well, so
would you rather have a modified definition of qualifying
uh, facility to include intrastate pipelines? Or would
you rather have the Railroad Commission change the
order of curtailment? And and include electric generation
in the human needs category. That's a good question. I'd rather have the
former than the latter. Um but I will say this um I
know from extensive conversations with the leadership
for example, at Enterprise and Kinder Morgan. That they
very much view um service to generation resources on
a par with delivery of gas to LDCs and human needs
customers. They would they view them equally um from
the standpoint of their customer base, from the standpoint
of their view of the priorities. Um I recall having
this discussion with the CEO of one of the companies
said, well wait a minute, you know my heat is electric.
To your point, um why would that? He said I was called
during your Uri, I would have liked to have that heat.
Um I there is, I think a certain view in the industry
that those are very much on par and hopefully can be
treated as such in the future.
(item:33:54444, Commissioner McAdams to Chad Seely & John Arnold) So Chad remind me of Phase I firm fuel, how much
did we use during Elliot as a baseline benchmark to
compare what our needs are? I think we ended up deploying
8 resources out of 19. And I think uh one of you
may need to come up. But I think the the maximum amount
was around 900 megawatts or so, is that correct? So
around 900 (inaudible) megawatts and we did make the decision.
Because this happened in December to go ahead and refuel
those, those 8 that we deployed. Yeah, that totally
makes and sense. In terms of magnitude of of our use, which
any as per the questions asked, which we won't address
yet. But uh any type of survey um would demonstrate
that um and and consumption rate that. Look every megawatt
helps, that we can contract for. Every megawatt helps
make costs manageable for consumers. But also for your
uh the purposes of your forecast and ability to know
that you can manage through any contingency. Um we
have a great tool in the toolbox right now with Phase
I. Phase II is certainly appropriate and and I encourage
the Commission to not close the door. Look ultimately
Phase III's can be in the future, you know, if we
don't get this absolutely perfect right now. But looking
at your map, Mr. Arnold. North Texas is the void of the
type of uh competitive storage facilities that would
absolutely help our system be more resilient. And meet
any type of reliability standard. Manage expectations
for the part of the grid operator that we can effectively
manage through a large scale Uri type event. And so
just having it concentrated along the Gulf Coast doesn't
solve our problem. And we've got to get more infrastructure
up in North Texas. Ultimately the policy approach that
we are pursuing is to create a market and you're effectively
doing that Mr. Chairman. By saying, look, we were gonna
have a product out there if you can match our needs.
There is going to be ample um uh revenue um for your
gas suppliers to build infrastructure and to supply
that need. Um but I do, I think we need to be
iterative about this methodical um, I think all eyes
are upon us. The Legislature is clearly watching this
and ultimately uh we need to analyze this on an iterative
basis. Because Railroad Commission's policies will evolve
as our own policies do. And it is my hope that one
day um generation is seen in parody uh under a human
needs test with all the other populations that are
already accounted for. Because ultimately, I mean the
systems are, are tied together. Um so I I appreciate
the thoughts, I appreciate the work that Kinder and
Enterprise are doing, to provide those competitive options.
For our generators, but I think we need to think long
and hard about this.
(item:33:54444, Commissioner Cobos comments to Chad Seely & John Arnold) So a few comments it with respect to ERCOT's proposed
definition of qualifying pipeline. If we were to change
it and modify it to include intra, intrastate pipelines
that um serve human needs customers. Recognizing that
Kinder Morgan, Enterprise per per your feedback. Has
had a successful history during Uri and historically.
If we were to modify that definition, um, that would
include other pipelines besides Kinder and Enterprise.
So we have to be mindful of that, that impact. And although
Kinder and Enterprise um may have had good performance
we we're going to open the the gates for all intrastate.
I don't know how you make a cut and and maybe that's
part of your questions you still have out there. Absolutely. Um
with respect to how do you strike a balance um, if
it's possible at this time. With um allowing some intrastate
pipelines to compete in this space to firm fuel service.
Given the Railroad Commission's curtailment rule and
everything in the backdrop on the, on the gas side.
And, and I think as we're thinking about Phase II
and and sort of, you know, looking at what happened
during Elliot as well. I think, I think ERCOT's recommendation
is 48 hours of duration. Ultimately, I think once we
figure out what we're doing with the proposed definition
if we're staying the same model, you know, whatever
wherever we land. I think we need to conduct a survey
to see what megawatts are out there. So I think that
data will help us inform the procurement size, the offer
caps, the duration requirements. Although my personal
preference at this time would be 48 hours. Because given
Elliott's performance um, I'm sorry the firm fuel product
power plants that have been given a firm fuel service.
Um, only the first day was 48 hours. The rest of the
days were about 24 hours. The first day being December
22nd. So I think we've sort of laid a first initial foundation
through Phase I and appropriately balancing what
we are doing with respect. To not only ensuring more
reliability and resiliency, but also balancing consumer
costs as we continue to scale this product into the
market. And I think also with respect to the survey
that goes out. Once we decide what we're doing with
the definition. I think as part of that survey, we
should ask if there are any additional um, on site
fuel storage capability out there. Because now that
we've sent the signal through Phase I, there could
be a market response to add that type of technology
dual fuel capability um, out there. And so just getting
another picture so that maybe as we go out on Phase
II. We are not just looking at fuel supply arrangements
but maybe scaling up the Phase I. Because that's the
first contract, the first Phase I was only a one
year contract. Great point. So that, and, and I think also um, you
mentioned replenishing and restocking. I think as we
continue to look at Phase I and Phase II. It's gonna
be really important that we provide some more guardrails
on replenishing, restocking. Those are costs that are
outside the budget. And so Phase I firm fuel was
54 million, whatever restocking and replenishing went
on is outside of that 54 million. So we, we need to
at least have some kind of view as to how much those
costs are and be able to um you know, have more transparency
in that process for both Phase I and Phase II. Obviously
you know, replenishing, restocking is important, especially
if it's earlier in the Winter. And and you know, those
are good decisions that are being made but that's also
additional costs. And having some kind of idea of what
those costs are, things can be really important for
transparency to the Commission um as ERCOT directing,
their restocking.
Yeah, good points. I think we can, those are all good
things to take up once we have the Phase II defined.
Commissioner Cobos, I would just briefly say one thing
with respect to opening the qualifying pipeline definition.
And have, it includes all of the intrastate gas utility
pipelines. It's important to remember that ERCOT started
from the standpoint of building a framework that focuses
on accountability. Both from the generation resource
that offers ancillary service in. But also from the
perspective of that generation resource using now specified
contractual commitments, including the enhanced force
majeure language and the firm commitments that are
made there under. So so the accountability is also
not just from past performance, from a couple of folks
that I represent can tell you what the track record was. But we're
building accountability into the product going forward
with respect to the transparency of those contractual
commitments. And the clawback that Chad mentioned with
respect to the accountability of the generation resources.
It does put the folks in the market on notice that
they need to make sure that these contractual provisions
are solid. And that they can then offer in a dependable
product. Good point. Certainly, and I and I and I want to take time
to thank Chad and um, you know, our outside counsel.
And Peggy as well on this issue, it's it's extremely
complicated. And I think that um, taking the extra time
to dig into these issues as part of Phase II is critically
important. And, and, and you know, thank you for being
part of the conversation. Obviously we're learning
a lot about the intrastate and interstate pipeline system
as well. We don't regulate the gas side. And so I think
it's important to have your voice involved in in our
discussions. I haven't hung up my PUC boots yet, so
I'm happy to be here. I have one. I'm sorry Kathleen, please.
(item:33:54444, Commissioner Jackson's comments to Chad Seely & John Arnold) I just was gonna ask Chad, I mean, um part of what
you can um shared with me. Was in the decision making
process, of course, curtailment within the existing rules
within the intrastate pipeline. Was a big part of that
initial decision, but one of the things that you pointed
out to me. Was there's also curtailment on the interstate
pipeline. And depending on certain weather conditions
or situations, um, that could in some situations um
play into it if you were. If your pipelines were interstate
and I don't know, maybe you could share that scenario
that you were discussing with me about how that it
actually could kind of flip flop. And you'd be potentially
better off with an intrastate pipeline from a curtailment
team. Yeah. And I'll let Marcia chime in as well, but.
I mean, we're not eliminating curtailment risk with
this product. Um, so with the FERC interstate, they still
have a curtailment process. But it's on a pro rata
basis. So everybody is on par, when you have firm service.
So that that's the and we're allowing the FERC interstate
pipelines to participate in this, recognizing that
there's still a risk of curtailment. But if there's
a 10% reduction, it applies to all the customers that
have firm service. It's not, whereas under the Railroad
uh, Commission's curtailment rule. In that situation
where the utility makes the decision to curtail from
an intrastate perspective. They're going to first
reduce the supply from the generation resources before
they get to the LDCs of the human needs customers. So that's
kind of the fundamental difference between the interstate
and the intrastate, as far as the curtailment risk.
And and when we look at this definition, again, going
back to what Chairman Lake started with. Our goal here
was to make sure that firm really is firm and that
the consumers of Texas are getting a reliable service.
And that you're putting the interstate on par with
the intrastate framework as far as the firm service
delivery product.
And this is a point that commenters raised and it's
a valid point to consider. And this is very much why
it's a policy decision for the Commission. Because as
Chad said, because of the way FERC jurisdictional
pipelines curtail on a pro rata basis. The effect of
that is that let's say a pipeline's capacity was reduced
to 80%. Because of a compressor is down or something
along those lines and pretend it's 100% firm subscription
100% firm service. So what would happen on a FERC jurisdictional
pipeline is everybody gets suffers that 20% reduction.
On a pro-Rata basis within firm service based on their
their reservations. And so it's it's egalitarian and
equal. But if you apply the curtailment rule, let's
say that that 20, there's 20% on that falls in a priority
that's lower than generation resources. And we outlined
this in the letter, there's actually five categories
that have lower priority than generation resources.
So imagine those are industrials, they would get curtailed
generation resources wouldn't. Because it's not a situation
where the pipeline is having to choose between curtailing
generation resources and generate and LDCs. It's really
only so the data that the pipelines have provided is
very helpful. Because it suggests that we would have
to face a really high reduction in capacity before
the pipelines get to a situation where they're having
to choose between generation resources and LDCs. But
it is truly a policy decision because it's, it's pick
your poison. Do you want everybody to be treated equally
in a very transparent way and suffer the curtailments
equally? Or do you want the system where if we get
to a situation where you have to choose between LDCs
and generation resources, the generation resources
are going to get curtailed first. So this is why we've
come to you all for guidance. And that's why the follow
up questions are so important on the market share
system wide. But ultimately from a policy position, the
important thing for ERCOT is managing expectations.
To know that in a worst case scenario we can count
on so many megawatts that in that break the glass plan.
So that those operators can engage that and things
still run and we can manage a scarcity condition as
it becomes amplified. And so I think, I think that's
it's either, you know, under the current intrastate
framework, it's either everything's going down on you.
Or we have varying degrees of pro rata share that
we can reasonably expect to accommodate our firm contracts
and that's. key distinction. Yeah. I have one more question to John. Um
if we would change the definition of qualifying pipeline
to include intrastates. Do you think the universe
of intrastates would accept the framework that is
laid out here? Or do you think they have uh concerns
about um data nomination information, um, storage inventory
levels, things like that? That would uh be another
point of contention down the road. Um, so my point
the question first, that's one question. The second
is so if we include them in here and they still don't
like this framework, are we not going to get them in
because they don't like the framework? I think that's
a pertinent question and based on. I represent many other
pipelines besides Enterprise and Kinder Morgan. There
is some hesitation about that. What they have to do
is weigh that hesitation versus the incentive of participation
because there's a premium here. You know, the, the
companies that I represent are interested in the reliability
and supporting the operations of the state. But there's
also an opportunity to make money through a very valuable
product here. So they're gonna have to make some pragmatic
decisions on that basis. What I have seen is when faced
with the prospect of the, the incentive to further
develop these facilities. They have not hesitated to
say these compromises to have otherwise been a different
business practice for us in our contracting. We're
willing to make the transparency, the enhanced accountability
provisions and the contracts, not a problem. Um, and
I think there's gonna be a mix because in this marketplace
it is anything but a monolith. Um, even the business
model between Enterprise and Kinder Morgan can be very
very different. Kinder Morgan owns the molecules in
the pipe. Enterprise typically doesn't. It does in some
limited circumstances. Um, there's a wide array of
choices. I think that they're gonna have to make that
decision. There will be some that say it's worth it.
There will be some that say we're not used to making
this type of accommodations, this type of transparency
with respect to operations, and were less interested
in the product. So Commissioner Glotfelty it sounds
like what you're saying is, will the market respond
to this incentive or will they walk away? And I think
you ultimately, with any product we send a signal,
the market has to evolve and accommodate our requirements.
It's not the way the other way around that were ultimately
just gonna start peeling back our requirements to accommodate
more and put ourselves at risk. That's the most important
point. This is incentivized changes in behavior not
to pay exactly. Yeah, I can tell you with respect to
the amount of conversation and deliberation we've had
about the various issues here. Making those types of
changes to the commercial practices has been pretty
far down the list. Um, so the, the opportunity here
I think is the greater incentive than the disincentive
of having to change some of the commercial practices.
And if I may just add on that point. So one of
the things that you highlighted Chair Lake. Was the
desire to get something more than what you're already
paying for. If you're going to provide this incentive
that's born by customers in the market, you should
be getting something more. And in addition to the fact
that just historically there's generally a lower percentage
of firm transportation service agreements and and capacity
in this market. Um than in other markets that have more
constraints on pipelines, for example, up in PJM. So
this is already something that you're trying to incentivize
more generators to enter into these firm transportation
agreements, firm storage agreements. But then separately
with respect to the requirements on the force majeure
language and the providing data to customers. That
is something that does not exist right now in in intrastate
contracts in Texas, and it's not required by law.
So this is if, if the pipelines are willing to change
their behavior and adopt these mechanisms that we've
proposed to include here. This would be a substantial
change in the market. These these contracts would be
much more protective in terms of giving information
during, if a force majeure event occurs. Trying to
decrease the events of force majeure and just day to
day data. That the shippers would have access to would
increase substantially. So it's a pretty big um benefit
from the product. Well, well said. Um good discussion
I think that everybody's okay waiting another couple
of weeks as we wait on this other information. Marcia
good chat. John, thank you very much for all the work that's
gone into this. (item:29:52373) One final note, um just for the public
record, ERCOT filed this letter under and the draft
framework under project 52373. Just note that for
the general public. Thank you all, appreciate the work
and look forward to continuing to get this drive this
thing home. Appreciate the comments, Commissioners.
I don't have anything else on the remainder of the
agenda. Uh, so we're having no further business before
this Commission. This meeting of the Public Utility
Commission of Texas is hereby adjourned. Thanks Peter. Thank ya'll.
(silence)