(gavel banging)
-: Right, we will reconvene this work session
of the Public Utility Commission of Texas.
I think we covered all of the first bucket
or the primary topics in the first bucket
of SB3 related changes.
We've designated the second part of our work session today
to talk about another,
what I call above and beyond more fundamental changes
that I believe that SB2,
the spirit of SB2 directed us to do.
A lot of the things we talked about this morning
were mechanisms that have been used before,
or were already in place.
That doesn't diminish the value of making those changes.
But I'm also confident that we need to not,
we can't stop there.
We need to strongly and thoroughly consider
additional changes to firm up our market.
As we've said multiple times,
I think we're solving two problems.
We're solving an extreme weather event problem,
as we saw last February,
and we're also solving the blue sky problem.
When we have resource adequacy challenges
on a perfectly normal day with beautiful blue skies,
like we saw last April, and June, and July, and August,
and late October, that is a substantial challenge.
We have plenty of generation in Texas.
We've got over 110,000 megawatts installed
and our highest peak load demand, I think was 76,000.
The peak this summer was 75,000.
We've got a hundred and 110,000.
We've got plenty of generation,
but a good portion of that is not firmed up.
It can disappear leaving us with just the 75,000 megawatts
that we have of dispatchable.
SB3 calls for fundamental change
and the regular resource adequacy challenges
that we face periodically are I think,
giant red flags waving in our face that we need
in addition to all the changes we discussed this morning,
above and beyond fundamental change,
that firms up our grid.
We've got plenty of generation.
We need more firm dispatchable generation and that direction
was clear in SB3 in the Governor's letter
and other direction from the legislature.
I don't know exactly what a a firming mechanism looks like.
There are a variety of ways to accomplish that.
As you heard at our last work session,
so far I think the LSE, some version of an LSE obligation
is the best solution I've heard so far.
Of course, there's a spectrum of versions
of what an LSE could look like.
And if you'll, my colleagues will hear me,
I'll try to lay out the short version of,
or array of options of what that could look like.
And then of course, we want to hear
y'all's thoughts and questions.
And then as the later part of the conversation ,
have a discussion about if we don't utilize some form
of an LSE obligation, then what, what do we do?
I'm happy to consider other ideas,
and there's some interesting ideas submitted
in the comments this week
though we can discuss those at that appropriate time.
At the end of the day, our goal for December,
the blueprint is, in addition to everything we talked
about this morning, I think as I told Lori I'm very,
very trigger happy,
and the legislature wants us to be trigger happy.
And there are these giant red flags that we see periodically
are demanding, our grid is demanding
that we be trigger happy.
The goal is for December is to make decisions
about what mechanisms to choose,
what horse to back, if you will.
That does not mean that we will have
every single detail figured out.
That does not mean every single nut and bolt
will be in place, of course,
but we need to provide our market,
and our stakeholders and investors, and most importantly,
the people of Texas some indication of where we're going,
what we we're doing to solve this problem,
to make this grid reliable
and show them how we're gonna do it.
Of course, there'll be more analysis and implementation.
Of course there'll be more work to be done after that point.
But like I said, we need to, on all of these tools
that we're discussing need to get to the point,
we can pick a direction and go from there.
With that, I'll lay out some brief
additional thoughts on the LSE obligation to build
on the conversation from last work session.
I mentioned the spectrum of LSE obligations.
The NRG proposal is what I call, land somewhere
on what I would call the heavier handed approach.
And I'll offer these comments as bookends,
not suggestions from the heaviest most robust version
to the lightest touch version.
The heaviest hand, whether it's energy or any,
some variation of that proposal creates a new product,
a new capacity type credit.
In order to provide transparency and ensure there's no,
or there's mitigation of market powers
would require that capacity credit to be traded
and exchanged in a transparent way,
probably through a central clearing mechanism at ERCOT,
I think CRR on steroids.
That shows price, volume, counterparties
so that everybody especially the IMM,
but also the entire marketplace can see who's selling what
to who, when, how much and at what price.
That is as you can imagine,
you asked the implementation question last time,
that's a big time implementation exercise.
That's a major undertaking, it provides transparency,
it provides a market mechanism to require the retailers
to procure the ability and the capability
to provide power to the customers that they promised
they were gonna deliver that good too.
That's the heaviest hand approach,
the other bookend you've got the lightest touch.
That would be something
or a solution that does not create a new product,
no new capacity credit,
no new product is created, or traded, or exchanged.
So that's what we could call simply proof of purchase.
The Commission sets an accreditation standard
that holds each resource type accountable
for the level of reliability it can provide,
or is expected to provide
and we simply ask for proof of purchase
of an LSE's expected load for the set timeframes,
very much an audit exercise.
It could even be as simple as asking LSEs to ensure
that they are fully hedged
and only with dispatchable resources.
And if they show up in the real-time market,
unhedged, accounting for forecast error,
that will always be there.
But if they show up short in the real-time market,
there's some sort of penalty associated with that.
So that's a much lighter touch
that doesn't have any public transparency component to it.
So I'd offer those as the bookends of what an LSE obligation
could look like.
Like I said, we're not gonna figure that out by December,
but I know we must continue to evaluate options like this.
And so there's also of course,
market protection mechanisms that can be put in place.
For new entrance in the market,
you could easily have a two-year exemption
for any obligation, or until they reach a certain load size.
You could have price caps in the first few years
of implementation to ensure
that the financial liability is limited,
especially as the new dispatchable generation
that we've been directed to incentivize,
and that we need so badly is brought into the system.
We know we don't have enough dispatchable generation
and whatever form that takes.
We know we need more.
We know it's not built now.
And so somebody somewhere somehow has to put their money
on the table and pay somebody to build it.
The reason I have favor an LSE obligation
is 'cause that's just requiring the marketplace to buy it,
rather than the central administration of ERCOT.
The other reason the market participants are the ones mixing
and matching the resources,
according to the prescribed accreditation standard.
It's not us, it's not the central administration,
the other reason, but somebody has got to put money
out there and buy these resources
and pay for dispatchable resources.
It can be the market.
It can be the Centrally Administrated ISO.
That's the choice we've got to make.
I prefer to the market.
I think our, in general Texas prefers
market based solutions,
and also suggested the LSE obligation
because especially in the absence of creating a new product
and just on the proof of purchase side,
show us your receipt, you're just requiring LSEs
to purchase the power that they expect to use.
You're not spending money on resources
that are deliberately intended to be held out of the market,
except when there's scarcity and crisis.
So, those are a few thoughts.
I'll stop there.
Happy to try to answer any questions.
I know we've got multiple resources here
that can provide a lot more detail if needed.
So, open it up.
This is the pinata part.
-: So, I'll go first.
I mean, so Chairman Lake, thank you for laying out
where you're at right now and everything.
I've spent some time
looking at Senate Bill 3 and what it requires
and what it doesn't require.
And I believe that if we wanted to make
a market redesign change, we have the authority to do so,
but what SB3 asks from us
is not directly a firming requirement.
It asks from us a variety of measures
to reach a reliability requirement.
And what I mean by that
is they've got a specific section, a new section, 39 151.
I don't wanna sit here and read it all,
but it talks about establishing your requirement
to meet the reliability needs of the power region.
And that in my mind, you can interpret
that as a reliability standard
or at least some kind of requirement that we have
to meet with dispatchable generation.
We still don't have any feedback
on our reliability requirement, or target,
or anything at this point.
It requires us to periodically,
but at least annually determine the quantity
and characteristics of the ancillary service
or reliability service necessary
to ensure appropriate reliability during extreme heat,
extreme cold weather, and during times
of low dispatchable power generation priority region.
That sounds like blue sky day.
And so it requires those ancillary and reliability services
to be procured on a competitive basis to ensure
that reliability is maintained during extreme heat
and extreme cold weather conditions.
And during times of low non-dispatchable power production
in the power region.
We have to come up with qualifications
and performance requirements for those services
and sizes for the services.
And so from my perspective,
and I certainly respect the fact and the charge
that we've been mandated with to drive more steel
in the ground for dispatchable generation,
but for I'm sitting here today, I want, from my perspective,
I think we got to focus on what SB3 requires,
and we've got to keep a little bit more broader perspective
on what it requires.
I don't see a straight firming requirement being required.
So, from where I'm coming from,
I just want to keep at least a broader perspective
as to what maybe long-term solutions,
I mean, we'll continue to look at the LSE obligation,
but I do wanna open our perspective
to think about other proposals, because I think
there's a lot in SB3 that ties to ancillary services
and reliability services.
And we must be mindful of that language.
The other thing that I think is really important,
Senate Bill 7 created our ERCOT competitive market
over 20 years ago.
And it moved that risk of investment away from the consumers
that were being served
by regulated vertically integrated utilities
to the investment community.
I fear that with an LSE obligation construct
that we're looking at right now,
where we're taking that risk and putting it right back
on the consumers and departing
from the underlying principles of Senate Bill 7.
And I don't think that SB3 can be read
to move us in that direction.
While we're trying to ensure reliability
and insent dispatchable generation
using a competitive market
that was established by Senate Bill 7,
we must be vigilant,
and make sure that we're not weakening our market
and in shifting the risk
from the investment community back to the consumers.
And so I just with that backdrop,
but, I just want to lay that out.
And as we continue to look at long-term solutions,
whether the LSE obligation
and any other solution that's out there that,
that I really would like to bring some more options.
I don't wanna be looking at just one option--
Peter: I'd welcome any and other options.
I didn't see a lot.
There were a few in the comments this week.
And if you'll, go ahead.
-: Oh, sure.
So, to close all this, I just wanna say,
I continue to believe that we need to move
in a strategic targeted phase manner
to ensure greater reliability and resiliency.
While we take the time to thoughtfully,
deliberately and holistically evaluate
all potential long-term options
that can help maintain grid reliability in the future,
as our industry continues to evolve.
The Commission's evaluation
from my perspective of potential long-term actions
that would result in a mass redesign
of the ERCOT competitive market must be fully evaluated
and vetted before we can pull the trigger.
I know we're all ready to pull the trigger,
but I would prefer to pull the trigger in a very calculated,
strategic, targeted way, right?
We shoot a gun to hit the target, right?
Peter: Sure.
-: On moving forward with the implementation.
So too much is at stake for us
not to really scrub down every long-term proposal
in a very, very diligent way.
It's critically important matter.
And well, that will have long lasting impacts
on our market and our state.
That's where I'm coming from.
I just wanted to set the table as to kind of how I'm seeing
potential LSE obligation and how I would like
to look at other potential long-term solutions
as we move forward in our evaluation of those measures.
-: Sure, let's start scrubbing.
We've been asking for ideas.
We've got a very narrow scope of ideas.
And so let's start scrubbing.
You mentioned investor risk.
I wanna clarify that an LSE obligation
is not risk on consumers.
It's risk on companies that have promised to provide power
to the consumers when they took their money.
The risk isn't on the consumer, it's on the company,
the retail company.
Those retail companies also have investors
just like generators have investors.
Oftentimes it's the same investor
when it's an affiliated generator with retailers.
So in no way would an LSE obligation move the risk
to the individual consumer.
It would move it to a different set of customers.
And I know you care deeply about consumers as I do
and we all do.
That's why we're here at the end of the day.
We're not here to create new revenue streams
for these companies or to juice their operating income.
We're here for the consumers of Texas.
And my part of the concern with the current framework
is that when asking about what an LSE obligation
might look like to a retailer and their investors,
one response I got was a retail provider,
picking up a coaster, waving in my face,
saying we don't provide power, we sell things.
We don't do, it doesn't matter.
It could be this coaster.
We're just sales.
That's all we do, which is not in my mind,
providing reliable power to our customers,
our consumers, our businesses,
that's a sales shop that doesn't care what they're selling
as long as they get more people to sell it to.
And I have no problem starting to add some accountability
to people like that.
-: Okay, well, I would just like to say that the retailers
are not required to own generation.
That is not the way our competitive market is structured.
So -: They're prohibited.
-: They're prohibited, so.
Peter: Sure, but at the same, I mean,
you can't pretend like retail providers
don't have investors.
If you own shares of any of the affiliated generators
that we have in our market.
And we're glad to have them,
any of them NRG, Vista, Calpine, Exelon,
any of them.
You are an investor in both the underlying generators
and the underlying retailers.
So the risk is on the investors and those retailers.
That's the objective.
-: Mr. Chairman, listening to the spectrum of proposals
that you've laid out, one as we move forward,
and again, as Sam's watching this and Brattle,
as he is developing his recommendations and his study,
what's important to me,
and I believe it should remain consistent with the products
that we have already discussed.
Price responsive behavior on the part of the market.
In real time, it's been the beauty of the ERCOT market.
Again, it will allow us to better manage the resource mix
than most because our market is already accustomed to,
I've got to be responsive to price somehow.
Other markets don't necessarily have that.
So as Sam's listening and as Brattle is taking notes,
we've got to continue that
because it is my foundational belief
that whatever firming requirement vision on loads
or resources is pursued,
or if we pursue it in the coming months or years,
it's still must remain a bedrock principle
and an attribute of the ERCOT marketplace.
-: Absolutely. -: With that, I think
it would be useful subject
to Commissioner Gloflefty's comments or questions to you,
to be able to call someone up who can answer
some kind of a practical exercise questions
on what firming requirements look like.
And with having said that I'd like
to call up Lubbock Power and Light to talk through, okay,
SBP in that market, and again, they just transitioned.
What does that look like in SBP?
How is your proposal different?
And again, how does that harness the best aspects of both?
Could we?
-: Sure. -: Okay.
-: It looks like they already did.
-: Welcome. (all laughing)
Quickly before we go through this line of questioning.
I would say that in any version of an LSE obligation
on that spectrum, demand response should be treated exactly
as any other generating source with both the benefits
and the penalties.
So I think that would not only continue
to allow demand response, it would enhance it dramatically
because now that demand response has to be quantified
and you have to be accountable for it.
The command, it's a reinforced version of the command
and control you've correctly identified as so important
to demand response.
Not only does ERCOT need to be able to have the command
and control for distributed resources,
we're gonna count on that demand response.
As you correctly suggest,
it's not much good if you don't have
that command and control to rely on
this would not only require that,
but any version of those LSE requirements would require
the quantification of it and the accountability of it.
So this would be one of the most, I mean,
this would supercharged demand response
because it's not just kinda, as it happens go with,
it's now accountable, it's quantified and it's valued.
So I would say
it's not only continuing to allow demand response
it's reinforcing and encouraging it.
-: In your view, if this panacea of demand response
behaving as generation is developed, again accountable
on the same standards as frankly, a resource, again,
aggregated DG, how is an unaffiliated retailer,
and again, this would be accounted for
in the CDR and for our purposes,
reliability metrics moving forward.
How would an unaffiliated rep who is again,
not a generator first own those assets
and still not run afoul of PURA.
-: Own demand response?
-: Well, DG to an aggregated degree where there, I mean,
thousand megawatt plays, Octopus Energy.
If they harness enough DG where they're commanding
and committing a thousand megawatts.
-: Well, if we're gonna say
we can't accept distributed generation from retailers,
because that runs afoul PURA,
we've gotta open up a whole nother--
-: I know, I'm just trying to think
through legal can of norms type issues and stuff like that.
-: I mean, if that's the, regardless of an LSE obligation,
if distributed generation
can be treated as a retailer regardless of affiliation,
if the subsidiary of the corporate structure
owns and treats, if we're gonna treat
that distributed generation as a retailer owning generation,
and you read that contrary to PURA,
then we need to put the brakes on any distributed generation
coming on to ERCOT at all.
-: I don't wanna do that, but I just raised it--
-: Okay, well, if we're gonna do it,
let's do it everywhere.
Not just on a specific proposal.
It's a fair question we need to consider,
but let's consider universally.
-: Okay. -: Lubbock.
-: Hi, do you wanna explain your experience?
-: I'm David McCullough, I'm the Director
of Electric Utilities with Lubbock Power and Light.
Peter: Welcome.
-: I can tell you a little bit about our experience in 2014.
When I started with Lubbock Power and Light,
we undertook to secure power supply for a contract
that was expiring in 2019,
long in advance of when it was actually expiring.
And so we went through an RFP process,
looked at a number of options,
including local generation build options.
And the most attractive option we got was a PPA option
that was ERCOT based when we did the RFP,
we opened it up to ERCOT and SBP options
because the CREZ lines were in close proximity to Lubbock.
We thought that it was an option
that we should at least consider and look at.
So the PPA option was far and away the best option
that we looked at, it was ERCOT based.
So the first thing we did was ask that company,
if they could structure that as an SBP product.
And they tried really hard to do that.
We all took a trip to Little Rock, Arkansas
and met with the executives of Southwest Power Pool
in Little Rock and went back and forth.
And because of their
load responsible entity resource adequacy obligation,
it's a physical generation requirement.
You've got to prove that you have access
to physical generation.
And not only that, but it's deliverable to your load.
The deliverability problem was where we got
wrapped around the axle with,
with their program is because Lubbock was kind of at the end
of the transmission system and SBP,
we were in a constrained part of the grid.
There were capacity options available
in Nebraska and other places that were
economically priced, but we could not get those delivered
into Lubbock.
So, ultimately we decided
not to exercise the build options,
but to pursue integration with ERCOT,
that happened in 2015.
-: Okay.
So in the accreditation portion for SBP,
how functionally did that work in your experience?
How do you get different resources accounted for?
-: Well, they do have an accreditation process.
They look at generally the fossil fuel units,
gas and coal and nuclear and all those,
they generally get a hundred percent accreditation,
the wind resources get a much lower accreditation
and then solar,
kind of at lower percentage as well.
But generally, when you sign up for a capacity,
you've gotta know what its accreditation value is.
SBP determines that, and you've gotta cover
a hundred percent of your load
with these deliverable resources.
And then the 12% reserve margin can be covered
with non-deliverable assets.
That's something that changed
after we went through this process.
-: Okay, and in the real-time market,
how does SBP sort of look compared to ERCOT
now that you're in?
What was your experience there?
-: They have LMPs, you can offer into the day ahead market
and settle in the real-time market,
but there's not a robust, actively traded forward market
in SBP that we could make access to.
So it's not a actively traded liquid, wholesale market
like what we have in ERCOT.
And that was one of the features that was attractive to us
as well coming to ERCOT.
-: Is that because they're vertically integrated utilities,
or because of some requirement on LSEs
to prove they've purchased the power,
they promise to their customers?
-: It's a good question,
I can't tell you that I know the answer precisely.
I think it has probably has something to do with the fact
that vertically integrated utilities
and it's primarily a physical market,
unlike in ERCOT where you have a lot of financial traders,
you've got active financial institutions
that are active in this market.
And that creates a lot of liquidity in the ERCOT market
and financial strength.
-: Fair not to blame that lack of liquidity
solely on the liability obligate.
-: No, but I would say about the reliability obligation,
SBP had 23% reserves
in their latest resource adequacy report.
And it declines in 2026 to 12%.
They're seeing generation retirements just like ERCOT is.
And I think nationwide we'll continue to see
because of the pressures that y'all talked about
this morning, the environmental pressures,
the financial pressures, we'll continue to see
conventional resources retired.
-: So Commissioner McAdams touched
on operational reliability issues.
Was LP&L and SBP during winter storm, Larry ?
-: We were, we did experience rotating outages.
It wasn't, we experienced rotating outages
on the 15th and the 16th.
A longer period of time on the morning of the 16th.
And what drove those interruptions was SBP
was importing about six gigawatts of power
from adjacent RTOs.
That's an advantage that ERCOT doesn't present have,
but so it was the imports that really saved them
from more lengthy rotating outage scenario.
Those tide lines were interrupted
on the Tuesday morning event
and that's what caused a lot of the rotating outages
that we experienced.
Yeah, we participated in that.
I've been through three rotating outage events in my career,
'89, 2011, and last year as well, and this year.
-: Thank you.
-: Load growth forecast, how does, because again,
under the concepts, both in SBP and E3 proposed
and Mr. Chairman, I'm not sure kind of the modifications,
but the way we account for the reliability
or the way we account for the need to firm
is based on load growth forecast, correct?
-: Right.
So I've seen in comments, but again,
you're out there in, Lubbock's interesting animal.
I grew up south of you.
It's got a good urban core dynamic,
and it's got rural areas going out.
It's got an oil field play right next door.
So you've had a little bit of everything on load growth,
but what are the considerations we should take into account
on the forecasting of load growth,
conservative versus you wanna get those numbers right,
otherwise you're overpaying or underpaying,
or you're not gonna be there.
Talk through that, how does it work?
-: It's a challenge for all of us and load forecasting,
because particularly for a city like Lubbock
that's undergoing a fair amount of renovation.
Some of the older facilities that are getting torn down
are replaced with much more energy efficient facilities.
So you don't get a one for one growth with new facilities
that come in.
Even though they're large compared
to what might've been there before.
So the energy efficiency is really had a big
effect on overall demand growth.
It slowed down pretty significantly.
We have a forecaster that works for us
that develops our, our energy forecast and demand forecasts.
So that's, it's an art and a science
that is beyond my level of expertise to do.
-: Is it subject to manipulation?
-: Sure can be. -: Great.
So you mentioned transmission constraints,
keeping LP&L from being able to meet obligation requirements
in SBP, you're kind of out there on the end of the line,
on the ERCOT grid too.
I mean, you're in between.
-: We are, but we have,
the advantage in the ERCOT market is that again,
we buy firm LD block energy products for them,
for the most part to hedge our load.
And the wholesale market is very functional
from that standpoint, you can buy,
we're buying two years ahead of time right now,
firm LD products.
They're backed by credit worthy entities that,
that sell us those packages.
And so we have a lot of trust that they'll deliver
when the time comes.
Peter: Who determines they're credit worthy?
-: We work with a energy market administrator,
or third party.
I probably shouldn't mention their name.
Peter: That's a hired vendor.
-: It's hired vendor.
-: So, that's on y'all, that's the risk on you.
-: They do a credit check on all the vendors
that are doing business with.
-: Okay, so that, that, that risk is on you?
-: It is. -: In both ERCOT and SBP?
-: Yes. -: All right.
You mentioned the deliverability requirement
was the key concern.
-: It was.
-: You said there are two components of the SBP requirement,
proving that you've procured according
to the accreditation standard of the power
of your expected load plus the reserve.
-: Right.
-: And then the second component was the requirement
to prove that you can get it to your load.
-: Correct.
-: And from your comments, it sounded like
the second part was a problem, not so much the first part.
-: The second part was the problem of the, primarily,
just because of the length of time it took to run,
the SBP to run this studies.
You had to participate in the aggregate
transmission service study,
took six to 12 months to go from start to finish.
-: Right, but the proving you purchased the power
you were gonna purchase anyway,
doesn't sound like it was too onerous.
-: Well, there was a, it's a bilateral market,
so you could, you'd have to get out and talk to people,
but there's, there was capacity available.
It was just a matter of getting
proven that it was deliverable to your load.
That was the hard part for us.
-: So the first part,
just proving that you've purchased the power
that you're going to purchase anyway,
it doesn't sound like it's a dematic departure
from business, in business as usual.
-: No, that was not the problem.
-: Okay, and I don't think any other proposals
on the spectrum of our LSEs obligations
have a deliverability requirement.
In fact, the centrally cleared
that even the heaviest hand approach
by definition being a centrally cleared capacity credit,
can't have a deliverability component to it
because it's gotta be fungible between all parties.
On the lightest end of the spectrum the proof of purchase
shows your receipts sounds similar to the first part
that you did the first element of SBP requirements,
which you described as not really changing business.
And it is normal, no departure
from your normal business practices substantially.
It was the second part, proving you could
get it to your load that was the real challenge.
That is not being considered in any of our LSE obligations.
-: Yeah, the IMM,
read through some of the other comments,
the IMM mentioned that that might be something
that would have to be looked at at some point,
but I haven't heard y'all say that
that would be a requirement.
And that was in my testimony that y'all please don't make
that part of your requirement.
'Cause it's very problematic.
-: It's not under consideration in any
of the versions we've seen.
You mentioned you got about a hundred percent plus the 12%.
I know it was in an additional reserve margin
was in some of the proposals.
And as you saw in my memo last week,
that's not under consideration
and the straw man, I offered.
So we would, again, never ask LSEs to buy more power
than they expect to use for their customers
during some metric related to peak demand.
And finally, you mentioned the challenges
with load growth or forecasting load growth.
I think it's fair to say that the U.S. stock market
is one of the most quantified evaluated ecosystems
on the planet, and nobody can get that one right tomorrow.
So under no circumstances does any,
I think any of us expect load growth forecast
to be accurate even a week out.
And that is exactly why my straw man proposal last week
had a escalating requirement
starting at 50%, three years out.
Is there any scenario where you see Lubbock losing 50%
of its load in the next three years?
-: Well, as you know, as most of you might know,
we're planning on joining the retail market.
So in theory, if we join the retail market in two years,
we will lose a hundred percent of our load.
Somebody else will be responsible for the demand
at that point in time.
-: Okay, sure. (all laughing)
Welcome to ERCOT.
As previously,
in SBP, when you're responsible for that load,
was there any scenario where you expected to lose 50%
of your load within the timeframe of 36 months.
-: No, absolutely, our load is fairly stable.
Weather is the biggest factor year to year
'cause you can't predict weather three years in advance.
-: But if you have-- -: Of course not.
Long hot summer, your load is gonna be 10%, 20%
higher than it would be in a mild summer.
-: Okay, so you said
you were buying the bilateral arrangements
for your power two years out, right?
-: Yes. -: Or even more with the 2019?
-: We're buying through a summer,
well, let's see, we're buying through May of 23 right now.
-: Okay, so you were already buying power multiple years out?
-: Right. -: Okay.
-: It's firm LD products though.
I don't know if they qualify under the LSE obligation,
approach the chart considering.
-: As always devil's in the details.
-: I mean, they're firm from my standpoint
because they're financially firm for sure
from our perspective.
-: So Mr. McCauley, LP&L is,
you're in the process of unbundling.
I mean, your experience in SBP
is a vertically integrated utility, right?
-: Right, it was.
-: So it's a little bit of a different experience
than say a rep would have, traditional rep would have
with an LSE obligation?
-: Yes, and the reps,
reps are adding load and losing load all the time.
So I think it'd be a little harder for a rep
to predict what they're load might be
two years, three years in advance.
-: So there's a lot of wind in SBP?
-: Yes.
-: Are they experiencing some of the issues we experienced
here in ERCOT where it's a low load,
higher than expected load,
lower than expected wind generation?
-: They are.
I think every RTO is experiencing the same phenomenon
that y'all are experiencing.
SBP has got a major wind resources coming into the grid.
I don't know if they've got as much solar
as ERCOT has coming in,
but they're all dealing with the same kind of problems.
-: And how do they manage those operational reliability
scenarios or experiences they have with a lot of wind
on the system that they drop off?
And I know they're multi-state market.
So, they have access to a lot of resources,
but what are some of the tools,
do they have an ancillary service market as well?
-: They do, they deploy a lot of the same tools
that ERCOT is using?
They may be a little more aggressive about curtailing.
I know we've got some wind resources
that they get curtail frequently, so.
-: So even with an SBP, some version of an LSE obligation,
they continue to rely heavily
on their ancillary service market on those types of days?
-: Yes. -: Okay, thank you.
-: And the point I made a minute ago, there 23% reserves
and which is above where ERCOT is today
and they still had rotating outages.
So I think that they call it
the LRE resource adequacy requirement does not guarantee
that you're gonna have a hundred percent liability.
The winter storm area was in the extreme black swan event
that affected and affected all of us nationwide.
-: But the wind degeneration days are not black swan events.
They're issues that all markets are experiencing,
including ERCOT.
-: SBP has large and growing percentage
of wind in their mix, in their portfolio.
-: Do they have, does SBP experience rolling blackouts
on blue sky days that you've heard us talk about?
-: No, sir, the event in February was the first one
that'd had 80 years of being around.
-: Yeah, the extreme weather event is one problem.
The blue sky problem is a different problem.
Okay, thank you.
-: But that's primarily the structure
of the vertically integrated utilities
that have rate-based plants that have been in there
for 50 years.
So we have a very different market from that.
-: Sorry, it's the blue sky problem is the result of what?
-: Yeah, the blue, I mean, obviously the blue sky problem,
in my view, the blue sky problem there,
and here it's very different
because they have vertically integrated utilities
with power plants that are in their rate base.
We don't have those.
-: They shouldn't be-- -: That would be called
a capacity market in this space.
-: Right, so they shouldn't be having those problems.
-: They shouldn't be having those problems.
And that gets us to a,
if there's a capacity market issue here,
that's persona non grata,
but that's what they have.
-: Sure, they'll have to talk to the, I mean, right.
If anybody wants to go straight to the capacity market,
they'll have to talk to the legislature.
-: That's right.
-: Well, I mean, right.
-: I'm pretty sure the legislature
would want to way in on that.
-: I mean, anywhere near capacity market, right.
-: They're gonna weigh in, I can guarantee that.
-: They did weigh in.
-: They're gonna weigh in again, I guarantee you that too.
Sir, on your filing, how did you come up with the costs
that you put down there?
'Cause again, we're all trying to come up
with a menu of costs that we're looking at it.
-: Well, it was based on
what we have paid historically for capacity and SBP
and just multiplied it out.
It was anywhere from $4 to $8 per KW month
is what we paid for capacity and SBP,
multiply that out times 12 months,
times how many megawatts you need
and then divide it by your annual energy sales.
And that's how I came up with that cost.
-: Okay.
-: I actually do have a question.
So would you describe the LSE obligation and SBP,
which bookend that the chairman talked about,
is it much more proof of purchase?
-: I would say it is a,
if you look at just the capacity part of it,
it's probably the light touch approach.
It's this deliverability aspect
that made it so unworkable for us.
-: Okay, so the proof of purchase side of it
is not very problematic.
-: No, that part was not, it was not that difficult,
There's annual filings that you have to do,
show you the load forecast and show you your contracts
and generation that you own and just match all that up.
Peter: Accounting and Auditing.
-: That part wasn't tough.
-: Thank you.
Any other questions? -: No sir.
-: All right, thank you sir.
-: Thank you.
-: Could we have Bill Barnes come up
and offer some thoughts on the Lubbock perspective?
-: Thank you.
I think what you heard from Lubbock
pointing out some pretty big structural differences
between the SBP market and in the ERCOT market.
So in terms of comparing--
Will: Bill, current or as proposed?
-: I would say current, current markets and as proposed.
Will: Okay.
-: The evolution of all we need to get to.
-: Okay. -: Right.
And we keep coming back
to this capacity versus energy discussion,
similar to what we see in SBP in other markets, ERCOT.
So I think we need a brief therapy session
on what energy versus capacity means.
We've never had an energy only market.
We've always had an energy, mostly market.
And that means like any other power market,
you have two sources of revenue that support operations
and investment, and that is energy revenues
and capacity revenues.
Lori: Ancillary service revenues.
-: Our capacity revenues have been traditionally
a much smaller piece of the overall picture,
ancillary services.
As we have evolved through time and learned that
a system that depends on frequent scarcity
is not in the public interest,
we have recognized that we need
to increase the capacity revenue side of the equation.
We buy more ancillary services.
We've implemented the ORDC in a way
that does not reflect the fundamentals of a scarcity price.
It reflects the fundamentals of needing
to get a higher price at a farther portion of time.
And so when you hear the phrase capacity market,
to me, that is interpreted widely by all of us
to mean something that's,
it costs a lot of money that buys stuff we don't want.
And in my perspective, there isn't a proposal in here
that is doing that.
That is not what the LSE obligation proposal
is intended to do,
but at what it is intended to do is to recognize
that as we meet our reliability objectives,
we need a competitive product that values reliability
in a better way than what we have today.
That's what it's intended to do.
And it's intended to use mechanisms that have been
and are reflective of what we see in our market today.
When we went through the process of developing this,
we stopped at every part, every bucket of proposals
that we've seen in this, ORDC reforms,
expansion of ancillary service products
which when we spent time thinking
about how those would work,
we kept getting back to the point of, well,
if you're buying a substantially
higher amount of ancillary services,
which is a central procurement of capacity.
So let's, again, let's talk freely about
what were these concepts.
Lori: Which we have in place right now,
right, through our ancillary service market?
-: We have that in place now.
And we're one bucket of solutions is to increase that
and create new ones.
And so to me--
Peter: We're just expanding existing ones?
-: We're expanding existing ones.
Peter: Just moving on,
spending 20 thousand megawatts.
-: To me, the market design is a, from a high level,
very simply a risk management exercise.
On one of the spectrum,
you have the lowest cost, highest risk.
on the other end of the spectrum,
you have a higher cost, lower risk.
And so we're trying to find something in the middle
that works the best for our market.
With concern about expanding ancillary services
and relying just on it, which is a path we can go down.
Lori: That's envisioned in SB3
with respect to ancillary service and reliability services.
-: I think SB3 addresses that as well,
but we obviously believe that SB3
also provides a clear framework
for a more comprehensive approach,
but our worry is the ancillary service route eventually ends
in a spot where you've compensated capacity
to be dispatchable.
You've compensated a portion of capacity to be able to meet
very specific operational needs.
But then you have the, the rest of this capacity
that's not getting compensated that will eventually
have to exit.
And then you're talking about
adding another ancillary service to keep them around.
And you basically backed yourself into a central procurement
of capacity for everything, okay.
So when we thought about the LSE obligation
and we looked at SBP, we looked at Australia,
and this is where, when I look at all the proposals filed,
I think, and probably not apparent to you all,
but we've gone through this process a few times
in the last 20 years.
And I feel like there's more agreement and support
for high level principles than we've had before.
And that is one, make sure we achieve
our reliability objectives,
but also preserve our competitive market.
Whatever we end up with, right,
has to check those two boxes.
Now, the difference, I think, between the proposals is,
maybe a matter of the sense of urgency,
but I can tell you from our perspective,
what informed our path and our decision-making was,
do we think we will get another chance.
If this doesn't work, if we go down the route
of a certain direction and it doesn't work,
do we think we'll have another chance at this?
And I spent more time at the legislature this last session.
And I can tell you, I agree, but I don't think we do.
And so to me, the solution has to be forceful
in how it addresses reliability,
but we have to address the issues and the concerns
that we've heard and you've seen
filed for the LSE obligation.
Market power, impact on retail.
We got to make sure that it meets those things,
which is what kind of coming back to the original question.
That's what makes ERCOT so different from SBP, right?
You've got a kind of handful of utilities up there.
It's just a very different structure in terms of the ability
for participants to provide liquidity, to provide products.
You hear folks talk about how our ERCOT is,
the product is a liquid, energy product is a liquid.
That to me is a function of price volatility,
not necessarily structure.
So why is there ERCOT product so volatile
or so illiquid at times is because the bid-ask
is 9,000 or a hundred dollars, right?
And that I don't care what market you have.
That's going to be a very liquid market.
So lowering the vol will help address
some of those issues.
But structurally there is ample amount
of financial intermediaries.
There are brokers, there are mechanisms
that help provide liquidity for the energy products
that we have, right.
So that to me, I think is one of the bigger differences
with, the LSE obligation in ERCOT versus SBP,
in terms of the mechanisms on how you implement it.
Accreditation, we have a version of accreditation now
with the SAR and the CDR that would absolutely
have to be revamped and thought through and bolstered.
And when I look at section 25,173 of the substandard rules,
that creates a process to incentivize investment
in a very specific amount of capacity.
That's assigned full load serving entities, retail entities,
in that, in aspects that,
that's the renewable energy credit,
the structure is similar.
The concerns that you hear about it is
because that type of product in this market,
we think we are of short supply.
We're not short supply of renewable energy credits, right?
But structurally, it's similar.
Our ancillary service market,
we administratively set an amount of ancillary services
that we want to procure for a specific reliability reason
and we assign it to LSEs.
This is not a foreign concept in our market,
but we do have issues that we need to work through
to make sure that it does not do harm.
It maintains the parts of our market
that have worked so well.
-: But, again, reps are specifically authorized and statued
by specific legislation. -: Agree.
-: We are talking about making something
out of whole cloth here.
-: Yep.
-: Tied to two sections of a somewhat ambiguous section
of law that has profound consequences for the retail segment
of the market, in the energy only market design.
Would you agree with that?
-: I don't wanna minimize the effort involved
with implementing an LSE obligation.
It's not a small change,
which is why we have encouraged a longer term process
to develop that because we wanna make sure
we get it right and we explore it.
I do think Senate Bill 3
provides the foundation to pursue this path,
but it is one that like the Chairman has said,
this isn't a today thing tomorrow, next month,
there are issues that we would need to work through.
But when we look across the spectrum of proposals
and we look at them through the perspective of,
do we have another chance,
I don't see a proposal that is comparable
in terms of its ability to reduce the risk
of reliability event.
And so that's where we get concerned,
is what else is out there that helps us
solve the reliability problem and achieves the objectives
that we want in terms of preserving our market.
-: So two things, you've said multiple times
we don't have another chance.
This is not a today, tomorrow thing.
It's unknown how long the LSE obligations
is gonna take to implement.
I mean, we can be moving towards your proposed path
and still not have a chance.
So, I mean, I don't view this as, like,
we don't have another chance,
we need to go down the LSE obligation route
because we don't have another chance.
I see it as we need to attack
our operational reliability issues now,
because we certainly won't even get a chance
to get to your LSE obligation in the mean, if we don't--
-: I agree with that. -: Okay.
-: Yeah, this isn't a just pick this and do that.
Forget everything else.
No, I think this is all the above.
What's the downside of exploring a longer-term solution
while you do the things you just mentioned.
-: And you said another thing that I just,
I have to say, you said, well,
this is the way we maintain reliability
and make sure the lights don't go out.
Something like that at the tail end of your statement.
But I have to say,
SBP might as well have LSE obligation related markets
and had rotating outages during the storm,
California has a more similar market
and their Governor had to take extraordinary action
to address energy supply shortfalls.
So we gotta be cognizant of the fact that
absolutely you wanna maintain reliability,
absolutely everything we can to figure out a solution
to get there.
But we really have to be cognizant of the fact
that these market constructs exist in one form or fashion
and ours will be different 'cause we'll be cutting it
out of cloth, but I'm not sure they ensure
complete reliability and nothing will, nothing will,
but we can't be saying that this will definitely do that
or help us get there when we have real-world examples
of where it has not.
-: Agreed and we shouldn't say that,
we can't make any guarantees.
I certainly will not.
-: And I wanna work the problem.
So in that interest, okay.
So Singapore has one of these, don't they?
Sort of? -: It was proposed.
-: Okay.
Well, so I'd heard that we're talking about
under your concept, Mr. Chairman, a hundred percent,
we're trying to firm to a hundred percent
of what we're gonna need on a given day, right?
That's what we're gonna try to trade.
-: The first straw man's a starting point.
-: I understand.
-: But no under no circumstances,
would I ask LSEs to buy more power than they expect to use.
-: That's where my question's goin, toward the straw man.
In order to allow flexibility in the market
for price responsive behavior.
Again, in real time, I'm worried about suppressing
the animal spirits of real-time, Bill
on the steel which has been extremely effective
in Texas and made power affordable.
Do you need to procure all a hundred percent or over?
Should there just be a minimum procurement there
to allow the market to market?
-: So, I think the main question that you raise
on this particular topic is how should the responsibility
to provide reliability, be distributed
amongst market participants, sir, right?
Which raises the question of free ridership for liability
is that something that we think should be addressed
or should be left to the market to decide?
Peter: The wagon coaster.
-: Exactly, right?
-: Say that again. -: The wagon coaster
from retailer, we don't, we just sell things.
I'll sell you a coaster, I'll sell you a pen.
If it's power or coasters, I don't care.
I think that's not the right approach for retailers
in Texas who were responsible for powering the lives
of their customers.
-: So that's part of the decision with the LSE obligation,
but to your question Will,
which is part of what's allowed this market to work so well
is that freedom and the ability
to be as flexible as possible
in meeting real-time obligations, right?
And if a retailer decides that they wanna be
completely unhedged and take that risk, right,
that's a market risk, they're free to wear today
and they will bear the financial consequences
if they're wrong.
We all make that decision every day
in operating our businesses in the competitive market.
I think that is a separate from the question
that the Chairman raises,
which is who's gonna help us solve
the reliability problems?
And in a central procurement,
if we increase the ancillary services,
ERCOTs procuring that amounts and then distributing
it to everyone, right?
Or LSEs based on low ratio share.
The question with the requirement to hedge energy,
which this is part one that I've been thinking about
quite a bit, which again, this is a complicated thing
that was gonna take time to work through.
If LSEs are required to hedge their energy,
What I've been thinking about is,
how will the bilateral market evolve
and respond to that requirement?
And I think it actually manifests itself
in more of a product that looks like capacity.
'Cause as an LSE, I don't know exactly what my load's
gonna be next week, or next month, or next year.
So in order to meet a hundred percent requirement
to match my load,
I'm gonna want as much flexible resources as I can,
that can ramp up or ramp down to meet my load.
Now, in any construct that is pursuing
this type of attribute,
you want that same ability in real time.
You don't wanna be constrained
to have to go buy something very specific.
You may wanna use demand response.
You may wanna have batteries.
You may wanna have whatever.
So that's part of their proposal that we thought
was attractive, is not constraining to a specific resource.
And providing a range of options of certain resources
that can provide certain percentages of reliability
and allow the market to solve the problem
in the way they prefer.
Some may wanna lean towards solar and batteries
because it's has green attributes.
Some may wanna use demand response,
others like us that will have a much bigger obligation,
we'll have to probably invest in conventional generation
'cause the smaller bites of the apple won't be enough,
but the attribute or the function that you described,
I think is important to try to preserve,
which is the ability and flexibility to solve that problem.
It should be up to the market to do that.
And again, this is really premised
on the notion of having a reliability standard,
which you haven't talked a whole lot about
or having some goal that all of us,
market participants know exactly
what it is that we want to accomplish
and we can go out and try to do that
without making the guarantees, but lowering the risk.
-: Oh, sorry, Commissioner, I wanna hear your thoughts.
Yeah, yeah, yeah, go ahead.
-: I'm gonna go off on a different direction
if you wanna carry, keep on this thought.
-: Okay, well, so the problem I'm trying to solve
is look, everybody sells
or buys their dispatchable energy credits
and they've got it locked up 95% month out.
-: Not everybody. -: Who?
Who is not?
-: Well, everybody who comes and talks says they do
and promises they do.
-: No, no, no, I'm talking about
in the functionality of the proposal.
-: Oh, yeah. -: What we're talking about?
Yeah, yeah. -: Sure.
-: So you go out there and you buy your decks
and you're going into real time.
And so everybody's got their paper
that says they're good for that day.
And then STP trips.
-: Yep.
-: A lot of megawatts.
And then how do we respond to that?
Well, we hope we have excess
dispatchable generation to kind of try,
and the wind's not blowing
and we hope we have excess dispatchable generation
that already hasn't locked in and sold their paper
at X value in the deck market, right?
To meet that challenge
'cause it's kind of way the other
forward capacity markets work.
They don't ramp up as quickly.
They're not as nimble. -: Yup.
So I think a mechanism
that provides additional dispatchable capacity
which is another thing, that's the product we need, right?
-: So an ancillary service?
-: A longterm dispatchable capacity,
the product that ERCOT needs
is dispatchable capacity so that we can meet the duck curve.
We can meet situations when there's a lot of forced outages
and not every everything's trying to take an outage at once
when it increases or decreases.
So that product, right, will increase,
create incentives for more investment
that will increase reserve margins
which helps you in operations.
So when plants trip, when STP trips offline,
and we have a more robust reserve margin
that's composed of dispatchable capacity,
not a reserve margin that has
a good deal of renewables in it,
then you're able to withstand those events.
So, long-term incentives for that type of capacity
reserve margins translate into an easier way
to manage through operational issues.
-: Like a product like this
you're saying a long-term dispatch,
an LSE obligation of some form or fashion would be that,
you're not talking about a different product.
-: I'm not talking about different product.
-: I guess I'm confused because it almost sounded like,
and I'm just trying to envision it
and we've gone around and round on this issue,
I think to some degree
and that is if you had LSE obligation
and we have these operational issues
as in minus one minus one scenario
where STP trips off and the wind's not there,
and maybe solar has some cloud coverage,
so maybe that's another minus one.
How do you nimbly address those issues?
And it sounds like we would rely
on our ancillary service market, whatever product it is,
whether it's an existing ancillary service product
or a new one like TCRS.
And so I guess what you're asking is,
what happens in a scenario like that?
It sounds like the same thing
would happen that happens today.
We would rely on our ancillary service market,
but I guess, at the tail end,
I was trying to connect the dots, Bill
'cause he said, well, we would have
more dispatchable generation
and that would be driven by what's signal?
-: I see now, there's a difference.
In my opinion there are two different problems.
There's the operational need, right?
And so we see a huge net load ramp, we see solar drop-off.
We need enough operational capacity to be online,
to better manage that event.
That's problem one.
Problem two is enough,
additional installed dispatchable capacity
to be able to provide the operating reserve, right?
So, two different problems,
ECRS and the suite of ancillary services
addresses the operational issues
and so it is the RDC reforms.
The hole is what solving the investment incentives?
Now, our market has operated
almost entirely up to this point that the operational issues
are expected to connect the dots downstream to investment
or incentives, right?
So as we have operational issues and we stand,
we dispatch more ancillary services which will increase,
as we buy more ancillary services
that increases ancillary service prices.
As we have operational issues
in real-time energy prices go higher, right?
The current framework of a market says,
well, eventually that will manifest itself
into enough expected revenues where investment will come in.
And I think what we've seen
is that those dots are challenged
in terms of fully connecting that investors want,
more certainty
and our market isn't great at providing certainty,
which is why I think we're challenged in those aspects.
So, the mechanism that the LSE obligation provides is,
let's provide longer-term certainty,
or, I mean, I've seen other proposals filed as well,
seasonal procurement of reserves
which is a short-term capacity market.
Those provide more certainty
to help solve the same problem.
-: Centralized procurement,
short like a smaller centralized procurement.
Okay, so as we're trying to incent more
dispatchable generation it sounds like
the two mechanisms are the energy
and the ancillary service market revenue streams
that we currently have in our market
and we know at least we're sending some signals right now
with ECRS,
but what you're saying is
with this additional market design change on top,
it'll drive additional generation investment.
And what I'm trying to figure out,
because we are solving a today problem,
we're trying to solve a near term problem
with operational reliability issues as we await
long-term solution, let's just say,
it's the LSE obligation.
So when would that signal,
'cause I know, and you may have a different,
and I can't remember if you did three year look ahead
or one year look ahead, but when would we get the signal?
Like when would we get investment?
Would it be, is the investment community
gonna be waiting for us to get our rules,
our framework in place first as they shape up.
And then we start sending signals that way.
So that could be, we could start,
it sounds like to me, and please clarify,
'cause we're all trying
to incent more dispatchable generation
that it could be, I don't know.
It could be a couple of years before we send a clear signal
and then you still need two to three more years
to build a plant depending on what size or what it is.
So, is it five years when we get steel in the ground?
-: So, I think the answer to that question has a lot to do,
unfortunately with what you guys decide what to do.
If-- -: Which will go on
for a little while, right? -: Yeah--
-: If we went with it. -: And I'm not trying to put
pressure on you, certainly you don't wanna speed up this,
the deliberation on a longer-term solution
because I do think the details are important
and there's complexities too.
But I'll use a couple examples.
One, if this Commission were very clear
that they were gonna adopt a reliability standard
and that standard was known to be some amount
and the message was we're gonna develop
some market-based approach to achieve
that reliability standard that provides a signal
that there is going to be at some point
a revenue stream for this reliability.
So I think that helps get the gears turning quickly,
or even just, we're gonna require,
basically a 0% reserve margin,
which would be loads have to meet their own obligations.
And that's very clear
that we're gonna develop a solution
that solves that problem
or achieves that outcome is a better way to say it.
That will start people thinking, investors thinking about,
okay, well, this is going to be an additional revenue stream
that can help justify investment.
-: I know there's a requirement.
If I build dispatchable power,
I know there will be a requirements
by my dispatchable power. -: Yes, you know that
there's going to be something there which is--
-: It does not exist today. -: Does not exist today.
We confirmed earlier at the opening of this conversation,
over the day that I already see,
or you're researching comments
and our general, all of our experiences does not drive new
dispatchable generation -: That's right.
That is one of the other things
I think that makes ERCOT unique
is it is very attractive for investments
even with the history of our market design,
when we have ancillary service floors,
you already enhancements,
you see a willingness to invest
based on a higher risk profile
than potentially what you see in other markets.
So just signaling that there's more certainty coming
from a reliability perspective
that will support investments.
That will start the gears turning,
and you'll start to see folks get more serious,
but it's hard to put your finger on a timeframe, right?
The more certainty we see in the solution, right?
The more certainty we have to show to our investors
and to say, see, look, we need to start moving.
So, it's a dance.
-: So, and I know you talked about
central procurement versus LSE obligation
and just for comparison.
So let's just say, we went out and said
we're gonna have ancillary or reliability service.
And just for example,
and we said, we're gonna procure, I don't know,
5,000 megawatts of these types of resources
with these types of characteristics
that would play in the market in a certain way
strategically and it's all well-defined
and setting aside all, the price impacts and all that.
Versus an LSE obligation
that we'd have to spend a couple of years
developing a framework on.
What do you think is gonna send the signal quicker,
honestly?
-: Well, so that will send a signal.
So, let's talk about the ancillary service path.
-: Or reliability service. -: Reliability service path.
-: Which you acknowledged
we have to kind of pursue that path.
-: I think, well, we already have, I started in July
when our company bought 5,000 megawatts of non-spin.
So we're already moving in that direction, right?
And so the question is with ECRS,
how do we want that to look, do we wanna buy more?
Is there some other ancillary service product?
So, let's talk about how that creates investment incentives.
That will, one is the demand for,
that short-term capacity product will go up.
So the revenue streams that you get
from selling that product increase to some extent.
And I also think there's probably a temporary phenomenon
where when you're buying that capacity,
you're reserving those resources
and you're holding them outside of the energy market
until they're deployed,
which means you have less resources
that are participating in energy markets.
So energy prices will naturally increase
to some extent as well.
But I think that's a temporary phenomenon.
As you see other resources come in,
then that'll naturally find an equilibrium there.
-: That sort of, I mean,
our ancillary service market works very similar to that.
-: It is, that's exactly what I'm describing, yup.
-: Lori also think about quantity of ancillary services.
It's a fair question.
So we, this summer, or going into the summer, we added,
I think total AS from 4,500 to 6,500,
which is almost 50% increase.
We've heard multiple proposals that said,
well, you just need to build
this reliability, ancillary service.
It's only gonna be two or 3000 megawatts.
We've already done that, we didn't get any new generation.
And on top of that,
we've got 75, 76,000 megawatts of dispatchable generation
in ERCOT right now, some of it's old,
some of it will be retiring, but we've got a lot
and I'll be interested to hear Bill's perspective on this.
But if you've got an existing fleet of dispatchable
and you set up a new reliability service
or ancillary service to buy 10,000 or 20,000 megawatts,
that's gonna be filled by the stuff you've already got
because it's cheaper to buy that power
than it is to buy power from a new generator.
It's just by definition.
-: But again, that's why we get back
to that question, Mr. Chairman, that we asked Woody
what kind of generation do you need to match that?
And again, a coal plant will break
trying to arrest that fall, ramping that quickly.
-: Sure, but that's fine, I mean, like again,
ECRS is needed and we need to do that.
No one here is saying to not do that
and to do it expeditiously, robustly,
but we need more than a hundred megawatt band-aids
strapped across ERCOT.
-: May I ask and actually NRG
this is an appropriate question.
-: Let me finish the thought.
We had a scarcity pricing event in late October,
the price went to a thousand dollars a megawatt.
Because ERCOT correctly allowed thermal generators
to go down for maintenance to prepare for the winter.
We expected 12,000 megawatts of wind.
We got 1500 to 2000 megawatts for that sequence of days.
And ERCOT and our stakeholders did an extraordinary job
making sure that we had adequate supplies,
but it was very, very tight.
That wasn't a couple, that was 8,000 megawatts,
10,000 megawatts short.
You'd have to add 8,000 megawatt peakers
just for a blue sky day in October
when it's just a normal fall day.
That's 10% increase to the total number of units
in our cart right there.
So, yes, we need to do that
but days like that and make it abundantly clear to me
that we need to go above and beyond, just that.
-: So, what I will say can, if I can add real quick,
because we did hear from,
and this is where I'm trying to understand
this a little bit more
because we heard from Mr. McCullough earlier,
and we know from live experience here
and your blue sky days
and what we're experiencing on those days.
But it seems like we would still be relying
on our ancillary service market, right?
-: Sure, you'd still use it.
That's the question, I think Bill's hit on several times.
To get new dispatchable, you need to put money on the table.
Somebody needs to put money on the table
to pay for new dispatchable.
Do you want it to be centrally procured?
Eight, 10, 8,000,10,000, 20,000, 30,000 megawatts?
Or do you want that won't be used
except in scarcity incidence?
Or do you want to set a standard
that requires the market participants to buy dispatchable
as in a mix that they best see fit for that moment in time?
-: But you're not doing that, sir.
You're asking them to go out
and buy a thousand megawatt facilities.
And the answer is 250 megawatt facilities,
and they're not band-aids.
On aggregated they're a suit of armor against these threats.
And then I would ask Mr. Barnes,
given this, what are you gonna go out and build?
You're gonna build peakers, aren't you?
Because that's the headroom you need
to meet these ancillary service type products
plus an LSE obligation so you double dip in both.
-: Plus there's ECRS that provides a fine revenue stream
for peakers in the near future.
-: I think the, again, this goes back
to the same foundation that I was trying to portray
which is certainty and cost
versus what you're trying to achieve.
So sufficient dispatchable resources
to solve an operational reserve problem.
You need 10,000 megawatts, whatever, pick a number,
but you also need enough
that you can have outages during that time.
You need enough if the load outperforms
and the wind under-performs, or if it's a cloudy.
So you need enough installed dispatchable capacity
to make sure you can meet your operational reserve needs
doing it just through ancillary services,
which again, up to this point, that's what we've relied on,
will increase revenues for ancillary services.
It will, I think, temporarily impact energy prices
but you will rely on those two revenue streams.
The capacity revenue stream will be a little bit
higher than it is today.
But again, in terms of the amount of dispatchable capacity
that you need to provide reserves and have one outage,
it's not gonna address that issue, right?
It's not the longer term investment signal.
It will help with the investment signal.
So again, in my opinion, it would be a lower cost,
higher uncertainty path than an LSE obligation,
which would be a higher certainty, but a higher cost.
-: And maybe higher, okay.
So I have one question left on this,
and that is for the Chairman's latest straw mans parameters.
And Mr. Chairman, you mentioned that in the first two years,
you could maybe consider an exemption for new reps,
as you work for a competitive rep.
Is that something you would be comfortable with
in the competitive market
if some reps were exempt for two years
for meeting an obligation, but you were--
-: Yeah, an exemption?
I mean, we've been really thinking hard about this concern
that's been raised about whether this proposal
creates advantages or disadvantages for retailers.
And we thought about an exemption or having some
other type of mechanism
that smaller reps that don't have affiliate generation
could use to help address
the reliability issue without an obligation.
This I would put in the category of something
that we need to talk about and think about more.
-: To clarify, so any new rep, not just on affiliate.
-: Any new rep, yes.
-: Exempted for two years or up to a certain load.
-: Yep, yep. -: Excuse.
-: This topic has come up
a couple of times in your discussion.
So I didn't wanna touch on it.
And it's the concept of Gene Taylor
or the fact that we've got
retailers that have affiliated generation in our market.
This, in my opinion, has been a natural evolution
of our market to find the lowest cost,
and ability to be able to be competitive
on a cost to meet supply.
As a large independent rep which reliant was at one point,
you have to procure a lot of capacity and a lot of energy.
Let's just say you have a 10,000 megawatt peak load,
it would be very difficult for you
to purchase 10,000 megawatts on the open market, right?
The cheaper way to do that
is have some affiliated generation
and then that way you can go out and get the rest.
It's almost would price you out of the market today,
so the market has evolved to that point
to be able to provide the supply
in the cheapest way for our customers.
Now, if you are always a rep
you're always looking for the maximum,
the optimal mix of supply to make sure you have a lower cost
and meet your targets and what you're trying to achieve.
But I just wanna make sure that
that that business model is understood
as a natural progression and evolution of our market
that has had to go in that direction in order to provide
a lower cost structure.
If I had to buy 10,000 megawatts
from you, Commissioner Cobos,
the margin that I would have to post and credit
would be extraordinary, right?
And so that's how large retailers have evolved
to be able to meet that problem in a more economic way
and with more flexibility.
Will: Do you have another question
or can I go? -: No.
-: Go, go, go, please.
But I do want to, I have a lot other questions
for a lot of stakeholders as well.
And so for the sake of time,
and I'm not trying to lower you
but I'm just trying to --
-: So my questions deal more with the retail market.
Then they do the wholesale market.
I think we're trying to make solutions
for the wholesale market,
which is important and reliability is managed through there.
But the retail market
was the crown jewel back in the '90s
when we pass retail competition.
And we've seen a lot of retail providers come and go.
And according to this study that I read since 2018,
you all have acquired five of the eight largest
and NRG accounts for almost 50%,
under 50% of the residential load in the state.
So 45%, according to one study.
So your acquisition of direct energy
totally skewed the HHI index
which basically said that this market is very concentrated
and that disturbs me.
It disturbs me that the crown jewel that we tried to pass
to give consumers a choice is becoming, you get one to five
and one of those five corners their generation market,
and then there are five
that corner of their generation market.
And then there are no small reps that come in here
because they can't build.
You yourself just said, you are trying to get
a economy of scale
by pairing your retail load with your generation load.
Not everybody has that balance sheet and that ability.
And that's what scares me about this.
It scares me that you all are pushing something
that you all can achieve, but nobody else can.
Maybe you and your four other brothers
that are the big Gene Taylors, but nobody else can
and that concerns me.
And I did ask you if this would allow you all
or you would bring on new generation
if they LSE obligation and you said,
paraphrasing it, you said, if there's a deficiency
and the rules were implemented correctly,
and we needed it for our load, then yes, we would.
And I think that's the mentality that I'm scared of
is that you all are gonna be doing just stuff for you all.
And this market was built on the premise
that we were all in this together.
We socialize transmission costs,
we're all selling into a pool
and we're pulling out of a pool.
And if we have five big Gene Taylors
that are gonna be just doing it for them, that's an issue.
-: And that is a fair question to ask
that we would have to address
as we work through this proposal,
'cause I can tell you at the end of the day,
a market structure that is not competitive
and does not have a robust retail market
would ruin it for everyone, including us.
That is not the objective of this.
The number-- -: What consists
a robust retail market, sir?
-: One second. -: Okay.
-: The number one threat, without a doubt
to the retail market and to reps is reliability.
That is to me has been made crystal clear.
So we have to solve that problem
in a way that preserves the competitive market.
Now, on the retail side,
and we've mentioned this and I'll say it again.
We are the largest buyer under our own proposal.
In terms of physical capacity
with the acquisition of direct energy,
we are the shortest entity in terms of physical capacity.
-: That means you've got twice as much load to serve
than generation-- -: We have a lot
of these things that would be part of this proposal,
and we would do that through many different ways.
-: The annual report strategic plan lays out
the fact that that is the expansion of load
is the intended business plan.
-: Yep.
-: You're planning on getting shorter.
You're gonna have, the plan is for your company
to have more load to serve than generation,
you can't more than generation.
-: We have widely, this is years in the making,
but we've mentioned that we are an asset light company,
and that's what we continue to do.
We are assigning more contracts and building less,
but financing the construction of other things.
But your concern that you raised, I understand,
we think other structures would be much worse,
but everything you just described.
We would have to address.
We'd have to make sure that that is satisfied.
We'd have to make sure that market power
was sufficiently mitigated
which if you look at these concerns of market power
and you'd go back and look at 20 years ago
with filings on when we developed Tizona market,
they're the same.
And we figured it out.
It's all been done before, and we can do it.
But just to emphasize this point,
is any reliability construct
that does not have a active and robust retail market
would be a failure for everyone, including us,
because if it's not competitive and it doesn't work,
the legislature will take it away from office.
-: On that note,
because you have very much focused on market power.
I would like to call Carrie Bivens.
-: Let's see if anybody else has questions.
-: Sure, sorry, go ahead, Jimmy are you done?
-: Anybody else? -: No, I'm good, sir.
-: Actually I do have one very quick question.
So under your construct, I hope I get this right.
I'm sorry if I don't,
but I think today, this was in someone's filing.
I don't know who it was,
but it made a good point and it just kind of stuck with me
and that is, ERCOT or does not talk to reps today.
They talk to qualified scheduling entities.
What's the mechanism for getting a rep obligation
information to ERCOT in that process, the LSE obligation?
-: That happens through the queasy,
that same construct exist today in renewable energy credits.
-: So that would roll up to the queasy,
the queasy would be the one responsible
for relaying that information to ERCOT?
-: So when ERCOT settles the market,
they know the load by LSE,
and that's how they calculate the compliance penalties
or the requirement to have retired enough reps
to meet your share under 25, 173.
-: Okay. -: Yeah.
-: That's a great question and I would love to explore
some of that with ERCOT as our discussion continues.
-: Thank you, Bill.
-: Thank you guys.
Just want to say,
having been part of this process and other processes
where we've discussed market design
at this Commission is a very complicated topic
that has many issues, and it is often been divisive.
It'll always be divisive among stakeholders, right, Katie,
but it is often been divisive
and I just appreciate the open candor
and discussion and dialogue you guys have had.
It's helpful for stakeholders and we know it's contentious.
So thank you for taking in all of our opinions and feedback.
-: Absolutely. -: Yep.
-: Any changes that's substantial meaningful
is going to upset some people and probably a lot of people.
And I appreciate you bringing that issue
front and center in no uncertain terms,
but I would also remind folks
that there's no prohibition on somebody
other than the big five building new generation.
-: Absolutely right.
-: They're actually constrained by law
from going beyond that 20% of the generation side,
which is the whole point of the exercise is getting
new folks to build dispatchable generation,
which would then be available for not only
their excess load, but everybody else.
-: Which we encourage that 20% to be 10 but was a lot--
-: That's another one you have to check with the legislature.
-: That's a question to the IMM.
-: All right, you wanna order from the IMM, Carrie?
-: Yes, if I can, thank you. -: Come on up.
-: Good afternoon, Carrie Bivens with Potomac Economics.
-: Hi Carrie, how are you doing?
-: Doing great.
-: So I think before we resume asking questions with you,
I think just for the purposes of the public,
can you give us just a brief background
on what the main roles or duties of the ERCOT IMM are?
-: Yeah, there are twofold.
So we monitor the market
and we recommend market design changes as we see fit.
The second role is to look for market power abuse,
market manipulation,
and refer those cases for enforcement if appropriate.
-: In your current duties of serving
as a ERCOT IMM, do you monitor market power abuse
in the bilateral market? -: No, we do not.
-: What are some of the challenges
that monitoring market power in a bilateral market
under an LSEO construct would present for you as ERCOT IMM?
-: Yes, our role is limited
to the central ERCOT energy market.
And obviously if the Commission creates new products
or creates new markets, we will monitor those markets.
There are some unique challenges that we see
with the LSE obligation proposal centrally because they are,
these transactions are taking place
through the bilateral markets.
So one is that these contracts
may not necessarily be standardized.
So you might have contracts that are for accredited capacity
for uncredited capacity, for other types of products.
-: You're talking the light touch proof of purchase,
no new product version.
-: Any other one because there could be contracts that are
from-- -: In the new product,
create a new product by definition,
it would be standardized.
-: The product itself might be standardized,
but doesn't necessarily mean the contract would be.
So if you're, you could sell that product
and sell other products,
all packaged together in one contract,
and it would be difficult to know whether or not,
what the actual price of that standardized product was
because there might've been consideration
in the other products.
If somebody was trying to artificially inflate or deflate
the price of that capacity product they could do so
by adjusting the terms or changing the other terms
of the contract so it'll be--
-: They could do that with any contract between two
sophisticated parties-- -: Absolutely.
-: Except for those two parties just like --
-: So if you hand me contracts and you asked me,
is this entity exercising market power
and I'm trying to compare multiple contracts
to find out what the true cost of that capacity was,
it'll be very difficult to compare apples to apples
amongst all these bilateral contracts.
-: Have you ever reviewed a bilateral contract?
-: We have not.
When we go through our RFI processes,
we ask for particular data and we'll often get
kind of information about those contracts,
but there is a lot of hesitancy
to provide the actual contracts themselves.
-: So in order to be able to review a bilateral contract,
I guess, first that the companies
would have to provide them to you,
which they're highly confidential
and there's a lot surrounding there,
but in order to review them,
would you have to have the entire contract?
-: Yes, we'd have to have the entire contract
and another issue, again,
our role is to find market a power abuse
and refer it to the Commission for enforcement.
So let's say that we were able to detect and identify
market power abuse in the bilateral market
through these contracts
and we referred to the Commission for enforcement,
the Commission enforces, maybe there's penalties,
there's still a contract that was executed
and that the LSE is subject to for a year or longer
and that contract cannot be canceled necessarily.
And so even if something, we like to try to,
and that's why we participate so heavily
in the market design process
is that it's better to design markets
that prevent the exercise of market power in the first place
than trying to come behind it
and use penalties or enforcement after the fact,
because the harm is already done at that point.
-: How do you know there's not market power
enacted in the current bilateral market
if you're not reviewing those contracts?
-: Well, every entity has access
to the ERCOT energy market.
So if you weren't able to access good terms
in the bilateral market,
then you can purchase everything you need
from the day ahead market at ERCOT.
So there's that backstop.
-: Would that change with the LSE obligation?
-: Okay, so, one option would be a backstop
or residual type market,
so that if LSE had difficulty accessing
good terms in the bilateral market,
there would be a backstop or a residual type auction
and it would have all of the features--
-: This is in a new product scenario.
-: In a new product scenario.
It would have all the features
of any other centralized market
that would have market power mitigation,
reliability based demand curve, all of those features.
And it would probably in the end
just become a centralized capacity market
with a self supply option
is what it would migrate to over time.
-: And just to be clear, okay.
You're saying that a protective measure,
or a process to help you monitor market power
in the bilateral market under LSE obligation.
The one that you're pointing to, the residual auction
is essentially part of the capacity market?
-: It's essentially the heavier touch version--
-: What about in a proof of purchase scenario?
-: I'm not sure I understand how that would work.
-: Like the SBP, the first part of SBP
where you just, without the deliverability problem.
The part that Lubbock said was pretty straightforward
and easy as administrative accounting.
Didn't really change business.
You just need to prove that you purchased reliable power
for the customers
that you believe you were gonna need to serve.
-: And it would be based on accredited capacity?
-: Yes, an accreditation standard
that holds each resource type accountable
for their level of reliability,
just like you would do in the heavy touch version.
But if you're hedged, and then escalating fashion,
as you get closer to the operating day,
the only change in your day-to-day life
would be showing the receipt essentially.
And you don't have to, there's nothing saying that,
the wisdom of the contract you signed
between two sophisticated and competent parties,
you just need to show that you purchased the power
that you expect to have to deliver.
-: Right, I think that has the same market power issues,
because it's wholly relying on the bilateral market.
-: How do you know that's not happening
now in the bilateral market?
-: Because right now you have access to the ERCOT market.
-: You still would. -: You still would--
Peter: Nobody is getting rid
of the real time of the data.
-: But you're telling me I have to prove to you
that I have purchased for capacity
and if I don't do that, I have some penalty, right?
You're forcing me into the bilateral afford market
whereas nobody's forced there today.
-: That's the problem.
Nobody's buying dispatchable power in the future.
That's the problem, that's why we're running out.
-: So Carrie, under our PUC rules right now,
you're not required
to monitor market power in the bilateral.
In the bilateral.
Yeah, that would be an expansion--
-: Of your role. -: Of the role
under the substantive rules.
-: So what would that mean?
I mean, are you gonna have to add more staff, expertise?
I mean, what does all this mean?
-: Oh yes, absolutely.
We would need more staff.
We would probably issue
many more RFI, request for information
whereby folks would have to answer all of our questions
and provide all of our contracts
and we would have this iterative process.
But that's fine, we're happy to do it.
Just note that for every RFI we issue,
I'm sure everybody in this room can tell you
how much they don't enjoy having to respond to that.
It's quite an administrative burden for them as well.
-: So no matter what,
and what construct of an LSE obligation,
whether it's the souped up one or the light one,
you're still gonna have to have
some kind of new approach to addition to reviewing
and you'll still have to read those contracts
that you've never read before.
And we'll need some sounds like some additional staff
and maybe some expertise, perhaps.
Carrie: That's right.
-: So if you're gonna need all these things, right?
Who pays for the IMM?
-: The IMM is paid
essentially through the ERCOT administration fee.
So the archive administration fee
is assessed on a megawatt hour basis to load.
-: Okay, I'm gonna kind of change the subject here
because this is another piece of the lighter approach
or I actually, I guess just the one you had proposed
last time, Chairman, the public bulletin board,
will that help?
-: I'm not sure I see the benefit
of the public bulletin board.
there's no guarantee that what's posted
on the bulletin board is accessible.
-: What do you mean it's not accessible?
It's a public bulletin board.
-: It's a public bulletin board.
Maybe I need a little bit more description.
-: Oh, I mean. -: Natural gas pipeline
is a delivery point bulletin board.
It's a public facing website,
has prices and volumes of every transaction.
-: And so maybe I call you and I say I would like
whatever you posted and you tell me, oh, I'm sorry,
that's not available,
but I've got this other thing for different terms.
It's not a--
-: So you're saying that if the IMM called companies
under the Commission's jurisdiction to ask about
specific transaction,
they would swap out the contracts
and give you a different contract
than the one you really want.
And are we sure that's not happening today
when you put out an RFI?
Are we just conjuring up ghosts that already, I mean,
if you're worried about people switching out contracts
on you, that's a now problem as well.
-: No, I guess I'm just trying to say that
a bulletin board is not the same thing as a cleared market.
And so it's just somebody putting up a post-it that says,
I'll sell you this at this dollar amount
and that doesn't necessarily mean that
the other contract terms are going to be favorable to you.
-: So, the bulletin board with post executed prices
and this would be--
-: Oh, this is an after the fact, maybe,
I apologize.
I thought the bulletin board concept was,
because Australia has like a trading platform
where they do some brokerage services and that's the before.
Okay this is an after. -: And do both.
I know this is not the way ERCOT works but most,
a lot of markets have the bid stack,
the offer stack all in one,
you can see price transactions cleared and you can see--
-: Okay, absolutely that,
increasing transparency would help, yes.
-: Or real time, I mean,
these are updated every five minutes.
If it's cleared, it's posted,
if it's a bid or offer always subject detained,
but you can see the stack.
-: Yeah.
The only thing, I just wanna go back to the fact that,
these contracts may contain terms that are not comparable.
It's not necessarily that one and another
are gonna be the same.
So let's say you've got two affiliated entities.
One is selling to the other,
the capacity part of that contract
might look lower and it,
I don't wanna go into too much detail
because I feel like I'm just telling people
how to get in trouble. -: Said by monitor.
-: Yeah.
Maybe I need to be a little bit more cautious, but anyway,
I can certainly see examples
under which you could try
to make things look different than they are.
-: Take it from the other side though.
Is there a reason to have different terms and contracts
for different counterparties, valid reasons?
-: Yes. -: Okay.
So just because they're different terms,
doesn't mean they're evil or manipulative?
Carrie: No.
-: And there's a very good reason you could sell power
or any good or service to one counter party
at a higher price than you did it,
the same product to the next counterparty.
-: Yes. -: They're very legit
and I'm gonna make sure everybody's clear on that.
There are very legitimate business
and risk management reasons for that.
-: Okay, because different counterparties
have different risk profiles.
-: Different risk profiles, different delivery terms,
different-- -: Yes.
-: Financial risk management
and payment terms associated with it,
there are a lot of reasons
for different contract terms to exist.
And just because they're different
doesn't mean that they're malicious.
-: No, no, absolutely.
I'm just saying that,
if you're selling a megawatt of energy in real time,
that megawatt of energy is the same for everybody
and so I can say if you're offering $30
and you're offering $800,
I can very easily compare those two
and I can make some judgment calls about.
-: Sure, and also just to be a point of clarification
on all of these proposals, none of these proposals,
anywhere on the spectrum, envisions a real time
constant checking of exactly how many credits you have,
or exactly how hedged you are.
In my straw man at most it was a one month away
from the operating day.
At which point, and you asked about the realtime
and the head market earlier, that's what they're for.
I mean, after one month ahead, under the first straw man,
which is just a starting point,
we don't care.
We've got the proof of purchase in the lightest touch.
We've seen that you bought 95%
or a hundred percent or whatever the number is
and you go about your business.
Nobody's checking every morning
or every four hours that would prevent.
So you can still go to the realtime market.
You can still go to the day ahead market
to meet your energy needs.
There's no requirement in any of these proposals
anywhere on the spectrum,
that if your load changes a week ahead,
you've got to scramble to get more credits,
capacity credits, or decks,
that's not proposed anywhere in any of these versions.
It's a monthly at most, probably more likely
quarterly checkpoint with ERCOT.
-: For the 5% that has not been procured?
-: In January you've got to submit your report.
Some subset of those would be audited.
And they look at essentially your book three years out,
here's the expected load, do you have 50% of that, check.
Do you have two years out, do you have 75% of that
or whatever the escalating requirement the obligation is,
that's a milestone or check-in,
there's no real time penalty.
And they'll check all your operating days.
Three or seasons is months, weeks.
I don't know what metric we'd wanna use,
but you look ahead and say, hey, if it's January,
what do you have lined up for February?
We're only gonna look a month ahead out and further
because once you get within the month,
it's too dynamic and it's moving too fast.
So it's not a real-time buzzer.
Nobody's sewing a flag in the middle of the football game.
Whether it's a new credit product
or the light touch proof of purchase,
they're just checkpoints and milestones along the way.
Nobody's gonna grab you two days before your operating day
and say you're two token short.
That's not envisioned at all.
I just wanna make that important clarification.
-: And I got to say that I'm gonna need the (indistinct)
I think to properly evaluate what you're recommending
and this now new lighter touch approach.
I think it would be helpful to have it
scripted out because I'm now beginning
to get a little bit confused
as to what the purpose of the reliability tokens are
and everything, and in order to properly evaluate it,
I think we gotta get it sort of shaped so we can look at it
and be able to ask appropriate questions.
But at the end of the day I think,
it sounds like no matter what,
you're still gonna have to look at the bilateral contracts
and they're just not standardized contracts, right?
And that's fine if they're not standardized,
but I think what you're saying is,
it's not that there's any malicious intent
because they're not standardized, they never are.
The point I think that you're trying to make
is that it's gonna be a very complex administrative
process for you to look for market manipulation
in an area that you've never monitored before.
-: That's accurate, yeah, that's a challenge.
-: Under this scheme, how would you,
what are your fears about manipulation?
Because we've got large actors
on both sides of the field now.
What worries you?
-: I think Commissioner Gloflefty spoke very well
to my largest concern which is around
the fact that there are large retailers
that have affiliated generation.
And so they're going to, I think it was even stated here,
they're gonna reserve that generation for their own use.
And let's say they had more generation than they have load.
You have a retail arm that you could, now I'm being,
I feel like, again, like I'm talking about
how you could do it--
Will: Well, this is the future.
-: I know, I know, anyway.
-: That's a blueprint, she does not wanna lay out.
-: Yeah. -: I mean, maybe one or two.
-: But you have an advantage over smaller retailers
because you have access to this affiliated generation.
And why would you want to help out your competitors
by offering that generation to them,
knowing that they'll be penalized if they don't have access
to enough generation to meet their obligation
and there's a limited amount of,
there are pivotal suppliers.
And so you could have an advantage there
by forcing the small retailers to go
to ERCOT with their penalty,
which could be very extensive.
And the backstop to using the penalty
is to have ERCOT procure some sort of resource for them.
And I would love to ask for more detail
on how that would work. -: Best offer (indistinct)
mentioned earlier can be helpful.
-: Yeah, but I mean, if you have retailers
that don't meet the showing and they pay a penalty.
There was a statement in the obligation proposal
that then ERCOT would procure on their behalf
and I would love to see more detail on how that would work,
especially month ahead.
-: Would the must offer requirement help?
What is your thought on that?
-: I definitely think if you have a capacity product
that it means you need to have a must offer requirement
into the ERCOT market, yes.
I mean, otherwise I'm not sure what that credit gets you.
-: The other piece is I think is interesting is that,
we were talking about penalizing
and not penalizing and penalties.
These are contracts that you're penalized,
that you pay your penalty and you're still gonna keep going.
Well, the entity that is subject to a penalty
would just keep going
and that LSE is locked into your contract.
They're still on the hook for getting into a bad contract
that Carrie has discovered has issues.
Is that a fair representation?
-: Yeah, again, so that's kind of where you come
after the fact monitoring, which definitely has its place,
but the before,
because it's in the bilateral market,
there's a mitigation that can be really handled
before the contract is signed
because it's all happening party to party
instead of through some entity that can impose a mitigation
ahead of time.
-: Do you think there could be affiliate,
well, like most favored nation status kind of contracts
that if you're a affiliated retail provider
that your generator has to provide
under the same terms and conditions
to other retailers in the market?
Is that something that would be a viable?
Yeah. -: Yes.
-: Is that something that happens today in bilaterals?
-: No, but it is something--
-: How do you know?
You don't read the bilaterals today.
-: There's no requirement in the statute that you offer--
-: Okay, so simply having an LSE obligation
would not necessarily introduce behavior or the opportunity
for malicious behavior that's not there today.
-: Yeah, I'm pretty sure that there's some cases
in non ISO markets in which there are rules such as that,
that you have to offer non-affiliated entities
the same terms as an affiliate.
-: Sure, but let's not pretend
that just by bringing in an LSE obligation
and that would suddenly introduce them.
I know, I'm just being,
it's just a clarification for folks watching at home
that this would magically introduce the opportunity
for malicious behavior and bilateral agreements.
That's a challenge today.
-: And my point of bringing it up was more that
it could be a viable mitigation measure--
-: Sure, sure. -: If something like--
-: If today there's no LSE obligation, that's the difference.
The LSEs are physically financial responsible
for procuring their obligation at whatever percentage.
So that's the difference.
And that's why they will honor our market counts today
and that's why we got to make sure the ERCOT IMM
can effectively monitor the bilateral market.
-: But there's risk in not doing so,
as I think somebody pointed out earlier,
if you go into the operating day short and un-hedged,
you better hope that whatever price
you get in the spot market
is lower than what you charge your customers.
So there's financial risk,
and a lot of people will take advantage of that
by just showing up to ERCOT and saying,
I'm sure I didn't hedge,
ERCOT, it's your responsibility to serve--
-: Well, I'll say that we had a slow of reps
that after the storm, which was extraordinary,
but typically we don't have a lot of that go on.
We've spent a lot of time
strengthening our rep certification rules,
strengthening our rules of the PUC
and ensuring that we have solid reps come into the market.
So it's not something that's happening a lot,
but I understand we saw that a little bit more recently
because of the storm,
so I wouldn't classify that as a reoccurring problem.
I think it's one that we definitely experienced
because of the storm, and ERCOT got some reps
on their books right now that defaulted,
and that's all true, but with respect to,
does that happen all the time?
I just don't know.
I mean, this is a different kind of obligation.
-: Sure, but if all of these LSEs are hedged anyway,
what burden are we?
I mean, they're forcing themselves to go buy those hedges.
I mean, we heard two years earlier,
we've heard other people
that are buying power five, seven, 10 years out.
So if they're doing it anyway, what's the change?
I mean, how does life change for that individual in LSE?
-: Well, you're you gotta do it, or you will penalized.
-: I mean, they're doing it anyway.
-: I would just say the other difference
is a lot of folks today are financially hedged,
but they may not be physically hedged,
and what the LSE obligation
puts a physical hedge requirement on you,
that does not exist today.
And so if you're going out with, you might have exist,
so that's something that we brought up in our comments
is that you have existing contracts today,
Lubbock talked about first,
if that's not tied to physical units
that can determine what they're accredited capacity are,
then those contracts would not count
towards an LSE obligation.
So there is-- -: Sure.
That's also the important part,
making sure the physical power's there
and not just hoping that my financial book works out.
All right.
Thank you, Carrie. -: Sure.
We're at a good spot for a 10 minute break.
So we'll step away for, 10 minutes are good?
All right, we'll be back at 2:40.
All right, this meeting
of the Public Utility Commission of Texas
is now reconvening.
We certainly had a thorough discussion
about the LSE obligation
and heard a lot of the benefits and the challenges,
concerns, and possible ways to mitigate those concerns.
Obviously, like everything else,
not at something to make a decision on today.
The most important thing is that we keep,
as always said, scrubbing all options.
And in the sake of time,
let's move on to any other firming options
or above and beyond reliability standards.
Obviously, we've covered my proposal of an LSE obligation,
would love to hear thoughts on other mechanisms.
-: Chairman Lake, so I really had a lot more questions
for some key folks we gotta hear from at ERCOT
and I think even the independent reps,
I would love to be able to ask them some questions
since we're not gonna have an opportunity
potentially to ask them any more questions
throughout our process.
-: Okay, just for the sake of time management,
have you to call them back up or call folks back up,
are there any other firming concepts
that we wanna discuss in the time we've got?
-: If I may, Mr. Chairman your gavel, LCRA,
could they talk about their reliability?
Is that, yes, that one.
-: Okay, so you do wanna fit that in--
-: Sure, I like that.
-: To get us out of here by 3:34, hopefully.
-: Do you have two minutes is for--
-: No, I'm happy to, I'm just trying to think about
how much we gotta cover in the time we've got.
So yes, I would love to hear more about it.
Any other concepts?
I know there were some TDU concepts.
-: I give my time Commissioner Cobos.
-: And I'll try to make this quick
so we can have LCRA come up and talk about that.
-: Okay, I'm trying to get--
-: I'm sorry, I keep hitting you in the chin on this
when I don't have some alternative right here
to hand to you, so we'll keep at it,
we'll keep figuring it out.
-: Yeah, and I'll say, Chairman Lake,
I mean, you coming out boldly with a concept.
I really am interested in going back to the drawing board
and coming up with some strategic reliability service
to also look at it as an option
and I'm gonna do my best to come back with something else
'cause I do think we need to be looking
at more than one option
and not all of them are gonna be perfect,
all of them have positive and negatives
and so I think we,
it is a matter of due diligence that we continue to look
for at least one to two other options
near the finish line in December.
-: As I've said, open to all ideas,
there's no apparent silver bullet,
but a key part of that is actually having other ideas.
-: And be little bit more open-minded about it
because I think that--
-: I am very open-minded about it.
I'm happy to consider the TDU purchasing,
the capacity credit so it doesn't touch the retail market.
That was one of the interesting suggestions that came in.
I'm happy to consider any and all ideas.
We've got to move past reading the same comments
from the same folks over and over again,
and start making decisions and picking a path forward
and like you said, to scrubbing, so--
-: Yes, sir.
And I know you've been very open
to hearing a lot about different concepts.
And so, by no means, we're all trying
to just keep an open mind here.
I guess what I'm just saying is,
kind of continuing to look for something
that accomplishes our goal
of ensuring reliability for the future
in our evolving market
without necessarily calling it affirming requirement.
'Cause I think when we call it affirming requirement,
we get really narrowed in on one path
and that's the LSE obligation, you're absolutely right,
that is, if you're gonna affirm,
then that's, well, structures are out there.
-: We can do it on the generator side too.
You can do it with just curtailment.
I think everything's on the table,
but I certainly am not gonna go back to the legislature
in the ADA.
We thought real hard about it
and did a couple of studies, they want action.
-: So, one thing to consider,
I know I'm gonna terrify people now.
Okay, we mentioned this before, gas credits.
We're very close to that threshold--
-: Like what? -: The gas credits.
Remember the statutory-- -: Th 51%?
-: Yes, sir.
-: Oh yeah.
-: So we're close to it.
-: You're above it, depending on the operating hour.
-: Depending on how define it.
-: Or the operating hour.
-: Yeah.
And we may not be there yet,
but with the amount of penetration that we're talking about,
we may cross the threshold.
It was put in there,
at least it's since I can read the statute,
it's clear, it's statue, just like Rec.
-: Read the key part so folks with watching the home
know what you're talking-- -: Sure, sure.
Go for natural gas.
And this is pure a section 39, 9044 A.
"It is the intent of the legislature
that 50% of the megawatts of generating capacity
installed in the state after January 1st, 2000
and use natural gas.
To the extent permitted by law,
the Commission shall establish a program
to encourage utilities to comply with this section
by using natural gas produced in this state
as the preferential fuel.
This section does not apply to generating capacity
for renewable energy technologies.
And it is the way that we define that
that could be considered."
-: What would your suggestion be?
-: How would you compute the resource mix of renewable energy
technologies as a part of a big pie chart?
Or are we talking about natural gas once it falls?
Because it's at 46% today
in terms of the overall resource mix.
Jimmy: Capacity or energy?
-: Well, Jimmy, I think we need to read the statute
many, many times and they might appear,
but that's like many things.
So I'm saying we got options.
It is a mechanism just like Rec.
The statute is mirrored after the Rec program,
something to think about as we--
-: So what would that look like in practice?
-: Just like the Rec program.
-: Everybody's got to buy gas credits.
-: To a proportion that gets us to 51%
of a dispatchable resource mix,
depending on the definition.
-: And the proceeds of those gas credits
would go to the purchase of gas supply.
-: That's correct, yeah.
-: That's something that you wanna put it on the table
for consideration, let's put it on the table for scrubbing.
-: Well, heck yeah, I mean, easy.
Yeah, we'll do it.
But I'm just saying that it may be an answer.
-: Yeah, that we've got to turn over every stone, right?
-: Sorry, I don't sound more optimistic,
but you know what I mean, we've got a lot on the table.
-: Yeah, but we've got a big challenge.
It's a challenge that a lot of other places
grids around the world are facing.
None of them seem to have handled it well,
a lot of them are watching us,
so we need to tackle it head on
and we need to be aggressive about it.
And as I mentioned earlier,
the ask for each of your offices
is to work on laying out your thoughts
on each of these components.
And Carrie and I talked about the winter, I guess earlier,
an ERS, I'd include ECRS,
what did each of you independently think
what that would look like,
I guess, and include that, flush that out.
What would it look like?
What would the benefits be?
What would be the concerns, pros and cons.
-: Next.
-: And do include the pros.
-: Yes. -: Yeah.
-: All right.
So we wanna hear about the LCRA reliability at ERCOT,
but before then, Lori's got some questions.
Does that work?
-: Yes, that's fine, if you're good with that.
Thank you.
I wanted to ask ERCOT about their implementation
of the LSE obligation and just some questions
to see what you may be able to share with us today,
because a big part obviously, of these proposals
is trying to figure out what the timeline is
for implementation.
I know right now, I think largely, I think--
-: You gotta pick a place on the spectrum
before you can figure it out.
-: Right, we gotta get some definition,
but I gotta also understand what are we looking
at ERCOT, if you're able to share
any glimpse at this point, right?
So, are we looking at system changes
that are impacted by the MS upgrade
or just settlement billing system changes
and how significant?
-: Yeah, I think in the way we've envisioned
sort of the ideas have been laid out
in terms of impacting existing systems,
it would primarily be settlements.
And so we've talked about some of the other priority,
things going on that affects settlements,
but largely, it seems like it would stay away
from a lot of our other core systems.
So I think that is certainly a benefit,
there'd be investment in whatever the new systems might be.
There maybe be some need for additional personnel,
but from a conflicting with existing systems,
I think it really is primarily around
our settlement systems.
-: Okay, and how significant,
because I've heard different things,
I've heard tremendous impact on settlement billing process.
So I just wanna make sure, like what kind of scale,
because we've got securitization,
we've got a lot of things on the,
I wanna make sure I understand what that impact is
because you have a lot on your table
and the settlements processes keeps coming up
over and over with everything we're talking about
in anything, right?
-: I think again, that's probably the devil's in the details
as you've all been describing on a lot of these things.
Again, maybe even one of the benefits,
I do think they would be fairly significant
settlements to changes.
That being said again, there'd be new.
So in processes I envisioned largely.
So to some degree, we're not again, necessarily
affecting some of the existing settlement that we have.
I think there's no doubt that it would be
a significant project,
but there is some of the benefits again
of it being new systems in some cases
and new processes in something like settlements.
-: What about forecasting?
I know E3 proposal has ERCOT--
-: Sorry, not E3 proposal, I mean, when we've got
my proposal is very different from the E3 proposal,
which is very different
than which is in the middle of a spectrum.
So there's a range here.
I don't wanna be beholden to just the E3 proposal.
-: Right, so, okay, understood.
So in your proposal,
is ERCOT involved in the forecasting?
-: Yeah, it would be some to be determined
but some ERCOT based load forecast by season,
like I said earlier by season, by month, by week,
the more granular, the more beneficial,
but of course, the more granular, the more complex
and more challenging to implement and operate.
That's something that would be a decision
to be made further on through the process.
But yes,
it would be some version of load-share ratio of forecast.
And of course that would be,
the obligation would be some percent of whatever that is,
which is why there's such a tremendous discount
on the four dated three year, two year
because there's always forecast error.
Forecast error increases the longer you project out.
The important part is for LSEs to procure physical power
to provide a price signal in the future for investors
so that investors that are considering building
dispatchable generation in Texas of any variety know
they have real hard numbers on what kind of megawatt
or value they can get for each megawatt
that they'll provide
by the time they bring that unit online,
like knowing what a megawatt worth today isn't very good
if your assets are not gonna be ready for two years,
you need to afford price visibility.
So in any LSE that loses 50% of their expected load
over two, three years,
ain't gonna be in business very long anyway.
-: Okay.
And thank you for that clarification
'cause I know already E3s and I know you had a different way
of approaching it.
So I was just trying to understand is this something,
in any proposal whether it's something ERCOT can do,
and do you have the capability right now
and do you have to have system changes
to be able to get information from LSEs
or anything like that?
-: I mean, I think we already have the capabilities
to the type of forecasting out and the system-wide,
obviously, there has to be some mechanism
to come up with some ratio share
to handle it out, again,
I don't think -: What's the ratio
of existing settlement system.
I mean, there's ways that we do load ratio share today.
So I'm sure there could be some methodology that come up.
So I don't see a change in systems associated
with that part of the process.
I think maybe where there,
something that would be a little bit new,
although there's some work that we've done in this area
and Mr. Barn mentioned it is related to accreditation.
So we obviously have to develop those processes
and come up with those look alike.
-: Okay, well, for the sake of time,
because I think to some degree,
we still got to get more details on paper
before I can really kind of drill down deeper
into ERCOT's implementation.
So for the sake of time,
I think I'll release you Mr. Roger.
-: Okay. -: Anybody got a question?
-: Oh, I'm sorry.
-: Thank you. -: Thank you.
-: I really would like to ask Cathy Webking some questions.
-: Sure.
-: I give you my time.
-: Good afternoon, Chairman, Commissioners,
Cathy Webking
with the law firm of Scott Douglas McConnicko.
-: Hi Cathy, so I know you submitted some comments
and I just wanna make sure that
'cause we've been very fast through this process
and the potential impacts that the LSEO proposal
in one form or fashion
and really just speaking to actually
just German Lake's proposal
since that's the one we're focusing on at this time.
Is that something that would be palatable
for your independent reps?
Do you still have lingering concerns?
Because that's what we're focused
on the Chairman's approach at this point.
And so I just wanna make sure
I get an apples to apples comparison.
-: Speaking from the perspective of independent reps
that don't own generation today,
or don't have affiliates that own generation,
as has been pointed out,
we're prohibited from owning generation.
We have very grave concerns
with a capacity obligation on reps.
That is not to say that reps don't hedge
and buy firm power for all of their expected usage,
which they do today from contracts.
But this is a separate, my understanding
of what we've seen in this period--
-: That'd be handled, it would be a separate product
and there's also no requirement
for independent reps to hedge their power today.
Many of them do that as a business choice, correct?
-: Correct.
And to my knowledge, most. -: Not all of them.
-: I am not aware of any
that are in business today that do not.
-: But for sure were a lot less February.
-: I don't know that that's been demonstrated Mr. Chairman,
and I'm happy to look at it.
There were other non reps who were not hedged.
Peter: I can think of a few, a couple of them.
-: Yes, but in terms of retail electric providers,
that is not my understanding
of what the concern was in February.
They had firm power purchase agreements
that were not able to be satisfied physically,
but it was not because they didn't have
a firm contract in place.
-: Perhaps a combination of both.
-: Absolutely.
With regard to the intermediate understanding of just,
of course, it's a just a basic structure
that's in the summary sheet
as we would understand at this point,
but it still looks to the LSE
to demonstrate a capacity procurement
specific to a physical resource
which is not how it's done today.
Today our firm contracts are, as Mr. McCullough described
from contracts with LDS liquidated damages
and they do, a retail electric provider
will have a QSC that represents them at ERCOT,
that QSC will procure resources
on behalf of the retail electric provider
as they enter into contracts
and that may be through another QSC
who may be through another QSC.
Ultimately there is a physical obligation in there,
but the individual reps qualified scheduling entity
does not necessarily have to demonstrate
which unit and which megawatts
associated with that unit are being procured.
And so it is a new product.
-: Could you speak to the lighter touch,
the proof of purchase
into the spectrum and what that impact might have.
-: If the lighter touches just demonstration
of energy hedge. -: Physical energy, I guess.
-: When you start putting the physical in there,
and then you start saying it has to be individual attributes
of the individual physical unit.
-: So you're not attributes of a unit,
just a classification of unit.
So it doesn't have to be a gas facility
for this accreditation.
It doesn't have to be the gas facility.
It's gotta be a gas gets so many credits.
Solar gets so many credits,
nuclear get so many credits,
it's by class, not by individual unit.
-: But as I understand the proposal,
it would be that the LSE would still have to say,
I am saying that these physical generation resources
are the ones from which I am procuring power.
-: That certainly could be a version, yes.
-: Okay.
In that version, that is still a tied to a physical unit
and physical megawatts, which are capacity of that unit.
And that is a much different scenario
than what we have today.
-: Would the exemption for the first two years help?
-: I went with Mr. Barnes on that,
trying to evaluate that
from a competitive position is very difficult.
And again, if you have this forward procurement,
there's still a much different issue there
because you're in essence being asked
to demonstrate forward capacity purchases
which are not able to be billed to the customer that day.
You may not know
that you're gonna have that customer in three years.
There's no revenue stream associated
with that forward capacity purchase.
Under our energy market today,
there's a very close correlation between the revenue stream
and the customer contract and the physical,
firm power procurement for that customer.
-: Okay, what about the forecasting process
that the Chairman laid out?
Is that something that you believe the LSEs that, I mean,
do you have any thoughts on that again?
-: And I have Steve Madden here
who's also an expert on the kind of forecasting and supply,
and we can certainly get into those details,
forecasting by LSE, for particular customers.
That's the exciting thing about our market
is that customers get to determine their options by shopping
and moving and moving freely.
And so forecasting that what my customer base
might look like years ahead is a very...
-: So do the retailers provide their investors
with forecast of customers and forecast of revenue,
or just say.
-: Those would be proformas, right?
So you could do that but--
-: You just make them up or where do you get those numbers?
-: I mean, yes, I mean, quite honestly,
I mean, that's what you're doing, right?
I mean, it is honest, it is just made up,
I mean, business models change.
-: So is it based on any analysis
and I hope some of your investors are watching.
-: So you have a strategy
that you've set as an entity corporation,
and then you look out
and you look at the market size and potential,
and you decide what percentage of that market
you think can capture
and you build that into your proforma,
but it has nothing to do with reality, right?
So now reality comes in and I change my business.
-: I'd love to invest with you.
-: You would've made a lot of money.
-: You're good at guessing.
-: I've sold two reps, yeah, I know.
-: Are you one of the coaster guys?
I don't care what I'm selling,
I make it up. -: I heard that.
-: We really do care about our customers.
I mean, February-- -: You just said
you make it up. -: Well, yeah, we make it.
-: Chairman, let me please,
the proforma was it a forward projection
for a business plan is a much different thing
than a cash obligation today,
three years forward for a customer you don't want.
-: How do you pay for the power you purchased
two or three years, five years, seven years--
-: As you sign contracts now this is where you hit reality.
So now like today, I'm sitting here,
I have 10,000 customers and in three years,
I'm hoping I have half a million, right?
And that's what I'm gonna tell my investors
that's what I'm gonna work on towards.
But if I went out and bought capacity
for that half a million at today's prices,
let's say I bought that at, I spent $10 million on that.
And then all of a sudden it's worth $2 million.
I'm out of business
and if I don't get those 500,000 customers,
what if I only get a hundred thousand?
-: So just again, for the 300th time,
nobody's asking you to buy a hundred percent
of anybody's load projection three years out.
It's a percentage of.
-: Right, but what would I base that off of.
So I'm sitting here today, like, back to that example,
I have 1000 customers
and I hope to have 500,000 in three years.
And I very well could, right?
I mean-- -: Sure.
You can base it on ERCOT load projections,
load share ratio projections.
If it's a young company and a high growth mode,
that's why the exemption is there.
If it's below a certain load threshold,
you can certainly accommodate that.
But I'd tackle it from the other side.
If we're expecting such explosive load growth,
where are we gonna get the dispatchable power if nobody's,
for three years from now.
-: People are buying that for three years from now,
this company that's coming in
and is signing up this customer to serve them,
they buy that power today.
They enter into a contract for that power
before they sign that customer and--
-: All 500,000 customers or a thousand, or?
-: As we sign them up.
So that's what we have to be responsive
to market prices, right?
This market is very efficient.
So as market prices are changing,
we have to adjust our prices to end use customers.
-: Sure, but you don't have the 499,000 customers yet,
but you and a lot of other folks out there
are buying power that won't be delivered or obligated
until three years ago.
-: If I would sign up a customer on a three-year agreement,
I'm gonna go out right now
and buy that power for that customer
for the next three years.
-: So you're not buying any power and expectation of growth.
None ever.
-: Very little, you can't,
because if the market falls, you're out of business,
very quickly, if you do that.
-: All kinds of businesses and all kinds of sectors
buy future supply and their plight prices fluctuate.
And that's in fact
the point of our financial hedging system
in any industry is to mitigate that risk
yet provide a mechanism for ensuring supply.
-: Mr. Chairman, for the entire grid,
if the concern is we need to tell the generation market
how much generation is gonna be needed and going forward,
system-wide that number is understood.
ERCOT forecast that number system-wide.
And system-wide that number can be evaluated
and we can decide, you know what, system-wide,
we don't have enough resources looking forward that we want.
So we can look to ERCOT to use a reliability product.
I think LCRA and others have talked about that
to meet that forecasted gap.
Peter: The (indistinct) as Jimmy currently says.
-: On an entity by entity basis,
with a competitive market on the retail side of it,
it becomes a much different prospect,
but for the entire grid, the generation can get the signal.
-: Sure, okay, so it clearly hasn't in the last, it hasn't,
I mean, that's why we're here.
I mean, that's why we have SB3 for both of the problems,
extreme weather event problem, and the blue sky problem.
And so if, I mean, it brings,
comes back to the buying another 5,000
of reliability, ancillary service,
it's just gonna be filled by definition
with the units you've got.
There's this carve out for performance standards for ECRS,
to address a very specific problem,
but we know we haven't gotten
the new dispatchable investment that we need.
That's abundantly clear.
And so by expanding our existing ancillary service suite,
you could double it.
What difference would that make?
-: If I can, 'cause this is part
of what I was trying to get at earlier, Chairman Lake
with ERCOT is we know they're buying ECRS.
We don't know how many megawatts,
we gotta sort of get a real good view of what we're buying,
what services.
I don't know this answer, and I'm not saying
anybody's wrong or right.
I don't know this answer of,
we're trying to set new dispatchable generation,
we have these revenue streams
whether they be through existing or new ancillary services
or some reliability service.
Do we know for certain,
it's just gonna be the existing generation
that moves from pot to pot.
I mean, is there even enough to cover
all of the buckets that ERCOT finally gives us
however many megawatts are gonna buy for ECRS, for non spin.
I mean-- -: That's a great, great point
because they will have to procure those ancillary services,
those dispatchable resources
to meet those specific performance profiles that they need.
And so once that, and that is the priority of the system,
'cause we've got renewables out here,
they are gonna provide low cost power.
So once you procure all those gigawatts of power,
how much is left for you guys to go and procure three years,
one year, one month, six months, one month in advance.
So it's a good question, valid.
-: And my point with that
is from the generation investment side too.
If we're gonna have streams
and the existing generation is gonna play,
and the real-time market, the ancillary service market,
ECRS, at some point, we're probably,
I would hope through all the mechanisms of RDC and ECRS
and whatever other ancillary service/reliability service
if we were to put one out there per SB3,
eventually we're gonna attract some generation needs
to fill those megawatts that ERCOT has said we need.
So that's what I'm trying to come up with,
is I need a view as to what we're gonna need.
-: Sure, I'll give you a quick example.
We've got, depending on exactly
what the winter fuel standard is for winter RNs,
we've got between 10 and 15,000 megawatts
of firm winter in place.
So until our winter ancillary service product
gets above 15,000 megawatts of procurement,
there's gonna be no new investment if that's,
call out the number, don't quote me on it,
but it's in that range, until we get to that number,
there's absolutely no incentive for anybody to invest
in additional winter farming
because by definition is cheaper for the existing asset
to clear that market than spending money on a new asset.
So that's just an example.
It's a fair question, it's an absolutely valid question,
and we need to know that,
but that's all for that example
as a practical way of showing that
if we're going to expect these suite of ancillary services
to solve a 75,000, 80,000 megawatt problem,
or even a 40,000 or 30,000 megawatt problem,
we need to be prepared to procure lots and lots
of ancillary services
and spend our consumer's money on generating assets
that will not be used on a day-to-day basis,
except in scarcity events.
That's a choice we've got to make.
The first step of that is the evaluation process
that you just laid out, which we should pursue.
-: And we have to, per SB3 in my opinion anyway.
And so I guess I'll say to that,
is that, what I'll say to that is,
and that's part of the view we need to get
from ERCOT is how big is this problem, right?
Commissioner McAdams laid out a really good
briefing on what's going on globally
and on the federal level.
But I hear from ERCOT that if they reach a certain threshold
of solar that they'll just curtail it.
So, I mean, are we really needing to have 30, 40,000?
-: I mean, that's fair.
We may need to look at, I mean,
that's a generator side curtailment mechanism
or farming mechanism.
You just reach a certain point of intermittent on the grid
and you say we're gonna curtail it
for a number of reliability reasons
that is a clear signal to the market
that some portion of our dispatch energy
will always be dispatchable.
That's a clear signal that if you put money
in a dispatchable resource in Texas,
it will be utilized and it will generate revenue.
And I'm sure these folks would love
the implementation timeline on that.
So that's an option. -: Okay.
So I didn't mean to veer off
into the broader policy discussion,
but as we were sort of talking about this,
and it just kind of started up some additional thoughts,
but I have one question,
you talked about reps going out of business defaulting.
When there are polar events.
If your rep went out of business and there was a polar event
who acquires typically your rep?
-: If it's an actual polar event,
then the customers get dropped
to the provider of last resort.
In this past year, there were significant volunteers
and I think they all went to voluntary
retail electric providers for the residential customers.
There were some commercial customers,
I think that went to other providers of last resort.
Some of these companies that we're talking about
and otherwise they get transitioned,
more customers, I think then got dropped to polar,
got transitioned
to other retail electric providers right before polar drop.
-: So when a rep goes out of business,
either there's a voluntary mass transition
and there's V reps, right?
Voluntary reps that sign up.
I think it's a yearly process that sign up
to acquire those customers.
And at least based on this past year,
who typically are they the bigger reps?
-: This past year that's the case, yes.
-: Okay.
And if there's a polar event,
is it still the same set of reps?
-: The V reps are for the polar event
for the classes of customers,
which they designate ahead of time
that they're willing to accept through a polar drop.
-: Okay, so it's the same companies
that are V reps and polar, so they're the same companies?
-: There are other companies
that are polars that are not V reps.
-: Yeah, and that's how I understood it, right?
Every year the Commission goes and puts out
some kind of requests for V reps and companies sign up.
And when we had the storm,
a lot of the customers that were mass transition
went to V reps 'cause they had to offer
a market-based plan and that's the better path than a polar,
which might be a little bit of a higher rate,
but maybe not because they're interested in keeping
the customer. -: Right.
-: But I guess what I'm trying to say
or what I'm trying to get to,
it sounds like to me that if there are defaults,
then those customers, at least the residential customers
all go to the bigger affiliated reps.
Is that a fair assessment?
Because I'm trying to assess what Jimmy is saying over here
about all this consolidation going on.
And I'm just wondering where to get more,
if there's more pressure on the independent rep segment.
-: And I think you need to look at not just the ones
that actually went through the polar process,
but those that transitioned otherwise
which there are a lot of them.
-: Those that purchased? -: Yes, okay.
Peter: Good, good question.
Who did you sell to your two reps to?
-: Exelon and Vista
Peter: Gene Taylor's affiliate generators.
-: Right, right. -: Okay, so,
twice that business model seems to have been used to move
an independent retailer out of the independent category
into the Gene Taylor category,
which we despise so much, okay.
-: Mr. Chairman, I wanna be clear
that is not despised so much at all.
It's just a market power issue
if you're gonna start changing
the statutory structure and requiring retail electric--
-: Sure, but it's also a key consideration
to ask this Commission to ensure
the competitiveness of independent unaffiliated retailers.
When the end result of helping
independent retailers flourish
is just shuffling them into the affiliated retailers.
-: I think in a healthy, competitive market,
as long as you have low barriers to entry
and people can continue to work in that market,
there continues to be a downward pressure on prices
from competitive options, as well as innovations
retail electric providers that can come into this market
and are not obligated to own centralized generation
that may have a 30 year depreciable life.
They have a lot more ability to offer some nimble products
in this market and in any competitive market.
There's market consolidation--
-: Competition is the hallmark of this market,
the crown jewel
and that is for the ultimate benefit of the customers
enhancing or protecting business models
just so they can be absorbed or purchased for profit
to go to the affiliated less competitive
Gene Taylors is another matter that we should keep in mind.
-: This is about preserving customer options,
not any particular individual company's business model.
-: Sure, Gene Taylors provide customers options.
Any other questions?
-: I do not, I did invite someone to come down
to share their business siting experience in another market.
And I'd rather have an opportunity to ask
because I asked them to come down
based on some conversations that I had, Garrett.
Thank you for staying all this long.
So, I think this is important.
-: State your name and who you are here with , please.
-: Yes, sir, Garrett Kent
representing commercial metals company
of steel mill in Seguin, Texas.
-: Mr. Kent, we visited a little bit in the last several days
and I thought you had an interesting experience
as you have had steel mill operations and in other markets.
And the reason I think this is important
is because one of the questions we pose
to the stakeholders out there was about
whether or not this proposal, the LSE obligation
would impact business development.
There was a lot of different perspectives on that.
Some say no, some say yes.
And I just like to hear about someone that is actually
in the business of siting businesses, industrial businesses,
that was our specific question.
What has been your experience with an LSE obligation?
-: Yeah, thank you for the opportunity.
One of the biggest things is I wanna start out with.
I'm very sure that I'm in Austin, Texas, not California,
or a different market.
We're a unique market here in ERCOT.
But when we hear things like resource adequacy,
which we experienced in California
or a capacity obligation, our ears definitely perk up.
And we recently scuttled a mill in California.
Part of that is because of some of the costs
we incurred in that market, having the higher costs,
also reliability issues
that we've experienced in California.
We monthly work and we're in that market,
but the last month we melted steel, 20% of our costs
for electricity was in resource adequacy.
That's something that was hard,
but really it's also just the bureaucracy
of working through that and as a consumer,
I have concerns that the best interest for all Texas
consumers is a program,
maybe isn't a program that could affect choice
and possibly in our experience
does not have a history of helping investing
in dispatchable generation.
-: Is that the sole factor
in the management of the California system
that impacts investors? -: No.
There are many, many parts to it,
but it is definitely one of the biggest.
-: Would state intervention and financing power plants
play a role in that
as occurred over the last several years?
Would that dampen investor enthusiasm in California
by the state procuring natural gas plants?
-: Yeah.
-: Well, they read it, they shouldn't have to, if they had--
-: Reliability. -: They did.
I'm saying they did.
-: Right they did
because the construct they had in place wasn't working,
if it wasn't, they wouldn't be trying to meet a shortfall
through ordering generation--
-: Could you tell us in your experience
how long that LSE obligation
had been in place in California?
-: Well, it's a very good question.
So almost three years to today,
we acquired that steel mill from another company.
We took that over and over two years,
we put a lot of manpower,
focused a lot of interests, worked with the right groups,
everything like that to try to make it work.
We had important jobs and important peoples there,
and we could not make it happen.
-: You operate in the ERCOT market?
What are your top two, top three main, I guess,
important aspects of our market as an industrial consumer?
-: Reliability is definitely very important.
Also, yes, cost is going to be important
and making sure that we are using the tools
that are available to us,
whether it's ancillary service or anything else
as smart as possible.
-: I don't have any more questions.
-: All right, and a point of clarification
on those gas plants that were procured,
there's a big part of that is locational
due to transmission being shut down to prevent wildfires.
So it's not a resource adequacy challenge necessarily.
It's a wildfire prevention
and transmission challenge as well.
-: And they've got a lot going on over there that I will say,
but it is extraordinary action
when the Governor sends a proclamation
asking agencies to look at getting more gas
and I don't know if a wildfire would necessarily on its own
dictate the need for more power plants.
So, I mean that they've got a lot going on over there.
-: I know it's hard to understand.
-: Yeah. -: Thank you.
-: Thank you for the time. -: You bet, any other guests?
-: Well, I do, but it's just that
I got a lot of comments out there
that it was interesting some of the dynamics
because there were statements made
that the LSE obligation would have an impact on LSEs.
And as you heard, and through comment
and through, I guess, feedback here today,
those LSEs have different answers.
And I could sit here all day and go through that.
But I think I'd just rather yield my time
so that you can have LCRA.
-: Sure, and you're, of course, welcome
to ask people these questions with your staff.
-: Absolutely, I just think it's important
as we go through this market design process
to have this public conversation,
because we asked for stakeholder comments
and we have a lot on our plate.
And so we limited, we're trying to be as robust as we can
and do this all transparently,
and we asked for comments on a lot of questions
that were limited to sort of specific page limit
and a short turnaround time.
And these are colossal policy issues
and impacts to the market.
And I just wanna make sure that,
with everybody out there
that doesn't have the time to read our comments,
that is not down in the weeds like we are,
that they have an opportunity to hear
all sides of the story, but I'm happy to continue to--
-: Sure, and you're welcome to continue those questions
and aggregate the responses that you and your staff get
and present those
when you put pen to paper for our next next meeting.
-: Sure.
-: All right, we've got, we wanna do--
-: Really quick. -: Sure.
-: Randall, you're up.
(all laugh)
Easiest question in the world,
tell us about your proposal.
-: Sure, no problem.
Randall Stephenson, Chief Commercial Officer LCRA.
This proposal is something that's been worked on
even before the winter storm.
So I wanna make that very loud and clear.
We have been as market participants talking about ways
to adjust market prices,
to reflect the cost affirming load with firm generation.
And we all know what the issue is,
but obviously federal incentives have kind of disrupted
the market dynamics and the volatility in our market.
And so we had worked on with a group,
this idea of resource adequacy adder,
which is really a energy only component,
which is part of the real-time market pricing.
So right now, when you look at what is cleared real time
in your settlement point price,
it's the LMP plus the ORDC ERCOT
plus the real-time online deployment adder.
And this now adds another piece,
which is the resource adequacy adder.
So again, we're trying to just address the issue
about firming the power in a energy only type concept.
The way you would do that is,
when a non firm resources produce
it's affected low carrying capacity,
we've all known that there is not really a value
for that backup power.
So what we're trying to do is create that additional value.
What you do is you look at each type of resources,
effective load carrying capacity,
kind of like what we've talked about in the certificates
for LSEs or the CDRO process.
And you figure out their contribution
to resiliency in real-time.
And the resource adequacy adder
is only paid to firm generators.
And so how it would clear is non firm generator
would clear at a certain market clearing price.
And then there would be an additional adder
in which firm generation would get
based off if they were there to back up power.
So ERCOT is counting on certain amount of renewables
based off their ELCC.
What we do is we would really clear the market,
assuming any generation above that was not available
and see what that additional adder
would have been to the market.
And you can do this after the fact, if you wanted to,
as a settlement piece,
or you could do it through the skid process.
There was a lot of different ways to calculate that piece
and different ideas on how to do that.
But that is in general what we were trying to do,
is really value firm generation
and look at trying to get additional price adder
for that backup power.
-: In your estimation, would implementation of such a plan
be put on hold until after EMS.
Randall: I think, yes.
-: Okay.
-: I'll be very honest,
this is a complicated piece. -: Yeah, price settlement.
-: Yes, and so we definitely
didn't have to get into the settlement engine.
If we wanted to do it through skid,
we'd have to open up EMS, there are different ways
and that's why we kind of parked it on the side,
just because I think there's a longer term
implementation planned for.
-: Is there, we've got several other programs
that have that restraint
that have, I guess, call it duct tape version
that has a watered down version, I guess,
that has been put in place.
And the development has been put on hold until EMS is ready.
Would there be some similar kind of temporary version
that could be implemented more?
-: You could duct tape it (laugh)
and it's still gonna have to impact the settlement systems,
but you don't have to run it through skid.
This could be an after effect, a price adjustment
that would come in and hit your settlement statement.
And then you would,
it's kind of post real-time settlement solution.
-: What type of generation do you expect to deploy
in this world?
Again, is it your combined cycles or is it,
what kind of steel should we expect?
-: I think when you're looking at the firming,
it's an adder for everybody who is thermal or a nuclear,
-: Or just dispatchable. -: Oh dispatchable, period.
It's trying to be technology agnostic on everybody
to provide this, that don't have intermittent base,
but a battery could also get this as well.
Peter: Yup, the key tech neutral performance base
is a key element of all of these.
-: Correct, correct.
Peter: I think, it's a good question
to ask what to expect,
but this, with many of the things we're considering,
doesn't necessarily have to be either,
or I'd be very happy with all of the above.
And I think that would provide all of the above works
just fine.
-: Sure, and we tried to come up with this idea
based off a lot of work
with a lot of the folks in this room,
but also, we had talked earlier about
two different skid stacks and a $20 floor,
and this is a little more elegant.
I think this is more based off
some of the economic dispatch models that we have
already in our cot based off the way
we're running the LRDC adders as well as this new adder.
-: Bill's kind of nodding his head.
I mean, this is competing plans here.
Is it workable?
(all laugh)
Bill: If I hadn't got it, I would now have a question.
(all laugh)
-: Try to dispute.
Bill: That's another way to solve the problem, I think.
-: Here's is a more elegant--
Bill: I think there's a more efficient way to do it,
but again, I think all options is validated.
-: All right, I'm gonna come up with more questions for this.
-: I don't have any at this time,
but I think as we have new proposals like this,
we can have Randall look at him too, right?
We should have him study all proposals.
-: Not all proposals.
-: Well, yeah, but I would like to see more robust analysis
of variety of proposals and this is one that we can--
-: But again, this lives within the real time.
-: Correct. -: Yeah.
-: And when is it paid?
-: It's after the fact.
-: I mean, on what performance basis is it,
does it rely on scarcity to pay out, of ORDC.
-: It relies on what is needed
for firm generation in that interval.
So it's really based on what's needed
for firm generation in that interval.
Jimmy: In that interval.
-: It's fair to say, it's does not rely on scarcity to--
-: No. -: Pay off.
-: Specializes on peak net load, sounds like--
-: Partly yes, I'd agree.
-: Well, and that's the next,
yes that's the next question is
from out a third-party investor,
do you all have a captive right base
and a different kind of investment criteria
than the IOU's of the world,
but I guess put your independent financer hat on.
How do you think this would be viewed
versus like the increasing I already see
which we know won't drive new generation?
How does this--
-: I would put it in the bucket like the ORDC,
it's not gonna drive new generation?
I don't think there's,
it's very hard, I think we just did a backcast of this
and try to like re-look at the last year
and how much more money would have add to the market.
And it was between one,
one and a half billion dollars of total cost.
And so I don't know if that adds enough new generation
to be quite honest, it helps.
It definitely provides incentives to get there
and a ability to back up the power.
But I do think the big benefit of this proposal
is also helping the existing generation stay online.
-: A little point and bounce this off of you,
as solar increases,
and again, is that peak net load margin increases
that's more money under this concept,
Randall: It is, correct.
-: Get enhances with the degree of variability.
-: Yeah, and I would think this,
would be utilized more frequently than I already see.
Randall: Yes, I would sell that a thousand--
-: Drive more gender, new generation,
we know we needed a various performing for more standards,
prefer to have all of the above.
So certainly would be interested in scrubbing this more,
but would also like to scrub it
while keeping in mind, how can we adjust it
and tweak it to move more towards that new generation,
not just keeping the cash for clunkers only.
-: Try this on for size, sir,
just because we're, again,
to the operational scenario of the duck curve,
but also the Blue Sky event,
which are what you wanna solve for, again,
that's kind of a nighttime phenomenon, right?
Wind drops off at night, all of a sudden,
in a 30 gig solar environment,
this would track those reliable units, I'm sorry,
somebody is gonna catch this dispatchable units,
would track their performance at night
to counter the variability of the wind at that point.
So it would cover the gap
and it would pay them to cover that gap.
-: Yeah, I mean, I support all of that.
The fundamental question is,
does it clear the threshold of meeting investor criteria
for new generation and that's what we've got to figure out.
-: No way.
-: No way? Okay.
-: I hope--
-: I hope's not a strategy.
-: I understand that.
-: Okay.
-: I feel like we're at a sports book in Vegas.
(all laughing)
-: Okay, we can go on record
saying this in no way will drive new generations.
Randall: No way, I wouldn't say that.
-: No, you just said, "No way."
-: No, you said, "Does it create financeable power plants,
steel on the ground?"
And I don't think this by itself,
I think that all of these strategies together,
even together are challenging our ability
for banks to finance power plants.
They don't like the wind.
They don't like--
-: They like the tax credits, they finance a lot of that.
-: Nobody's saying, they don't like fighting the wind
and they don't like fighting the solar.
-: It's too much risk.
So, and I think somebody, whoever,
I don't remember who it was who to talk to me,
that they built a plant in Illinois
funding the same issues, and it took them 14 banks,
they syndicate 14 banks to finance a power plant
because nobody wanted to bear the risk.
Peter: So what are we gonna do?
-: I'm not saying the words.
(all laugh)
-: You're gonna have to take that to the legislature.
(all laughing)
You got a lot to think about.
-: You can continue scrubbing.
-: You scrub all you want,
but we have a very real problem that's right here right now.
So we either need to saddle up and head to the legislature
or figure out some other way to finally to screw it up.
-: And I do think multiple solutions
that have been discussed today really do get you there
and help you justify getting the financing you need
to build a new power plant, but it's not just,
like there's no one silver bullet here, right?
It's gotta be a lot of these multiple solutions that come in
and help see this value.
The reason the resource adequacy adder is a nice companion
to the ancillary service piece too.
You're getting on your energy side
as well as your ancillary service side.
-: Prevent retirements of existing plans.
-: Yes, and hopefully enhance
when we see more and more solar penetration
and two, three years that add
or should continue to increase.
-: Thank you. -: Thank you.
-: All right.
-: By the way, I'd love for you
to build a new power plant on your balance sheet
Mr Chairman. -: I'm a public servant.
It's not much of a balance sheet.
I can get you a little gas station windmill.
Alright, thank you again to all our participants today
and for the thoughtful comments that we received.
Clearly we still have a lot of work to do.
I'll ask each of your offices,
as I said earlier, to put pen to paper
as we go through the next week or two
ahead of the next work session
on details of what ECRS should look like.
I think the technical details are pretty well ironed out,
the cost allocation is the big question there.
Winter ancillary services,
the fuel standard duration, structure
and quantity of winter ancillary services to be procured
details on ERS.
We know what the deployment looks like.
What should the procurement look like by megawatt,
by dollar, if by megawatt or by dollar,
what metrics should we use
to set that amount for ERS procurement?
And then finally,
any thoughts on affirming mechanisms?
Obviously everyone's got a good sense of the pros and cons
or initial sense of the pros and cons of the LSE obligation.
I'll continue to refine that,
and of course, look, would welcome
any suggestions on actually how to make it work.
And of course,
if any of you want to refine the reliability adder,
please include that
in your draft straw man or the straw man.
And finally, if you want to flush--
-: Gas energy credits final.
-: Yup, the gas energy credit, what that would look like.
-: Okay.
-: If it's credits, if it's curtailment,
or any version thereof,
and we'll coordinate with each of your individual offices
to continue to flush that out.
As we know, we've got a big challenge.
As we've seen last spring, this summer, this fall,
late October, the problem is here, it's is here now.
It's a big challenge and it's gonna take big solutions.
Thank you all for participating.
-: Chairman Lake, if I may real quick,
can I assign myself something to add to the blueprint?
-: Yeah.
-: So aside from affirming requirement
I'd really like to continue
to look for a strategic reliability service and--
-: You are welcome to come up with any concrete ideas
that you can come up with.
-: Okay, thank you.
-: I look forward to hearing them.
All right there being no further business,
this meeting of the Public Utility Commission of Texas
is here by adjourned.
(gavel banging)