Hydroelectric asset management involves systematic categorization of projects (refurbishments, redevelopments, rehabilitations, and expansions) based on asset condition and lifecycle, with refurbishments and overhauls being OMA-type projects while redevelopments address populations of deteriorated assets. Asset condition assessment uses health monitoring systems to evaluate equipment status, with replacement decisions considering factors like concealed conditions and project risk mitigation rather than solely current condition ratings. Capital planning employs a prioritization framework using tools like Copper Leaf to score potential investments based on net benefit calculations, balancing allocated projects with approved business cases against unallocated portfolio investments. The framework integrates operational metrics such as availability and equivalent forced outage rates (E4) to inform production forecasting and variance account calculations, ensuring capital expenditures align with strategic objectives of maintaining 1500 MW of regulated hydroelectric capacity while adding approximately 50 MW incrementally over the planning horizon.
Hybrid Technical Conference - Ontario Power Generation Inc. - OEB File No. EB-2025-0297Añadido:
Uh, can we just ask uh who will be uh sort of doing the introductions and leading off and then just to see the camera pan to them because I've yet to see that.
>> Good morning, >> Diana Coban for OPG Council.
>> Yeah, we're not having the Oh, there we go.
>> Oh, could you just say one more thing?
>> Yep.
>> Morning.
>> Now, can I just ask >> Thank you very much. Uh, Miss Coan, will you be primarily speaking for your party or will there be others that you anticipate?
>> I have um Miss Saba Zade here with me, VP of regulatory affairs, and she may sitting right.
>> All right. Could I just have the spelling of your name?
>> Sure. First name is Sabah. A B like Bob A. Last name is Zad. Z A D like David. E H.
All right. And just one more moment.
Sorry for this. One moment.
I just need to add your name. One moment.
One moment.
Just adding your name.
Okay, one more moment. Sorry for play.
All right. Thank you very much. Sorry for the delay. I have that added. Thank you very much.
>> Okay. Are you ready to go, Christopher?
>> Yes, sir.
>> Okay, great. Um, with that, I think we will get started. Good morning, everyone.
Uh welcome to the technical conference for EB202720 uh31 which is the uh OPG payment amounts proceeding. Uh my name is Michael Miller. I'm council for board staff. Uh and even though I'm on the DAS, I'm only up here because this is where all the buttons are. I am a simple public servant and I'm not a member of the panel hearing this case, but I will be your master of ceremonies for today. Um, I'm joined by my co-consel Ian Richler.
And we also have the case managers, uh, Thomas Midnight and Jeffrey Sauer. There are a number of other staffers who will be in and out through the proceeding.
Um, some of whom are here now, but I don't think I'll introduce them all now because some are here and some are not, but when they're asking questions, um, they will introduce themselves. Uh, so everyone knows who they are. We have a very busy, uh, schedule. Um so as you know one of the things I'll be doing is uh encouraging people to stick to the time estimates that they've given to me but um it does look like we will comfortably fit within time that we have allotted as long as we all uh do our part to work efficiently.
Um, we are going to move to uh appearances in a moment, but before we do that, could I turn to Miss Dazy for our land acknowledgement?
>> The Ontario Energy Board acknowledges that our headquarters in Toronto is located on the traditional territory of many nations, including the Missagas of the Credit, the Ashinabek, the Chipua, the Harosani, and the Wendat people.
This area is now home to many diverse First Nations, Inui and Matei. We also acknowledge that Toronto is covered by Treaty 13 with the Missagas of the Credit. We are grateful for the opportunity to gather and work on these lands and recognize our shared responsibility to support and be good stewards of them.
>> Thank you, Miss Senzy. Uh unless there are any preliminary matters that we need to address, I suppose I should mention folks will have seen procedural order number seven yesterday which um asks that the parties and OEB staff get together to discuss a possible schedule for uh maybe an additional technical conference with certain experts. What I'm proposing we do and I had a very quick chat with Miss Coban this morning is we start with some offline discussions about that perhaps on our break or over lunch or what have you. Uh and then when we arrive at some consensus hopefully we'll be able to address that directly on the record because you will have seen that the panel uh was going to find out about this through reviewing the transcripts.
Um so everyone will have seen that but I think we can deal with that later today or in the days to come.
Uh so unless there's anything further I propose to do appearances and I will start with uh you Miss Coban.
>> Good morning Daliana Coban council for the applicants. Um I will be sitting here with the hydroelect electric panel and then I'll be joined by my colleagues uh for the remaining panels Mr. Kaiser and Mr. Meyers and Mr. Turnberg. With me today I have uh Sabah Zadeay, VP of regulatory affairs at OPG. Um and Mr. Miller, is this a good time to introduce the panel to the room?
>> Yeah, why don't we do that?
>> Perfect. Thank you. I'll pass it over to you, Mr. Pender, to introduce and your colleagues. Thank you.
Uh good morning.
>> Good morning. Uh my name is Nick Panda, senior vice president of renewable generation and energy markets. I'll hand over to my colleague, Mr. Sikstrom.
>> Uh I'm Matt Srom. I'm a project director for our renewable generation major project group.
>> Good morning. My name is Nicole Faber.
I'm the vice president of regal operation.
>> Good morning. I'm Mark Chidiak. I am vice president of markets.
>> Good morning. I'm Melissa Hannon, vice president of FIN.
>> Morning. Matthew Kirk, director of regulatory affairs.
>> I'll just ask the court reporter, did you get all the spellings for that or do you already have the names? Do you need anything further from the uh witness panel to identify them? We are trying to get um some actual name tags down which hopefully will help, but just want to make sure you have the spellings of the names.
I do have the spellings of the names. It would be just helpful for the witnesses to use to mention who's speaking at the beginning just to remind me for the first while, please.
>> Great. Thank you very much. Okay. Back to you, Miss Cobin. Or are you finished?
>> All done. Thank you.
>> Okay. Thank you. Uh we'll go around the room for members of staff. I don't think you need to introduce yourselves right now. We'll do that um when you are u when you're it's your turn for questioning, but I'll start with you, Mr. Rubenstein.
>> Uh good morning. Mark Rubenstein, Council for School Energy Coalition, and I'll be joined throughout the technical conference by SEC consultant Jane Scott and also uh SE Council J Shepard.
>> Uh thank you, Mr. Rubenstein, and good morning, Miss Scott. Uh Mr. Bonigoro.
>> Uh good morning, Michael Bonigo. I'm council with the Consumers Council of Canada. Uh also joining me throughout the tech conference and the proceeding will be Lori Gluck, consultant for Consumers Council Canada.
>> Uh thank you very much. Is there anyone else in the room?
Okay, not seeing. Normally, I have a list of people and I do a roll call for those who are online, but I'm actually not sure who's here today. So, this may be a little bit of a free-for-all. I I'm going to start with people I actually see on the screen. So, uh Mr. Walker, could I turn to you?
>> Good morning, Mr. Miller. It's Scott Walker for AAPA.
>> Uh good morning. Uh Mr. Mloud.
>> Good morning. It's Mike McCloud for the Quinty Manufacturers Association.
>> Good morning. Uh Mr. Rosenluth.
>> Good morning. Dan Rosenluth, council for the Power Workers Union. Uh and I'm joined somewhere here by uh our colleague Bayou Cadane. I will be in and out during the proceedings, but obviously we'll be careful to ensure I'm here at my scheduled times.
>> Great. Thank you. And do keep um we have circulated the schedule as people will have seen that is of course subject to change. Times may press occasionally get longer here and there. So uh don't assume everything in the schedule is set in stone. It is re-released at the end of every day. Uh but you know if it says 3:40 don't assume it'll be exactly uh 3:40. Uh but thank you. Uh good morning.
Welcome uh Mr. Boille. Um, good morning, uh, Colin Bole and I'm here on behalf of WTFN Investments Holdings LP.
>> Good morning, uh, Miss Grace.
>> Good morning. Um, Shelley Grace, consultant for the Association of Major Power Consumers in Ontario.
>> Mr. Leeni.
>> Good morning. Uh, my name is Tom Leani.
I'm an independent consultant representing two interveners, the coalition of concerned manufacturers and businesses of Canada, which is a group of more than 400 manufacturers and businesses mainly located in Ontario. I also represent Energy Probe Research Foundation, a public interest group that has been active in OB proceedings since the 1980s.
I do not plan to ask any questions during a technical conference because I expect that other interviewers will cover any areas that are concerned to CCNPC and NG probe. Thank you.
>> Thank you, Mr. Leeni. Uh, Mr. Lee, >> good morning. Uh, Clement Lee, uh, I'm here on behalf of Building Owners and Managers Association of Toronto.
>> Uh, thank you, Mr. Lee. Could I ask, uh, folks who have already introduced themselves to go off camera that way people who haven't gone yet will pop up and I can see uh, who they are. Uh, thanks very much, Mr. Garner.
>> Mark Garner. I'm I am consultant for the Vulnerable Energy Consumer Coalition, ORBEC. Thank you. Good morning. Uh, Mr. Pinto, >> I'm Keith Pinto and by an independent intervenor.
>> Mr. Wulmer.
>> Good morning, Daniel Bulmer. Council for Manokei Corp.
>> Good morning. I do not see anyone else on my screen. Is there anyone else who has joined us virtually who wishes to make an appear?
>> Uh, Colin Fraser here for the society.
Um, for some reason my camera won't turn on. I'm not sure. So, I'll work on that.
Uh, I'll also be joined by Bowden Dooma and we'll be sort of trading on and off over the the uh term of the uh the technical conference.
>> Great. Good morning, Mr. Fraser. Anyone else?
Okay, hearing uh no more appearances, um I can turn to you again, Miss Coban. Um, did you wish to introduce your witnesses again or is there any uh preliminary remarks or can we get straight to the questions?
>> Let's get right to it.
>> Efficiency. I love it. Okay, Mr. Walker, you were the lucky luckily lucky person who was volunte. So, over to you.
>> Well, thank you. Good morning, everyone.
My name is Scott Walker and I'm a WAP consultant in this very complex application. Uh, some of you may not know this, but hydraulic generation holds a very special place in my technical heart. Having spent some of my early years in hands-on exposure to the Ottawa River assets and in having had executive management oversight of the rank and generating station while she was still a functioning generating facility, which was before they turned her into a museum, which admittedly I still find quite unsettling. Uh so I do want to thank panel one for being here and for pro providing us with the opportunity to more fully and openly explore some of the issues. However, in rereading the evidence in numerous of your IRS these last few days, I've somehow managed to ask the majority of the answer the majority of the questions that I had originally intended you. So therefore, I should be well under my time aotment this morning. Um, so if I could just beg your indulgence to uh better help me understand a few items that are not yet fully aligning in my mind. And if I could ask that uh exhibit A1, tab 2, scheduled two, page four of 10 be brought up for reference, please.
starting there at uh line 9.13.
Uh yeah, maybe if you could bring that up so the whole thing is shown.
Awesome.
Thank you.
So there's a lot of verbiage here and so broadly are you effectively saying in this paragraph that you want to be compensated based on the difference between your actual five minute hydraulic production in real time versus the committed day ahead forecast at the real time locationational market price. Do I have that correct?
Mr. Walker, could you please repeat the question?
>> Fair enough.
Okay. Are are you effectively saying that you expect to be compensated based on the difference between your actual five minute hydraulic production versus what you've pre-committed in the day ahead forecast at the real time locationational market The intent is for OPG to be paid for It's real time production in in the market. This paragraph describes the interaction between the day ahead and real-time interaction. However, OPG's proposal is to be paid on its real-time production in the >> all of it at the real time location marginal price.
>> That's incorrect. It would be at OPG's prescribed amount for regulated hydro.
>> Okay. So you're looking to be basically compensated for your full production. Is that correct?
>> I'm not sure what you mean by full production, but we are looking compens for our our real-time production in the market.
>> Okay. I I'm just because the last part of that paragraph says multiplied by the real-time locationational marginal price.
Why is that important?
that refers to an adjustment required in the market that was introduced by the ISO's market renewal program where there could be differences in either production or payments from the day ahead and the real time and this describes the adjustment to revenues to reflect that OPG will be paid based on its realtime production >> as would be different from the prescribed regulated price. Do I have that right?
>> No, it would be at the well the adjustment is not at the prescribed regulated price but the net payment to OPG would be at the prescribed regulated price.
>> Okay. So you are currently being compensated for all production at the regulated price. That is that correct?
>> At a high level, yes.
>> Okay.
>> Mr. Walker, can I just add one item?
This is Matthew Kirk speaking. Uh if we can just scroll up a tiny bit. I want to make sure we're looking at the page the same way.
So in in paragraph 12 there, this is what's establishing the uh base regulated payment amount that the that we're proposing the regulated hydro facilities will receive. And then what you're discussing with Mr. Chittiaak is the hydro incentive mechanism adjustment. Just want to make sure that we're understanding that point.
>> Oh. Oh. Okay. Okay. So, this is in sorry, this is incentive based compensation that's in excess of what you've forecasted on a day- ahead basis.
Do I have that right?
Mr. Walker, it's uh Mark Chidiak here again. Um so yes, this is in reference to the hydroelectric incentive mechanism which is described in evidence in uh E121.
Um so there is an incentive for OPG to earn incremental revenues in the market and there are two incentive one is a day ahead incentive and one is a incentive >> and it can actually the incentive can can go either way. So it could be a benefit to OPG or it could be a cost to OPG if assets are not um optimized appropriately.
>> Yeah was it was a question I had. Thank you for answering that. Uh so would this additional inreal time market revenue be collected as a separate revenue possibly requiring a new IEO tracking code or is it just like a gross adjustment to your monthly GA OEM payments?
>> Uh it is paid out as a a separate code by the ISO.
>> Okay. Thank you.
I I I mean, you know, it's fair to fair to say that you reasonably expect to be compensated for asset performance and productivity in excess of your day ahead commitments.
So, the the the challenge I'm having is how I reconcile these extra performance earnings against your ask for an X factor in the custom price cap IR equation.
I I'm I'm I'm sorry. I'd be more pointed. Is there not the potential for double counting the performance while this realtime market um incentive is in play?
>> Uh in ter in terms of the X factor, Mr. Walker, and sorry, this is Matthew Kirk speaking again. Um the proposal is in exhibit A132, section two.3.2.
Sorry, that's page 11. Uh Lori And it's it's obviously a long section.
I won't go into great detail unless you'd like Mr. Walker of course. Um but there's two components of the X factor um based on studies conducted by London Economics.
um one is a benchmarking study and the other is a uh total factor productivity study.
Um and the results of that study are what determines the uh the X factor that we've proposed uh to include as part of our rate setting mechanism.
>> Right. And and as as you're showing there on the screen, your productivity factor is effectively zero. Is that because of this additional revenue you're earning in the real-time market?
Uh no it is is not driven by the revenue. Um productivity specifically is based on a TFP study that um is industry based.
So um generally speaking when you see like the negative.4 four or negative.1% there. It's suggesting that more inputs are required to get to the same level of output. Um, and it's it's it's fully in the the study documentation from LEI, but it it looks at not just OPG, but the hydroelectric industry as a whole.
>> Okay. Thank you. I I mean, straight up, I do see the potential here for double counting. Um I'm not sure how to reconcile that. So fair enough. Uh so my next couple of questions are relatively straightforward and just for context, my client is very concerned not only by the total cost of the commodity rate but also they have a very profound uh interest in in how it's being allocated.
Um but does it matter to OPG how the IEO allocates your monthly remittances between the OEM and the global adjustment for example?
Can you can you clarify what you mean matter to?
>> I I I mean you just get a remittance advice at the end of the month from the ISO. Does it really matter to you how much revenue is collected from the real mark real time market versus the global adjustment?
while also acting as a load as exposure has exposure in the market to the global adjustment but from a revenue perspective how we are paid I I don't think it really matters from what bucket it's coming from >> okay I think I know the answer to this but um nothing about the IRM price cap mechanism that you're suggesting is really going to change how the global adjustment payments are made. So, i.e. the difference between your OEM revenue as made up by the difference in the in the global adjustment, you know, factoring in your production of course.
Is is that is that a fair statement?
>> That is a fair statement, but I will note that hydro has a very small impact to the global adjustment.
Uh, understood. Understood. Okay. Well, that's uh that's terrific. Those are all my questions. Thank you, panel. Thank you, Mr. Miller.
>> Thank you, Mr. Walker. Um, we're going to turn to staff, but before we do, uh, Mr. Bole, are you there? There was, um, something you wish to, um, address.
>> Uh, good morning, Mr. Miller. Um, WTFN filed a letter yesterday with written questions that I'm hoping to get marked as an undertaking in this proceeding. Um that is in in anticipation of avoiding my uh oral questioning. So >> Miss Coban, did you receive that letter and um are you prepared to take an undertaking?
>> Yes, we are. Thank you.
>> Okay. So, Mr. Bole, that so this is undertaking JT1.1 and it is um um questions filed by WTFN on uh May 26th.
>> Correct. Yeah.
>> Okay. Is that sufficient, Miss Cob?
Yes.
>> Okay, great. So, that's JT 1.1. Mr. Wulmer, did you file something as well?
>> Yes. Thank you. Um, Minoi filed a similar letter with a list of questions on last Thursday, I believe. We also like that entered as undertaking.
>> Miss Gman.
>> Yes, that's it.
>> Okay, great. So, that's uh same thing for Manogi uh JT1.2.
>> Uh, is that all Mr. Boil and Bulmer?
>> That's it for me. Yes. Okay, thank you.
We're going to move to some questions from OEB staff. We have a number of staffers who will be asking questions.
Up first, we have Mr. Sincar, who I see on the screen.
Thank you. My name is Chris Sincar and my first set of questions relate to the SPG variance account and my first question specifically relates to E1 staff 148.
And in that IR response, OPG noted under identical marketing conditions, it is not necessarily the case that a CMC payment in the legacy market would map to an instance of local SPG spill in the renewed market.
OEB staff had intended the questions in E1 staff 148 to be more precise in asking about only constrained off CMC CMS payments rather than CMS payments in general which also includes on and we also intended to exclude CMC's pay to nuclear does limiting it to only constrained off CMC payments and also limiting those payments to base load hydroelect electric change OPG's response in relation to mapping to local SPD related spill.
>> No, it would not change our response. it would be consistent as in the legacy market there was both a constrained and uncon schedule where we're able to decipher the the difference between the two in the renewed market that mechanism no longer exists. So although there would be likely significant overlap we can't do a exact onetoone comparison between two.
>> Okay. Um, under identical market conditions, can OPG please explain under what circumstances OPG would be compensated for local spill in the in the renewed market, but an OPG hydroelectric generator would not have received a constrained off payment in the legacy market since, as you noted, they would not necessarily map So, sorry, just to clarify, are you asking for examples of in the renewed market versus the legacy market of constrained off events?
>> Yeah. Well, um, in the renewed market, uh, you would be uh compensated for local SPG and uh so what cases would that happen but you in if it was a legacy market you would not receive constrained off payment >> so yes I was looking for examples >> well the the the intent I'm not exactly clear on your line of questioning here, but the intent of the revisions of the SBGVA for EB2023 was to capture both global and and local spill events.
So what was previously recovered as CMS's in the legacy market will now be recovered through the SPGVA.
only a subset of those constrained off events would be recovered through the SB SPGVA.
>> Yeah, local. Yeah, it was excluded before and now it's excluded.
Um okay. Um I have an undertaking request. Um as noted, the questions were intended to be more precise. Could OPG please undertake to revise chart one CMS payments received in amounts recorded in SPGVA in E1 staff 148 by replacing CMS payments with only constrained offium CMS payments and limit it to OPG's hydroelect electric base load facilities. Please.
>> Yes, we can we can take that undertaking. So, just to confirm, you want to update the in chart one the the CMSC row just to show um CMSC off events for regulated hydro.
>> Yes, please.
>> We can do that.
>> Thank you.
>> That's uh JT 1.3.
Okay. Uh, my next SPG variance account related questions will focus on E1 staff 149.
However, I will also be making reference to E1 ED011, but only for comparison purposes.
Anyone staff 149 OPG notes change in methodology to reflect renewed market not result in overcompensation in relation to SPGA variance account entries during the legacy market years. It was determined that the appropriate compensation was determined using a method methodology that involved SPG due to market constraints being one of the four categories that OPG intentionally excluded from the SPG variance account as explained in the application.
However, OPG notes that SPG due to market constraints is now included as part of the revised methodology used to determine the variance account entries.
If OPG was being appropriately compensated for SPG with market constraints excluded in the legacy market years, can you please clarify how additional SPG BA entries associated with including market constraints under the RA under the RAVI methodology does not result in incremental compensation for SPG.
So, I touched on this a little bit earlier response, but with the change to the renewed market, OPG's proposal is to recover both global and local spill through the SPGVA.
Local spill in the legacy market was recovered through CMSC's or congestion and settlement management credits.
So there was a recovery mechanism for those amounts through the ISO market previously but that no longer exists in the renewed market.
Okay. Thank you.
OPG also noted in E1 staff 149 that if the legacy market ran in parallel with the renewed market, OPG expects a meaningful overlap of instances when it experiences local spill and the presence of market constraints.
However, given the multitude of sources of differences between unconstrained and constrained run, OPG does not believe that the two volume amounts will be equal.
Would OPG be able to quantify meaningful overlap? for example, would that be over 95% or some other percentage as OB staff is uncertain how material those sources of differences between unconstrained and constrained are unfortunately we're not able to to quantify that amount without having access the ISO's dispatch algorithm.
>> Okay.
OB staff also requested historic analysis related to breaking down the volume still due to four categories that were excluded from SBGVA entries. Water conveyance constraints, production capability, market constraints, contractual obligations.
In E1 staff 149, OPG provided a table with historical spill amounts by category for the years 2019 to 2023.
In OPG's response to E1 ED011, OPG provided total foregone production due to SPG along with SPGVA entries for 2016 to 2025.
So one said it was the 2023 and the other was the 2025.
Given OPG did not provide spill for the four categories for 2024 and 225 2025.
Can you please confirm they were excluded from the SPDA entries in those years?
Yes, I can confirm as per the methodologies they would haveuded for 2024 and 2025. But I will caveat that in 2025 on May 1st, the market renewal program went live and post May 1st there is no longer um market constraints are no longer removed from the uh spill amounts because they are no longer quantifiable in market.
Okay, I have another undertaking request. Um, is OPG able to expand the table in E1 staff 149 with the four excluded categories to align with the years in the chart in E1 ED011 for the years 2016 and 2025 and also add a new row with total foregone production that includes the spill amounts for those or excluded categories.
>> So just to confirm, you're looking to extend the table to 2024 and 2025 for those four categories.
>> Yeah. to match the same years from 2016 to 2025 that were reflected in E1 ED011.
>> Yeah, we can take that on a on a basis.
>> We'll call that JT1.4.
I actually can't see the evidence reference here. So, um Mr. Sincar or would the witness just uh please repeat what the undertaking is for? Okay.
>> It's to um update the chart one and E1 staff 149 to include 2024 and 2025 >> and go back to 2016.
>> Sorry. And going back to 2016.
>> Okay, that's JT 1.4. Thank you.
>> And one more question. Now that market prices now include congestion in the renewed market.
When congestion is negative, that be an indicator of local SPG spill.
>> Yes, it could be a potential indicator of local SPG spill.
>> Thank you.
Okay, my next set of questions, uh, I'm moving on from SPG. Uh, and my next set of questions relate to the HIMYM and the removal of the revenue sharing above the threshold.
And I'll be uh referencing E1 staff 146.
In that OPG response to B1 staff 146, OPG confirmed changing the designation of the PGS to energy storage facility would essentially result in implementation of option one OPG's SPG study since both would result in the exemption from transmission network service charges.
OPG also indicated that option one provided the strongest incentive to time production.
OB staff asked in E1 staff 46 146. The PGS was treated as an energy storage facility but option three in SPG study eliminating HIM revenue sharing above threshold still provided incremental incentive for OPG time shift production.
Before I get into my specific questions, can OPG please first confirm that the PGS is no longer paying transmission rates due to the EB 2022 0325 decision which exempted energy storage facilities from paying transmission charges.
That is correct.
>> And does OPG agree that if two options were implemented that are intended to achieve the same outcome, the benefit associated with the second option that is implemented would be lower than it would be as a standalone option.
For example, if OPG got the GRC exemption under option two in the SPGA study and subsequently got the variable low charges exemption under option one in that study, OPG agree that the benefits associated with option one would be lower than those currently reflected in the study that was filed.
Sorry, I was I had a hard time following that that line of question. Can you please repeat the question?
>> Okay. Say OPG got the GRC exemption under option two in the study and subsequently got the variable load charge exemption under option one in the same study. Would OPG agree that the benefits associated with option one that was subsequently implemented would be lower than the benefits reflected in the SPG study that was filed.
So you're asking if we got the GRC exemption which is option two and then applied option one which is the load charge exemption if that benefit would be lower.
>> Yeah. If that benefit would be lower then it would be as a standalone option in the study that was filed.
>> No that if you can combine the two the benefit would be greater and that was that was >> it would be additive.
>> You just add up the uh not directly additive but the benefit um increases >> but it would be lower right than that this second option that's implemented would not realize the same level of benefits that you reflected in the study is my question since you've achieved some of those benefits with the other option >> I I I wouldn't want Uh so I I don't want to speculate on results without running through the modeling and and understanding your question in more detail.
Okay. Um staff asked if eliminating HIM revenue sharing above the threshold still provided an incremental incentive, how material would it be where the PGS6 is exempt from transmission charges which we now know they are? OPG's response noted it would provide an additional incentive and added OPG cannot conclude how material that additional incentive would be.
The question is, is OPG able to advise approximately how much of the time shifting of production that elimination of HIM revenue sharing would have incentives as a standalone option would already be realized due to the PGS avoiding network service charges due to the storage designation.
As OPG is as OB staff assumes that there is a limit in terms of how much OPG can time shift.
So is your question is there is there an upper limit on how much the PGS can time shift?
I guess is um like how much of the time shifting of production that revenue sharing above the threshold would have incent like in the study uh it didn't reflect OPG storage being exempt from paying transmission rates and that was essentially option one.
So if the elimination of the revenue sharing was I guess to what extent would the shifting of uh production be reduced that would be associated with him revenue sharing above the threshold.
as a result of EGS being exempt now the network service.
>> So as as as we've commented in the in the IR response, we're not able to to quantify and measure the benefit. the HIM sharing results in essentially it dilutes the incentive because it creates a larger economic barrier from utilization of the PGS and that could be um exemplified in the SVGBA study. So, if we could pull up exhibit E121, attachment one, page 21 of 36 Thank you Lori. So chart nine you can see in both scenarios the required price spread to utilize the PGS. So in scenario one which assumes 50% sharing above the threshold that would require a price spread between the on peak and off peak of $14.90.
And in a no him sharing scenario, that spread is only $8.20. So almost 80% lower than the no sharing scenario, which would result in incremental utilization of the PGS if we had not shared um the HIM revenues above the threshold.
>> Okay. Thank you.
Um given OPG's finding in the SPGVA study that elimination of variable load charges under option one would increase the price spread required to economically cycle the PGS and allow the PGS to operate in pump mode at all hours of the day.
How does OPG expect its hem revenue forecast and SPG variance account balance to change from what was provided in the pre-filed evidence given that PGS is no longer paying transmission charges may represent the variable represent the bulk of the variable load charges under option one.
So we we have not updated our analysis to demonstrate the impact of the energy storage designation of the PGS but I would expect the results would be similar similar to the option one that was provided in the uh SBG study um which is included in um chart two on page 11 of 36 in the same attachment.
So it would be essentially the same as option one.
>> Not ex I think a little bit lower because we have not excluded all load charges um with the designation of the PGS. It only eliminates the network service charge which is about twothirds of the load charges. There's still ISO administrative charges that we we will incur. But I think directionally the results would be similar and but a bit lower than what's described here in chart two.
Uh can you um please undertake to redo that analysis reflecting uh like I guess reality now with the um with the PGS no longer paying transmission charges.
>> Mr. care uh sincare I that sounds like a an ownorous analysis to undertake within the context of this process. Um so at this time we're not prepared to do that.
>> Okay.
Okay. Well basically reflect option one then or consider it be essentially the same as option one.
My final question is related to HIM revenues and I will be referring to uh G1 staff 242 and G1 CCC096.
In G1 CC 096, OPG included a table setting out actual HIM revenues for 2025. you're able to conclude include actual revenues to replace the forecast in the application.
Actual revenues increased by over $20 million to 49.7 million in 2025 compared to 2024.
That followed him revenue him revenues increasing by close to 15 million the previous year.
It's therefore now two consecutive years of significant increases, a larger increase in 2025.
Can OPG please explain the key factors contributing to those significant increases in him in HIM revenues over the last two years after many years of being flat and the substantial difference from OPG's forecast for 2025 which was $39.2 $2 million lower at 10.5 million.
So we we endeavored to respond to that question in staff 242 part A in terms of how volatility drives up HIM revenues and I would say 2024 and especially 2025 were analogous years in terms of weather. So we saw in 2025 a very hot summer followed by a cold winter and that drove up quite a bit of volatility in the market. So that's generally what resulted in the higher HIM revenues years. But again, if you look in the chart in uh CCC 96 uh chart one, for the most part from 2016 to 20 uh 2023, our revenues were below 20 million. So 2024 and 2025 were really standout years largely driven by of normal weather. And from a forecast perspective, our forecast for the HIM is based on weather normal conditions, which which is why you might see a more tempered forecast. As well, we assume that the 3,000 megawatts of battery storage assets coming online in the ISO market by 208 will significantly reduce price volatility in the Ontario market, which will limit our ability to earn incre incremental HIM revenue.
Isn't it much of that storage already in operation like Onidita? I think you included Onita in that.
>> Uh, correct. Onidita is a 300 megawatt facility and there's 3,000 megawws coming online. So by the end of 25 there was maybe 300 megawatts of battery storage online and by the end of 28 we'll have 3,000. So only about 10% were online by the end of 2025.
How does this new information related to actual HEM revenues for 2025 impact OPG's HIM revenue forecast of 17.8 8 million for 2027 given OPG indicated in G1 staff 242 that the HIM revenue forecast is based on the annual average over five years before the IR term.
>> Sorry that that is not correct. The forecast is not based on the annual average. I think the comment in the IR response was the forecast of 17.4 4 million was very close to 5-year average but the forecast is derived based on our modeling meth methodology uh which is um both described in E121 and H111.
So to confirm it, it is a model that for the HIM forecast in 2027, >> but uh um you've had two two years of major increases now. And um this might be the new normal, what you're referring to as abnormal weather now um that we're seeing. So I'm not sure how are you basically how are you taking what happened in 2025 into account?
Well, I'm not going to speculate on what weather is going to look like for the next five years, but as I mentioned before, we take a weather normal approach um which takes into account some volatility in weather, but not the extremes. So, I would say 2020 the the aberrations in 2024 would have been included in our weather forecast which will drive the HIM. However, the 2025 amounts were the weather data was not available at the time of submitting the the forecast. So those would not be included. But again, as our modeling uses weather normal and that is the most appropriate mechanism to forecast the revenues moving forward.
>> Okay, thank was my final question. Uh thank you for the clarifications and agreeing to my undertaking requests.
Uh thank you Mr. Sincar. We'll move um Mr. Mowitz for you now. Thanks.
>> Good morning witness panel. Uh I am Thomas Amanovich and I am a senior adviser with Ontario energy board staff.
Uh the questions that I'll be asking right now uh relate to the hydroelectric capital plan. Uh so these are highle kind of general questions. I'm generally interested in understanding some of the project classifications or the vocabulary vocabulary that OP is in the evidence when describing and substantiating the basis for the work that OPG performs and plans to perform on hydroelectric assets.
If we could please start with um interrogatory response to D1 PWU 001.
Okay. Thank you. So uh this is an interrogatory that requests uh some clarity on definitions on some of the project types and then we can see in chart one uh there are generally seems like four categories refurbishments, developments, rehabilitation and expansion.
And the response here points to other sections uh sections in exhibit F1. So I'd just like to confirm uh kind of the understanding of what these kind of types of projects uh mean. So uh refurbishments in exhibit F11 section 3.2 two and I'll just continue slowly here as as we uh get it on the screen. So it it it looks at least the way it's presented here in section 3.2.1 that refurbishments and overhauls are kind of generally uh grouped together.
Uh so I guess my first kind of basic question is is it fair to understand that these kind of happen together or could they happen independently of each other uh they can happen together. Um so one is an OMA type of project and one is a capital type of project. So depending on the investment uh they can be separate.
Uh but for the capital work typically there is always a component of OMA included in there. Um we can give you further detail if necessary.
>> Thank you. You're kind of already getting ahead. Um so I guess is is there any sort of like generalization or is it just like the the decision to do one or the other or the timing it it's just it's so varied that you wouldn't really generalize between overhauls and refurbishments on on units?
Maybe you could just for my my purpose as well just help us understand what you mean by generalize.
>> Well, I see the the section kind of groups them together and so I'm just wondering when there's a project that OPG undertakes. Is it fair to say that overhauls and refurbishments happen together or could there be overhauls that are done independent of refurbishments?
And I'm just wondering like I'm not trying to ask for exhaustive details.
I'm just wondering generally does one happen without the other and if they do like how does OPG decide do an overhaul versus a refurbishment on a unit? Um so our decision on a project is fundamentally driven by asset condition and um given the asset condition that will set a scope of work that set scope of work has defined criteria for treatment uh for the type of money whether it's OMA or capital um so there's some fairly clear rules around delineation of when we're doing major work on a unit, what is considered OMA work and what is considered capital work. And is there like a general kind of summary of how that decision is made already on on the record?
I I assume it is. I just can't recall to my memory.
It is on record. We have a capitalization policy uh which details the specific breakdown. If you we can find the reference to that if that's helpful. I I I think control F1 on capitalization policy should be it.
Um, so just because I'm trying to wrap my head around the different terms, I just want to confirm I have a common understanding of of these of this type of work that I can kind of have in the same place as the other types of work. So is it fair to say that the the overhaul work uh the omen work is about sustaining the assets and that refurbishment work is about extending the life of the equipment and may also increase uh the ability or like the potential for production. And so I'm kind of looking at let's see I think line lines 10 10 through 15.
On the next page I think it is that's where I direct you to the definition. That was where I would look for treatment of what OMA gives you and treatment of what capital gives you. Uh lines 10 through line 15.
>> Perfect. Thank you so much. And so now um in section 3.2.2 uh we have uh redevelopments. And so this is another section that has a a helpful straightforward uh definition uh right at the start of the section that identifies that this is primarily about or entirely about extending the life of existing assets. Is that fair?
>> I'd use the word primary goal, but you are correct. lines two and three define what we mean by redevelopments.
>> And so is it fair that the core kind of distinction from a refurbishment is that we're talking about like a collection of assets? Like I see the word population of as of assets. So would this be kind of like on a station level as opposed to on a unit level? Is that fair?
>> Could you give me the reference? Sorry, I don't see the word population.
>> Um it's so section 3.2.2 Two on line three says necessary to address a population of deteriorated deteriorated or otherwise end of life assets.
Thank you. Um yeah so we can I think when we're referring to there the word definition um we're talking specifically about um specific deteriorated or end of life assets as detailed. So um yes that there are a number of stations in that category which that is the population >> and and just conceptually could there be like a refurbishment could could a redevelopment include refurbishment work but it's just there's more of it like more assets.
>> I'll hand to my colleague Mr. Sikstrom to give you a further definition.
Yeah, as is mentioned in section 3.2.2 there, um it could include the replacement of a significant portion of the generating station equipment, but could also include the replacement of existing civil infrastructure as well.
Thank you. And and that kind of note on civil infrastructure, is that like are redevelopment projects generally also including civil infrastructure or is it just kind of like this example mentions it but civil work is not necessarily common uh or general to redevelopment projects.
They may include civil work. It depends on the condition of the assets at the particular fac. Thank you.
So the next kind of category that was mentioned in the in the interrogatory was rehabilitations. And so this is uh was referenced to section 3.2.4 or 3.2.5.
Luckily they they're kind of together.
And so for for this kind of group or or the use of the word rehabilitation, it's it's more of a description of projects.
So this is kind of what I was trying to kind of help myself understand.
Um is in terms of like a generalization.
I see on line 17 for example there's mention of um like canal wall deterioration and then um on lines 25 and 26 for Abbotipi Canyon we have like concrete structures and line 30 again uh concrete deterioration.
Is it is it fair to generalize that a rehabilitation project is more about addressing deterioration on Yeah, I'll stop there. Is it is it about like deterioration and addressing that >> as we identify uh in the section that you've referenced correctly? So F11 page 9 of 36 section 3.2.3.1 2.3.1 we identify under the section referred to as concrete and dam restoration and rehabilitation projects that this is to address concrete deterioration through re rehabilitation and restoration projects.
>> Thank you very much.
And on um Oh, thank you. I see it.
And so on uh page 15 of that exhibit uh which I think is is a continuation of the description of the Abboti Canyon project on page 15 at line three it makes uh reference to upstream concrete rehabilitation and I just wanted to confirm my understanding that what this what we take to mean from this is that this rehabil rehabilitation project is not limited to the generating station structure itself like there's other structures further up the river.
In the context you're pointing to in line three on page 15, upstream concrete rehabilitation uh refers to the upstream side of the dam. So there's a downstream side of the dam and an upstream side of of the Abby Canyon Dam.
>> Thank you. That's uh that's very helpful for understanding.
And so I mean it's already on the screen but the last one I wanted to ask about um was just to confirm uh so we have kind of everything kind of grouped together nicely uh for expansion projects. I see here on on line 8 um towards the end of the line that it seems that an expansion project can be generalized to increase the generation at an existing facility. So is it fair that this is like adding something new like new assets to an existing generating station in terms of the reference in 3.2.6 six.
The expansion opportunity we have is falls and that does include the potential to add a new unit to that existing generating station. And so if I just wanted to understand generally like an expansion project, it is that it like is that the like is that representative of what an expansion project is or could there be an expansion project that is not characterized by the description of the Sha Falls expansion?
expansion projects look to add new generating capacity to existing facilities. Perfect. Thank you so much.
Um I don't I don't know if it's necessary, but uh back at the interrogatory response uh to PW00001, uh in the in the narrative that accompanies the table just before it, it says um that these uh categories are kind of descriptions for the purposes of organizing the the projects for presentation. And I just wanted to understand within kind of the general business planning of your capital plan, are there like distin like do these definitions, these categories like do they matter in the business planning process to the people who are making decisions? I'm just trying to understand that element of it.
I'll answer it in two parts. I think to your point, does it matter? We're trying to be clear. So our our objective is to deal with asset condition. So we're trying to um define as closely as we can what we mean by what that project is. So um this description is just is a helpful category to explain it. Um, in the business planning process, uh, we use that to communicate, um, what's in our plan. Um, but again, a refurbishment, a redevelopment, a rehabilitation, um, an expansion, uh, different themes going on there. So again, but primarily, if it's linked to asset condition, that's one set of things. If it's an expansion, that's that's not really linked to an asset condition. and that's linked to new potential. So we try and use this as a as a descriptor uh in our in our business plans.
>> Thank you. And so to try and kind of summarize there there's a common understanding between like you know the people doing the work, the engineers assessing the work, the people planning, the people approving the work. There's a common understanding of what these kind of categories generally mean to to them in kind of their own context.
I I can't answer what people understand, but I can say what we define them as.
We're quite clear. Um we do our best to define the categories. Um as to a common understanding, uh I I don't know what individuals think personally.
>> Perfect. Thank you so much. That's definitely sufficient for what I'm trying to ask.
>> Okay. Um, so the next kind of uh place I'd like to go to is um the interrogatory response to D1 staff 61, please.
So in this interrogatory uh OEB staff asked about kind of the criteria for determining uh eligibility for a project for the capacity refurbishment variance account and then identified five uh projects uh as examples.
And so I'd like to start off just very generally.
Is is there a particular um or like part of the organization or a particular kind of group that's responsible for determining or like labeling if a project is is eligible for this variance account?
So it's Melissa Hannon. Uh we do it as a a team effort. So we work with the line to determine the scope of the project.
Uh the finance team sits down, reviews the either the the scope discussions the business case and then we work with our regulatory finance team to determine if it is eligible.
And just generally like kind of when does that happen in in the life of a project? Like does it does the project get assessed for CRVA eligibility? Like when the business cases are being developed for the first time when the business plan is being developed after the project is done like I'm just trying to understand when that kind of uh characteristic is determined.
So we do flag it uh during the business planning process but as the project progresses through the the phases and the scope is more defined that decision can change.
>> Thank you. So, I'd like to ask and I guess we can scroll down to the response for uh part B sub3 where there's this uh Chanel uh Limmerick Island uh project.
Uh just for the purposes of the transcript, it there's a reference to exhibit D1 tab 1 uh schedule 2. I don't think we need to go there unless uh the the panel would like to, but I'm just kind of want if we could please start with what's the kind of general function of um I guess Limmerch Island or the stuff that's associated with it.
>> Uh so we we define it in line 25. if it's a a slle gate and a slle gate allows water to be passed through a structure.
>> Okay. So there's there's like a water control dam associated with this island.
>> Correct.
And Okay. And then the the equipment that's being worked on here are SL gates. And so this is for water control.
Is that correct?
Yeah. So it's um the sloo gates are necessary to regulate the water to downstream of the Chano generating station line 27.
>> And so there is no generating units on the Limmerch Island control dam. That correct?
>> Subject to check. I don't think so.
>> Thank you.
The other question I wanted to ask was about the next one that's listed here uh the Silver Falls uh surge tank uh replacement.
Can you please explain how or if the surge tank itself is related to generating units?
This is Nicole Fabro speaking. Um, to answer your question, I'll reference on the same page line items 30 through 232.
So, a surge tank is a protective device that manages water pressure fluctuations and ensures steady water flow to the turbines. It also serves as infrastructure protection from excessive pressure surges that could damage pen stocks and associated structures.
So, is it does water flow through it to go to the generating units at Silver Falls or is it something associated with um the thing that flows water to the generating unit?
So um the purpose of the silverfall surge tank um it um is to manage water pressure. So um on route to the station so in ensures a steady flow of water. So you can think about it as part of the fuel route to the station. So if it's if its function is to manage pressure, is it OPG's view that or description that it also manages the flow? Like are those distinct things?
I'm not sure your definition of water flow. Um I' I the way I'd characterize it is it's part of the apparatus to safely supply water from upstream to the station through a pentock. Part of that process is uh to control for water pressure in that pentock and that's the function that this um surge tank provides. So I'd say it's part of the system to uh part of the water conveyance system to supply fuel to the station.
>> Thank you so much.
So the next uh interrogatory response I'd like to go to please is uh D1 staff 66 and I think we can go to uh chart one uh which identifies uh some assets and some associated projects.
So, I'd like to ask about uh the bottom two rows here um where we have uh road upgrades and road maintenance for the Otter Rapids uh G2 uh refurbishment and the G2 overhaul.
And I guess the first thing I'd like to understand is the cap the the road upgrades that are listed as um capital u when I guess when this capital work is complete and there's a an inservice addition associated with the road upgrades is is OPG able to just generalize like what asset gets that in service edition like is is the road an asset or is there some other asset that has its that like takes in this inservice edition.
>> Uh it's a road. So, um, it's just a >> I guess you mean in terms of accounting, like if you have an inservice addition to an asset or an asset account, would this go to like a road asset, the generating station asset, the generating unit asset?
I can answer that. So the road was actually capitalized under project 82543, but when we put it into service, it did go into its own asset class at the road.
>> Thank you.
>> And there's there's more than one um generating unit overhaul and refurbishment, I guess, groups of work happening at at Otter Rapids, right? like if um at exhibit the actual exhibit D112 table one which lists uh which lists the the projects with business case summaries there are there's a project for Otter G2 and then there's further down at line line 20 of the table a project for Otter G1. So there's there's multiple like Otter G1 so Otter generating unit works happening over time, right?
>> Correct.
And I think I think if we if we zoom in on lines um 10 and 20, I think at line yeah line 10 there's also a camp project. Um, so I this is just very generally like the the Otter G2 work is is that complete?
>> The project's still open.
>> Okay. And then um I think on line 10 there's there's like a camp project.
Again, generally only if you know it off the top of your head. Is is that project complete or is it still ongoing?
I'd have to confirm whether the P has been complete. I that that's good enough for for this. Thank you. No, no need to confirm.
Um so I'd like to ask about um I guess the details of of this o um these overhauls.
And so the business case summaries are filed under exhibit D112 and an attachment one tab 9 if my notes are correct would be the business case summary for the work on Otter G2.
>> This is correct.
And I just wanted I just wanted to um I guess first see on the screen in in the recommendation uh there's a couple uh bullet points with dashes. Um the middle one kind of in the middle of the page uh identifies costs for road maintenance and construction camp operations and and maintenance.
And I'm just curious if you could very at the highest level like what kind of work is or was this on the Otter G2 project.
Uh so if we you're right um bullet number four additional costs for discovery work during execution additional cost for road maintenance uh construction camp operations and maintenance um due to schedule extension. So what we're really calling out here is um um the road has to be maintained. So this is um if you can think of it like a gravel road uh those roads have to be uh maintained after weather conditions. So there's a continuous activity to regrade to make them passable. Um so when we talk about road maintenance that's the that's the component we're talking to.
Um think grading in your mind that's a good proxy uh for construction camp operations and maintenance. um that is the staffing of the camp. So uh when we say camp um I don't know what you imagine but it's modular buildings connected together with heat and light and a kitchen. So uh it has to have security staffing etc. So uh that's uh the the the costs associated with that is what we talk about operations and maintenance camp costs as opposed to the capital costs which are um putting the camp on site. So the modular construction, the utilities etc. >> Thank you. And um Mr. Miller, I I am almost done. Um if we go to the previous tab, I believe that's the business case summary for the other otter. Um I think it's G1. And if we just focus on the same kind of recommendation section, uh there's again um a note about ongoing maintenance and operating costs for the camp and the road. Do we see that?
I see it around bullet three.
>> Yes. And so again, just in general terms, is this the same kind of work as in the other business case summary?
So my conceptual model just to help frame it is we will we have built a camp and then that camp will operate for the purposes of the refurbishment at Otter Rapids and we will go from one unit to the next to the next. So effectively there is costs for the first unit and then when that unit is completed there'll be costs for the second unit associated with running the camp and running the road because again people are using that road every day for the purposes of the uh refurbishment project. And are the camp and road used like more generally or are these like is this a new camp you built only for the refurbishment and then it gets dismantled similarly for the roads required only for the refurbishment and then it goes out of service after the refurbishments are complete.
>> I will deal with it in two categories.
The camp uh is modular in nature. The design of that is for the purposes of once this project has finished and other projects which it may be used in that vicinity uh there is a choice and an ability to relocate it. So this is very common um just to set what Otter Rapids is uh it's uh about 230 km north of Timonss. So it's not a downtown location. It's not accessible. Um so that that's why we have the camp there.
As for the road, uh we're bringing in equipment to site for the refurbishment project. So that road will remain in situ after the closure of the activity, but to bringing in the componentry we need to there's uh there's large heavy equipment that needs to come in which is why uh there is expenditure on the road.
>> Thank you.
>> For safety reasons.
>> Thank you. I guess generally like if I see you know projects individualized for generating units and I see common elements I'm just kind of curious how does OPG determine whether you know these common elements of a camp and a road should be put into individual like generator unit projects as opposed to just having a separate project for the camp and the roads.
I can't really talk about it generally.
I can talk about it specifically. So in this construct there's a geography uh there's a a program and a schedule. So uh the let's call it the Otter Rapids setup camp road refurbishment. That's a bundle of work. Uh we've treated it uh in the most sensible way we thought. uh if we look at other projects, we can talk about those. Uh I can't really generalize because the nature of our assets, they're very different in different locations.
Um so I I wouldn't like to give you a false opinion through a generalization.
>> Thank you. And I guess just taking us back to kind of the interrogatory where this started about CRVA eligibility.
When OPG undertakes the assessment, is it is it limited or constrained to the resolution of the project or does OPG ever consider whether certain components of a project are CRVA eligible and certain other components may be not eligible for the capacity refurbishment variance account?
we would look at the scope individually to determine the CRBA eligibility.
>> So, so just to repeat it back, you evaluate a project and you look at the scope of the project and look at the major line items and evaluate each item of the project for eligibility.
>> If there's unusual things in the project, we would do that. with this one. Um, we determined that the the road and the camp were were part of that refurbishment. We wouldn't have been doing them if we had not done that refurbishment project.
>> Do you have any example from either this application or just generally an example of a a project that was part of the capacity refurbishment variance account where a component of that project was excluded from the variance account treatment? I I think we might just be getting beyond the scope of what this panel can deal with. Um questions around the eligibility and and how that all works would be best suited for the last panel.
>> Okay. Panel panel four knows what's coming. Those are all my questions.
>> Thank you.
>> Uh thank you Mr. Emmanovich. Um we're going to take our morning break and then we'll to Mi.
Uh so it's about 5 after 11. Let's come back at 11:20 and then we'll probably sit for about an hour or so before lunch. is scheduled for noon, but I think it may push that out a little bit.
So, we'll see you all in about 15 minutes.
>> Uh, Mr. Miller, who did you say was next? Sorry.
Asking questions.
>> Yes, it's Mr. Pi from OEB staff. So, OEB staff is going to take us uh at least past lunch, I think.
>> Thank you.
Okay, welcome back everybody.
Uh, Christopher, are you there?
>> Yes, I am.
>> Okay. Uh, looks like everyone's back and we are ready to go. Um, I'm going to turn it over to Mr. Pali.
Thank you Mike. Um um Yaros Pali here for OB staff. Uh my first question is um centered around exploring the asset condition and remaining useful life of major assets. So can we please go to the interrogatory response to exhibit D1 staff 059 in exhibit L.
Thank you. Um so as part of interrogatory D1 staff 059 part B OB staff requested among other things the range of remaining useful life of major assets for all the hydroelectric capital projects with a budget of over $30 million to have a planned inservice date after January 1st 2027. OPG's reply in this to this interrogatory pointed to exhibit L D1 SEC041 for this information. Can we please now go to the OPG interrogatory response found in exhibit L1 L D1 SEC041.
Thank you. As per the OPG interography of response found in this exhibit part A, page two, starting at line 14.
Thank you. OPG states that OPG's asset management process does not quantify a range of remaining useful life.
With that in mind, can we please go to exhibit D112, attachment 1, tab 24, project 86386.
>> Could you please repeat the reference?
>> Yes. Um, exhibit D112, attachment one, tab 24.
It's the Kakabeka Falls generating station redevelopment project. Thank you.
On page two of this business case summary, paragraph 4, it states that the estimated remaining life on the 100 years old turbine generator system was assessed in 2021 to be approximately 5 years.
So my question is given that OPG was able to estimate the remaining the remaining life on the turbine generator system for the Kakabeka Falls generating station redevelopment project. Can OPG estimate the range of remaining useful life at the time of project start for all the other projects and major assets in scope found in exhibit LD1 sec041 attachment 3.
As you have identified in D1 SEC041, page two of three, I'd like to refer you to line items 15 and 16.
So, Miss Patchet, that's D1 SEC041, page two of three.
And specifically in line items 15 and 16.
>> I'm sorry, this is the court reporter who is speaking right there.
>> This is Nicole Fabro speaking.
>> Thank you very much. Sorry for the interruption.
So we identify um in the prior statement that OPG's asset management process does not quantify rem remaining useful life and the degradation of the health of a hydroelectric asset which influences the time before an investment be required is unique to its operating environment. In response to your request uh I'll start by setting a little bit of context. We have 54 hydro electric stations regulated hydro stations and 207 units.
These units, as we've identified in our evidence, range in terms of age. So, some can be um quite significant in age.
Um some can be relatively new.
The way that we assess the condition of an asset is based on a variety of factors and it would be um extremely challenging to accurately predict the range of remaining useful life of the assets in these stations.
>> Thank you for that. Um so my question goes back to the Kakabeka false generating station project. Um, so how was OPG able to determine the remaining use of life on that agendrom speaking here the remaining useful life that's or approximate year five years that is mentioned in this BCS was based on an assessment report which was done as part of the project.
>> So does OPG already have these um this data then for all the other projects in reference to Mr. Sixstrom's remarks that KGS report was specifically prepared for that project. And to answer your question, there's a variety of different assessment documentation uh that supports the projects listed in attachment 3 of SAC 41.
>> Okay. Thank you.
So, um my question also is a follow-up question to that. Um is it possible to provide the range of um remaining use of life for all the projects in attachment three to sec 041?
>> I believe that question has already be been answered by the witness.
>> Okay. So it it's possible but it would take a lot of work.
Well, I think the answer if we were listening carefully to it is that there's a variety of factors that go into um the assessment and um that information is available for the one project you mentioned because a specific report was undertaken.
>> Okay. Thank you.
So just um to to build on this question um we notice that throughout the business case summaries in exhibit D1 OPG sometimes indicates that an asset has reached the end of its expected service life. For example, can we please go to the BCS for the Conniston and Stinson GS redevelopment project found in exhibit D112 attachment one tab five page two the business needs section.
So here in the first paragraph it states that the the generating station has reached the end of its expected service life.
So my question is if OPG knows the expected service life of an asset, can OPG determine the remaining useful life at the time of the project start from the expected service life which is known and the age of the asset that is known.
With respect to the reconnaissance instant redevelopment project, the generating station was deemed to be end of life because the units are no longer able to fulfill their function to produce gener generating power um at the facility, right? Um so let me just I guess ask that question again. If we know what the expected server service life of a station is like I let me rephrase. Does OPG know and have the data on what the expected service life is of each station?
>> I think the answer you're hearing is it's not a numerical.
So you were referencing two dates. It's not simply a numerical exercise to be able to make that determination.
>> Okay. Thank you.
>> Okay. Um I will move on to the next question then uh that explores the acid conditions at the time of project start.
Uh could we please go to the OPG interogatory of response found in exhibit L D1 SEC041 and part C of the response?
Thank you. So, as part of this response, OPG provided a summary of the major equipment and scope and the health assessment ratings of each of those assets for the allocated regulated hydroelectric capital and O1A projects with a total project cost of over $30 million. In note four to this attachment, OPG states that the equipment health monitoring process described in part A of the interactive response is live, meaning the condition of the assets is updated following the completion of projects to maintain, refurbish, or replace components. For completed projects in attachment 3, the condition of of the assets reflects the current status. Condition of the assets at the time of project start are documented in each project's business case summary.
However, for completed projects in attachment three, OB sta OEB staff are unable to find the health impact condition rating of most major assets in project scope at the time of project start in each project's business case summary at the same level of detail as provided for the post project condition of assets in exhibit LD1 sec041 attachment 3. For example, can we please go to attachment 3, page three, and find the 83495 RA Saunders generating station G9 capital refurbishment project.
Thank you. So under the condition of major assets, the listed major assets are the generator, turbine, turbine regulating equipment and all of the related components.
It is listed that all of these major assets and their components are in good condition post project completion.
However, in exhibit D112, attachment one, HAB 15, project A3495, which is uh this project, the business case summary lists the major issues, but does not assign a health impact condition for the generator, turbine, turbine regulating equipment, and all of the related components at the time of project start.
So my question is would OPG be able to update exhibit LD1 SEC041 attachment 3 for all completed projects to include the health impact condition rating of major assets in project scope at the time of project start at the same level of detail as is already provided for the post project condition of assets in exhibit LD1 SEC041 attachment 3.
This is Nicole Farbo speaking. In response to your question, um, some of the projects in D1 SEC 41 attachment 3, as you have noted, have been completed and in some cases these projects have been initiated a number of years back, let's say. um you know potentially as far as five years or more. In our evidence, we identify that we have transitioned a new method of monitoring the health of our assets. It's referred to as the the e- health system monitoring. Um and so to answer your question specifically, in some cases, the projects that have been completed would not have been the condition of those assets would not have been put into that new software, which is effectively what you see reflected on the page today. So to answer your question more completely, no, I cannot provide you um the condition of the assets as it's presented in this attachment for the projects that have been completed.
>> Thank you. So alternatively, could you provide um a similar type of asset condition for those uh completed projects and all of its assets based on the previous reports before this system before this new system was implemented?
So why don't we do this? Why don't we take away your request and consider if something can be provided on a best efforts basis? If we can, we will. If not, we'll explain why we can't.
>> Okay. Thank you. So we won't mark that as an under right now. Um just in respect of timing is this something you can consider over the lunch break or I guess you'll just let us know when you have >> let's give it an undertake the record clear and we will if we can't do it we'll explain >> in the undertaking.
>> Well let's call it JT 1.5 and um Ms. Coban or Mr. Py what what is being undertaken?
Um we would like to see the condition of assets for the completed projects um based on I guess a pre not based on the health condition assessment ratings but on anything comparable for all projects and SEC 41 attachment three >> on a best efforts basis for the completed projects. Thank you.
>> Okay JT 1.5.
>> Thank you. Uh, next question also has to do with SEC041 and examines the assets and good and fair condition are being replaced.
OB staff notes that in LD1 SEC 41 attachment 3 there are several examples of assets in good or fair condition being replaced or refurbished. For example, if we scroll to page four of attachment 3, we can see the Connistan and Stinson GS redevelopment project.
So for the Stinson generating station in the far far right column, it shows that the condition of the rotor is good and the scope of the work entails a new installation.
There are two other examples that would show assets in good or fair condition being either replaced or refurbished. So if we can scroll to page five of this attachment, we can see the Otter G1 capital upgrade project.
It would be project A2542 Otter G1 capital upgrade.
Okay, thank you.
So here we can see that the current condition of the stator is fair and the scope of the work entails a refurbishment.
And if we can keep going to page 8 of attachment 3 for the sir Adam Beck uh G18 G17 refurbishment project.
Thank you. It states that the condition of the stator is fair and the scope of work entails a new installation.
So my first question is why do assets in good and fair condition get replaced or refurbished if the in general? Yeah. What what happens? Why why do these assets get replaced if they're in good or fair condition?
I'll begin by answering your question in a broad sense and then perhaps provide an example. So broadly speaking um as identified in D1 SEC041 uh page 20 of3 chart one um the intention is to complete work on assets before they get into a poor or unacceptable condition.
However, there are circumstances in which when we go in to do a unit refurbishment where there is a component uh subcomponent, let's say, of a of a broader assembly that is deemed to be in poor or unacceptable condition. And as a result, um in the effort to replace that specific component, it may necessitate um a broader replacement or redesign of neighboring components. And in some cases, yes, that may require that an asset that is deemed to be in fair condition may need to be replaced as a result of the broader configuration of that component.
There are also other considerations that we take into account when planning and scoping uh unit refurbishments and uh one in particular is the potential for concealed conditions. And as we plan a project um based on uh engineering expertise and judgment and and history of of past failures, we will apply that to do what we feel is prudent to mitigate risks what we call in outage or while that unit is undergoing a major refurbishment and in some cases um that may necessitate the replacement of that asset.
Great. Thank you for that. Um, just a follow-up question on your explanation.
Um, so how does OPG determine what type of work, whether it's a new installation or refurbishment, should be done based on these health impact condition ratings?
So in response to your question, uh if you reference chart one in D1 SEC 41, uh page two of three, the ratings provided are a guidance or an indicator of equipment health as we have identified.
And based on these ratings, um, engineering in conjunction with plant staff will, um, determine appropriate short-term and long-term mitigating actions to address conditions or risks.
And based on that that um that plan whether it be short-term mitigation or long-term mitigation in the case of long-term mitigation may require or necessitate a greater degree of investment or a greater action plan for example and that determination is what initiates in many cases the start of a project.
So to be a bit more complete in my answer, if we refuse refer to uh D2 or D one second here it would be D211 page four of 13 section 3.2.1.
Thank you.
So we identify in lines 17 through 20 that we conduct asset reviews on reliability, health and obsolescence and they these reviews um will produce a health report or a condition assessment and these assessments are what contribute to the recommendations to request capital or OMA expenditure funding for project needs.
>> Thank you. Uh could we just quickly go back to that table one health impact condition ratings that we had on the screen for SEC 041. Um I noticed here for the condition description of fair and good that it doesn't state any mitigation actions required. Um you know when you compare to the unacceptable and poor condition descriptions um is that and as I mentioned in the previous examples we did see work done on assets that do have fair that were in fair and good condition. So is it is this just based on like the overall project like you described like this this isn't like a religious chart that you have to follow.
Engineering will provide an assessment of equipment health. However, because in a unit refurbishment or overhaul, there are a number of components that we look at and do our best to maximize or be as efficient as we can with the work that we complete during that that project or during that outage. There could be reasons in which from a project risk perspective, we may elect to do work on assets that are considered in fair condition for the reasons I previously stated.
>> Okay. Thank you. Could we please go to page four of this attachment three please for the G20 G19 refurbishment project.
>> Perfect. Thank you. So we note in this attachment it appears that certain major assets such as the rotor and hydro turbine are not in the same condition between the pairs of units being refurbished for the sir Adambeck GS refurbishment projects on units G20 G19 G18 and G17 and G14 and G13. So for example on this page here on the for the G20 G19 refurbishment project here it states that the current condition of the rotor is poor for the G19 unit and good for the G20 unit and the current condition of the hydro turbine is poor for the G19 unit and fair for the G20 unit.
Um next if we can please pull up exhibit D112 page 17.
Perfect. There the G20, G19 refurbishment project. Um, so this this so the question I'm asking is also um related to G18 and G17 and G14 and G13, but I'm not going to be I'm not going to ask to pull those up because the references are the same across all of the three projects. So we note we note that all the these projects are being done in pairs due to being closely connected electrically. The the units share a common transformer bank, high voltage line, high voltage disconnect and medium voltage isolated phase bus as well as protection and controls equipment. All three of these projects include the replacement of electrical common balance of plant in the scope of work which is described in the business case summaries such as in exhibit D112 attachment one tab 41 in the description of the preferred alternative Thank you. So just to help us understand the benefits of combining these units together when the condition of certain assets um are different um we would like to ask um how many outage days does OPG estimate as the result of replacement of electrical common balance plant of work for each of the G20 G19 G18 G17 and G14 G13 projects.
I do not have that information in front of me today.
>> Is that something that can be provided?
>> Maybe you could help us understand why that's relevant. The number of outage days.
>> Well, the reason we're asking is because we we understand that one of the reasons why these assets why why these projects are being done in pairs is because they're closely connected electrically.
And um this these projects include the replacement of these electrical common balance of plant um assets. So we're trying to understand um if there will be a difference in the a number of outage days if these projects are done together versus separately.
We we can take that away to consider your request. I I I think there might be a premise baked into your question that we we need to clarify as part of the response. But um on a best efforts, we can take that away to consider and if we think the premise of the question is not appropriate, we'll we'll explain uh why in the response.
>> We'll call that JT 1.6.
>> Thank you.
The next question explores the probability of failure of assets. Uh, can we please go to attachment 2, the engineering risk assessment program, renewable generation procedure in exhibit LD1, SEC 041, page 8, section 1.222, probability of consequence selections.
Thank you. So here OPG describes the probability of consequence as the likelihood of the entire sequence of events that shall happen for a particularly undesirable result or consequence to occur. Before selecting the probability of consequence, the anticipated equipment failure or and resulting consequence to be evaluated should be clearly defined.
So my question is does OPG have a probability of failure for all projects and major assets listed in exhibit LD1 SEC 41 attachment 3.
I cannot confirm based on the information I have in front of me today definitively that a probability of consequence of failure has been completed for every single component listed for every single project in attachment 3 of D1 SECO41. Would it be possible to take it back and provide information for any of the projects or as much as as much as you can?
on a best efforts basis, I can undertake to provide you a representative sample of some of the analysis or the risk assessment that may have been completed to form the determination of scope for one of the projects listed in D1 SEC 41 attachment 3.
Um just considering the magnitude of projects and the impact on rate payers, I think we would prefer if it could be done um for all the projects in that attachment and um to make it a bit easier if we can meet halfway maybe the probability of consequence could be done on the major assets and not all of its components. Would that work?
I I think the scope of what you're looking for is is quite extensive. Um so we're prepared to do that on an example basis so that you can understand how it works but to undertake to do that for for all the projects uh even if we scope it down to a major component is is a significant undertaking and amount of work and we're not able to do that here within the timelines.
>> Okay. Thank you. In that instance can we please ask you to prioritize the importance of the project in the example that you give us? Um, so something with the the highest cost or just use your discretion to give us the most relevant example, please.
>> We will use our discretion to give you a meaningful example.
>> Thank you. We'll call it JT 1.7. Uh, Mr. Pi, could you just repeat for the record what the undertaking is for to the best of your recollection just to make sure we're all on the same page?
>> Thank you, Mr. Miller. We're looking for a probability of failure for um for any relevant and important project that OPG can provide us with as an example of how it is assessed and how it is and how we can use it to analyze certain issues.
>> That's fine.
>> Thank you.
My next question explores equivalent forced outage rates and a availability for generating stations. Can we please go to the interrogatory response found in exhibit LD1 staff 060.
Thank you. So in this exhibit, OPG provided the actual and target hydroelectric availability and equivalent forced outage rates or E4 for the Alexander GS and A Manitou Falls GS for the 2016 to 2024 period and the E4 and availability trends for these units as compared to the other units at the respective stations. On page two, part C of the interrogatory response, OPG stated that although the Alexander GS station has five units, refurbishments are only required for Alexander GS G1, G2, and G3 based on their condition. OPG also stated that for Alexander GS over the 2016 to 2024 historic period, availability trends for units G1, G2, and G3 were generally consistent with each other and aligned with the performance of units G4 and G5.
Similarly, historical E4 results for G1, G2, and G3 followed comparable trends and were overall in line with those of G4 and G5. So my first question is what condition are units G4 and G5 in?
>> I don't have that information with me today.
>> Could that be taken back and provided later?
>> Yes, we can do that.
>> JT 1.8 8.
>> Thank you.
>> Um, just a follow-up question to that. I don't know if you have this information as well, but when will units G4 and G5 be refurbished?
>> I also don't have that information with me today.
>> Could we add that to the undertaking?
>> Yes, we can just roll it into 1.8.
>> Thank you.
The next question is can OPG please help me understand what is the relationship between availability and E4 trends and asset condition.
So I'll I'll start with the availability and E4 relationship. So um uh availability is the total availability of the station um measured on a time basis weighted by megawws.
E4 is a subset of that. Um it's a uh equivalent forced outage rate is the definition of E. So it's a subset of the overall availability.
uh within availability there's planned outages, unplanned outages, E4. So there's a number of criteria that sits underneath there. Um the relationship of that to underlying asset condition um there's not a um there's not a direct comparable or linear relationship between one and the other. it depends on the context of the unit um the function of the unit in the market um and and the role it serves. So um again just at a at a broad perspective uh we have lots of units across the province. They vary in from new to very old. So think over 100 years old. So it really depends on the function of the unit in the market and how it runs. So uh if we if we narrow the question perhaps we could uh get to something substantive.
>> Okay. Thank you. So is it is it um acceptable to see a unit in good condition with poor um say E4 and availability trends?
Is that something that's commonly seen?
Sorry.
>> Yes. Um, if there's a um a generating station reporter, this is the court reporter. Sorry, the court reporter.
That microphone was off when that question was said back. Thank you.
>> Sorry. Can you can you just repeat the question or just clarify it?
>> Yes. Uh, thank you. Um, can an a generating station or um a be in a in a good condition but show um you know a negative or bad availability and E4 trends?
I I think I'm struggling with your question and the premise of it because as we heard and we can see in SEC 41 conditions not assessed at the station level, it's assessed with respect to the components. So could you maybe clarify your question because I think there's a faulty premise in there that you know might confuse the record.
Um, we're interested in the condition of the assets that drive the work of the project.
So, and we're trying to compare the overall station condition to its availability and E4 trends.
Uh, if I could refer you to F11, sorry, Fle 1, please. Page 24, chart 7 or charts. Actually, let's start with chart six.
uh on page 22.
So this looks okay.
Okay. So we can see on chart six a sample of um individual stations and then the fleet as a whole at the bottom uh where it says all 54 regulated hydroelect electric stations.
So you can see in this chart here we list out the uh actual and target availability for a station and that's at a station level and a station comprises of units that sit underneath of that. So to my colleagueu's point a moment ago when we're looking at projects we assess at unit level. We don't assess at a generic level but we track availability for a station at a station level. So um let's take a station example uh sirbeck 2 that's 16 units. So the if we look on this sheet here um third row sir Adambeck 2 GS uh that is the composite of 16 units uh worth of availability.
So uh the underlying asset condition will vary as we've just established on a unitby-unit basis and under that unitby-unit basis there'll be kind of subsystem and subcomponent.
So to your if I recall your question correctly for trying to link uh asset condition to availability um it's not a straight pass through in the relationship between them because of how all the subsystems tear together.
Your overall premise though is not unreasonable that a poor uh assets in poorer condition could have lower availability.
Um to your point on E4 which is a forced component that's a particular subset of unavailability which is related to being unplanned in nature. So again the relationship you're drawing is somewhat broad. Again if we want to zoom in we can be very specific but we're dealing with lots of units and lots of subcomponents. And I wouldn't want to draw a generalization even though it might be tempting.
Thank you for that.
Would you want to do lunch now or should I continue?
>> Um, how how much time do you have left, Mr. Pi?
>> Um, I have I have four more questions pro probably around half an hour.
>> Um, okay. Okay, we may need to uh why don't we take our break uh and we can um um see where we are from there. Okay, let's take our break now. It's but let's come back at 10:05.
Thank you.
Uh, Mr. Miller, this is the court reporter. Can I trouble you to ask you who would be the next OB staff witness to ask questions after uh, Mr. Pal?
>> Yes, I think it's uh, Ada Lee A space Li.
>> Thank you.
We're going to get started in just a second here, folks. Uh, Mr. Siddle, are you there?
>> Yes, sir.
>> Okay. Um, let's go back on the air then.
Good afternoon everyone. Welcome back to the afternoon session of day one of Tech Conference for OPG. Mr. Pi, I'll hand it back over to you.
Thank you, Mr. Miller. So, for this next question, we I would like to explore the Sir Adambeck Canal uh rehabilitation project deferral. So, can we please go to exhibit D112, excuse me, attachment one, tab 42, project 89252.
Thank you.
If we scroll on to page three please of the business case summary.
Okay. Thank you. On page three of this business case summary, OPG states that the sir Adam Beck one canal rehabilitation project began under project 82771 which funded condition assessments and various project management activities including the development of an initial overall cost estimate and technical specification. The project was deferred in 2020 following a risk analysis that confirmed that the deferral that the canal conditions could sustain this delay. As per the plan, upon project deferral, a team was was reassembled to explore restarting the project in 2024.
On page one of this business case summary, it states that the project was restarted in June of 2024.
Can we please now go to exhibit LD1, staff 075.
Thank you. So for this interrogatory OB O OEB staff asked how long did the 2020 risk analysis indicate that the canal could sustain a delay in rehabilitation and if any more recent analyses have been performed and if so how long did these analyses indicate that a delay could be sustained? In part A of its response, OPG replied that a specific timeline wasn't provided in the 2019 risk analysis indicating that the canal could sustain a delay in re rehabilitation and that no further recent risk analysis has been conducted.
So my question is given that there was no timeline provided in the 2019 risk analysis and there was no further risk re recent risk analysis performed, how did OPG determine the need to restart the project in 2024?
So as indicated in the IR response D1 staff 075 um there is an the next condition assessment is planned for 2030 and although the canal assessment that was done um in 2020 indicated that there wasn't a firm timeline it did highlight that degra ation of the canal will continue and eventually it will need to be rehabilitated.
So this project was restarted in 2024 with the scope of preparing for the eventual rehabilitation of the canal.
Thank you for that.
My next question explores unallocated projects. So, can we please go to exhibit LD1, staff 064?
Perfect. Thank you. In exhibit LD1, staff 064, attachment one.
I don't know if you can pull up the attachment to this, please. Attachment one.
It was an Excel file.
Perfect. Thank you. So in this in this attachment, OPG provided the estimated total cost and potential inservice year for each of the unallocated projects found in exhibit D112 tables 5A and 5B, which is all of these projects that we see in front of us.
OPG also stated as part of their interrogatory response that we can go back uh to uh the exhibit. Yeah, perfect. Thank you. So, OPG stated that with the introduction of the longerterm business horizons of up to seven years, the renewable generation business unit has aligned the management of its capital and OMA project portfolio with that of the rest of the company and implemented the use of of unallocated portfolio funding. The use of this unallocated portfolio in business planning was approved by the OPG board of directors.
Can we please go to exhibit D112, table 4?
Thank you. In table 4, OPG shows the yearly inservice capital additions by prescribed facility category which includes categories for allocated and and unallocated projects.
So my request is can OPG please provide a yearly breakdown of the unallocated projects that contribute to the forecast inservice capital additions for 2027 to 2031 seen in lines 27 30 32 33 34 35 in exhibit D112 table Four.
If you can please turn to uh IRF1 MCO 91.
Thank you. and then scroll down.
So in this IR there are charts in here that uh identify both the unallocated and allocated projects for that table.
>> Oh that's great. Um I just can't see the unalloc unallocallocated projects. Is that lower down in the reply?
>> Chart four shows your unallocated This is the court reporter. If I could just ask the witness to just bend your microphone just a little closer to your mouth. Thank you very much.
Okay.
Okay, that's good. Thank you.
Can OPG please confirm when the OPG board of directors approved the use of unallocated portfolio in business planning for the renewable generation business unit and when did OPG start implementing it in their business planning The unallocated portfolio has always been part of the the RG business plan.
Uh but because this is a 7-year business plan, it's substantially larger than it has ever been.
What year did it start >> the use of this unallocated portfolio?
>> So I don't have that in front of me.
>> Oh, is that something that uh we we you could check and get back to us with?
>> Maybe you could just help us understand how what is the relevance of knowing when it started.
I think we think it speaks to the way that OPG kind of plans capital projects and we're trying to understand and I guess compare to the last time the OEB kind of undertook a review of a capital plan. So we understand that these unallocated projects were not really a thing during the last cost of service proceedings. So we'd like to understand when when OPG as a business started using unallocated projects and and just stating that like the RG business uses this is a bit ambiguous to us because we understand there have been reorgs so it we're looking for like a even just a year or like a business plan that started using this idea.
Okay. Well, we we'll we'll undertake to consider your request and if we can provide an answer, we will. And if not, we'll explain the basis for the refusal.
>> Thank you.
>> JT 1.9.
>> All right. Thank you. Uh my next question explores the cost variance between the RA Saunders G12 and G16 units. So can we please go to exhibit LD1 staff 068.
Thank you. So in this exhibit, OPG provided the difference in cost and in the project scope between R the RH Saunders GS G9, G12 and G16 refurbishment projects. On page two, OPG states that RH Saunders GS unit G16 is the third unit to undergo capital refurbishment and the second CWC unit to undergo refurbishment as part of the RH Saunders GS refurbishment program. The cost and scope for unit G16 incorporated lessons learned gathered from both unit G9 and unit G12 up until Q4 2025 when the full execution BCS for unit 16 was approved. Unit G16 and unit G12 are both CWC units with the same scope of work as per chart one scope comparison summary major components on page three of this reply.
OPG also provided the cost breakdown per unit in chart three on page five.
OB staff note that the unit G16 refurbishment incorporated lessons learned gathered from both unit G9 and unit G12 refurbishments and had the same scope of work as the G12 refurbishment and yet cost $18.9 million more than the G12 refurbishment. Can OPG please undertake to provide a narrative that describes the main drivers of the difference in cost between the G6 G16 and G12 refurbishment by category as seen in chart three cost breakdown per unit on page five of this interrogatory response.
Sorry, just to refer back to chart three. Um you want to see the cost breakdown that's in chart three.
>> Yeah. Just uh we would like you like see like an explanation of these differences in cost.
>> So it's the narrative around the detailed items here project management and engineering through interest to substantiate the 30.4 to the 49.3 if >> that's rightly.
>> Yeah. Yeah, we can do this.
>> That's JT 1.10.
>> Thank you.
>> The next question explores the cost variance in the Chanel Limmerch Island Superstructure Gate Hoist Project. Can we please go to exhibit LD1 staff 316?
Thank you.
In this exhibit, OPG explained that this project is neither has a superseding business case summary nor is in recovery. So they did not provide the cost variance for this project. The BCS filed in exhibit D112 attachment 1 tab 19 identifies an increase in cost between the gate 2 definition phase and gate 3 execution phase from 11.4 million to 32.7 million. We can pull up that business case summary please for the quick reference.
Thank you. So it's just that first line, sorry, that second paragraph that states that the total project cost is now at 32 million versus the 11 million in the previous release. Um, if we can just go back to the interrogatory response now.
Thank you.
So in this interrogatory response, OPG explained this cost increase is a natural progression as the project continued to solidify scope, complete detailed design, and refine cost estimates throughout the planning process. As described in the business case summary in exhibit D112, total project cost at execution phase includes a revision to the sloogate control standard, power supply replacement, addition of stair towers, enclosed hoist house, and logistical considerations at the interprovincial bridge.
Can OPG please provide a quantitative reconciliation from the 11.4 $4 million found in the gate 2 definition phase to the $32.7 million cost found in the gate 3 execution phase by major cost category and by driver. Can you please identify which scope elements were known or foreseeable at gate 2 versus identified later? And can you please explain whether the increase was driven mainly by scope additions or estimate class maturity, EPC pricing, access or logistics, market escalation or contingency?
Uh so I think you're calling out the natural progression of our project maturity as we come through uh the phase of um uh maturity from a gate two through to a gate three. Um um so we we expect as scope matures etc to um and and um estimates to be refined. This is just part of the natural progression. uh if you're asking to do a specific breakdown um as per the way we've approached uh G9 and G16 uh in the aforementioned reference uh via those high level cost categories uh we would be willing to um detail that between a gate 2 and a gate three for this this limmer project >> that would be great thank you >> that's uh JT 1.11 Those are all the questions I have. Thank you so much for your time.
>> Thank you, Mr. Pali. Um I think Miss Lee, it's over to you now.
>> Yeah, we're just going to do a quick swap at the front here. Okay, very good.
My name is Adah Lee. I'm an analyst with the Ontario energy board and my questions are primarily related to the hydroelect electric production for um can we go to interrogatory response E1 staff 140 So according to the scorecard um the definition of hydroelect electric availability is the percentage of the generating potential that could have been provided after considering outages and drates regardless of fuel availability.
So can OPG confirm that outages and D rates are the only factors considered in this metric.
Uh if I could direct you to F1 staff 170. Uh we give uh maybe let's start on page five. Sorry, page two or five.
Yes. Staff 170 please and we'll start at page line 18. So um we give a description of here of what's included in availability.
Um so the components uh to derive availability is one minus the incapability factor and the incapability factor is a function of planned outages equivalent planned date hours forced outage hours and equivalent forced drate hours divided by the time period.
So I'd happily if you repeat your question I can uh answer the specific elements but these are the specific elements in the incapability factor to which I think you were referring.
>> Yeah thanks this confirms it. So the question was can OPG confirm that outages and D rates are the only factor that's considered in this metric?
>> Uh as per this calculation that is an incorrect premise. It is planned outage hours, equivalent planned D-ate hours, forced outage hours, and equivalent forced D-ate hours.
>> I understand. Thank you.
>> Can we go to exhibit F11, chart 6 and 7?
So chart six shows the historical hydroelectric availability from the year 2016 to 2024.
Um and chart 7 if you scroll down shows the target availability from 2025 to 2031.
Can OPG confirm whether the target availability in chart 7 in this case is the same as the forecast availability used in determining the hydroelect electric production forecast?
So it it would not be the same and the availability used in the production forecast is described in F140.
When you think about production and availability, you have to conser uh consider fuel availability which is water for hydroelectric stations. And as we described in uh E111, production is highly tied to the availability of water. So you could theoretically have outages that don't impact your production because you wouldn't have otherwise had water to.
So the numbers are different but the numbers used in the production forecast are included in the uh staff 140 response.
Okay. I so the availability used in the forecast is the one shown in 140 staff 140.
Okay, thanks.
>> So, can OPG provide like an availability table similar to what's in F11 that reflects the actual production forecast for 2027?
Is that possible?
It's possible. I'm just thinking about the level of effort required and the timeline available to us. So I think >> like the the top five stations by production.
>> Um yeah, I I think we will take it back on best effort.
>> Yeah, we're not asking for like every single >> fiddle station to forecast. It requires calculation because there's there isn't an explicit availability in the production forecast. It's a function of outages that are planned in the forecast. Right. And then I think from there we have to reverse calculate what the availability would look like.
>> Yeah. We're we're we're trying to understand how the production forecast relates to these metrics. So on a best effort basis, if by the level of production there's a few top stations that account for the majority, I think that would be sufficient for what we're asking.
Okay. Yeah. So, I think we could take that back as an undertaking to describe the availability used in the production forecast for the top five generating stations.
>> But sorry, Mr. Shiak, we understand from staff 140 that availability isn't like used in the production forecast. We're trying to compare, I guess, what would be the output of a production forecast to compare it to the availability metrics we see in in the chart of exhibit F1. So, just to be clear, we're not asking about kind of like an input of availability to the production forecast, but the result like the output.
>> Understood. Yeah. And and we will endeavor to provide that.
>> Thank you. JT 1.12.
>> Moving on to uh interrogatory response E1 staff 137.
If you can go to part D.
of the answer.
So for context, this interrogatory is focused on understanding the difference in the forecast methodology between EB 201321 and EB 2025297.
Can OPG confirm the following numbers?
The impact of unplanned outage spill is 0.19 terowatt hour for test year 2027.
Non SBGVA eligible market spill is 0.63 terowatt hour. Condensed mode operation load is 0.08 08 terowatt hour and the spill occurred outside SPG conditions and not associated with scheduling down is 0.16 terowatt hour for test year 2027.
>> That's correct.
>> Thank you.
So do you accept a subject to check that the sum of all these numbers is 1.06 06 terowatt hour >> subject to check. Yes.
>> Regarding the fourth paragraph in response F, can you please explain what is causing the spill that quote occurred outside SPG conditions and not associated with a market event? Specifically, what does this mean operationally for OPG?
Well, in terms of what it means operational for OPG is that we had economic offers to generate our facility and due to some market condition we were not able to generate and the that was not reflective in the the the shadow price at the time.
So it resulted in foregone production to OPG.
>> Can you confirm that the cause is unclear to the spell that's referenced here?
>> Are are we referencing which paragraph are we referencing?
So >> lines 1 to 10.
>> Yes.
>> So sorry, could you repeat your question?
>> So for the spill that's in line two and line three, what is the cause of this spill that occurred outside SPG conditions but also was not directly associated with scheduling down?
So it it it wouldn't be reflective of market outcome or patch from the ISO.
There are multiple potential causes for this type these types of events. They could be um ISO manual or verbal dispatches. It could be ISO respecting um vi uh constraint violations. There are a multitude of events that could cause this.
>> Thank you.
So using the above mentioned uh value of 1.06 terowatt hour as the sum of all adjustments and comparing it to the currently proposed 2027 test year forecast of 32.5 terowatt hour. The total 2027 production forecast would increase to 33.56 terowatt hour if the original EB 2013 method was applied.
Does it mean that if the EB 2013 0321 forecast model had been used to produce the 2027 production forecast, it would have been 33.56 terowatt hour? Can OPG confirm this?
I I would frame it more so the adjustments we've made to the production forecast for EB 2025 and in terms of the the totality of those numbers are the one point I don't remember the number you quoted but 1.02 terowatt hours Thank you.
Can we go to interrogatory response staff 007 A1?
So this is a list of inservice capacity by generating stations between now and the end of 2031 according to the capital plan.
So staff conducted an analysis of the amount increase between the current application and the year 2030 2031 and identified five stations that are key contributors to the capacity increase.
So for example for auto rabbits auto rabbit rapids has a capacity increase of around 11.6% 6%.
Does it does this seem right to OPG in the response uh in chart one? I I count a few more stations than the ones you noted there. Um so uh I think you how many? I think you said there were five.
>> Five. So list them all as uh Otter Rapids Otto Hoden RH Saunders and Sir Adam Beck 1 and two that is a subset of the increases. I agree with that.
>> Yeah.
>> Um and Otter Rabbits has a capacity increase of 11.6%.
Around >> uh I haven't done the math. It goes from 182.4 4 to 203.5.
So I make that 21.1%.
So uh in a rangebound way, your answer doesn't seem unreasonable.
>> So in OPG's view, is this increase in capacity a material impact to production?
C >> can you define material for me please?
>> So it would result in a change a increase to production due to capacity.
>> Um so can I just take a step back? So let's think about what capacity is. Uh so capacity is generating potential and generating potential gives you the opportunity to have higher production.
Again because these are hydro plants they are subject to water being a key constraint of how much water is received in the river or the the system. So uh making a direct linear comparison between capacity and production isn't the right mental model in this context.
I guess what we're asking does would OPG consider this increase that we're talking about for auto rapids to be material.
uh we can provide the net change in the production. I I again your material and my material. I I don't know if you can be specific. I might be able to guide you. Uh we're adding 21.1 megawatts of capability over the rate period. So that's being layered in over the next period of time. Um so this this is what will happen by 2031.
I get in the interest of time I I'll try and um make sure I understand what you're offering. So is OPG offering to attempt to quantify the production impact of that capacity increase? Like could you compare it for example to the 2027 forecast the incremental production of that capacity increase?
You've just made the question considerably harder.
>> I didn't understand exactly what you were offering.
>> So I I can't go back and remodel 27 because life moves on, things change. What we can do is give you uh a best efforts estimate of what happens to this 21 megawatt in the future. I can't go back and say what happened in 2027. had I had 21 extra megawws, what could have happened there? Um, that that's beyond our capability to do that.
>> Sorry, Mr. Penner, just to clarify, I was asking in the context of the 2027 production forecast that's proposed um for the hydroelectric payment amounts, like the forecast.
I'm just confused because you it seemed like you were talking about the past.
I'm I'm sorry if I'm tired.
>> I think we're all getting a little confused. Um what I understood is that we cannot reconstruct the 2027 forecast to account for this increase in production. That's what I understood from your testimony, Mr. Pender. If that's incorrect, please do set us straight on that. That >> that's where I was going.
>> We'll take whatever you're offering.
Thank you.
I'm unclear. Is there any undertaking here or so? Just to confirm the ask, you're seeking to quantify the benefit of the capacity increase at Otter Rapids in 2027 from the benefit to the production forecast.
That sounds about right. Well, on a best efforts basis, we'll seek to provide that.
>> That's JT 1.13.
>> So, continuing on.
>> Oh, okay. Thank you.
>> Okay. Uh, so, uh, thank you. Uh so I just have a couple more questions also related to the production forecast. So this is for the benefit of the transcript. Thomas Emmanovich uh advis senior adviser OEB staff.
If I can start please um start this conversation with ex uh interrogatory response to E1 SEC 128.
And so this is an interrogatory that identifies outages. I'm not interested in in the specific outages. Rather, what I'm interested in is the general concept of what OPG as a market participant kind of provides to the ISO in terms of production uh information.
And so it's I guess I'll start off by confirming that as a market participant, OPG provides information to the ISO for example related to outages and future production.
I can confirm we provide outage in to the ISO as per the ISO market rules but we we do not provide production information to the ISO or production forecast I should say.
It's OEB staff's understanding that under the market rules to support the ISO's planning documents such as the reliability outlook or annual reliability assessments, market participants provide information to support those ISO undertakings.
>> That's correct. That's generally outage information and availability and capacity factors, that type of information. Is that information also provide like production like megawatt hours over a future period?
>> I don't believe so but I'm not positive.
>> So OEB understand OB staff understands that the ISO has at minimum an annual process where market participants provide information to the ISO to support the reliability outlook. And I believe the ISO references a form uh 1230 and in our I just just for the transcript I see nodding heads at least one. Um if if you're able to like isn't there a megawatt hour component to that information that market participants provide to the ISO.
>> I think that's something we could check at break and get back to you on. And I don't know off the top of my head.
>> So it's it's our understanding that this type of information would support like for example the ISO reliability outlook and would contain at least some view of future production that the ISO uses for the reliability outlook. So for example, there is production information by fuel type that's provided in those reports and supporting tables and it's it's OB staff's understanding that that information comes directly from market participants that the ISO wouldn't come up with their own megawatt hour forecasts to support the reliability outlook. And so what I'm asking is if OPG could provide for some sort of I assume that this is a future outlook of at least 18 months because that's the term of the reliability outlook. And from the information on the ISO website, this at minimum has to be provided on April 1st annually with any subsequent updates afterwards. And we're asking if OPG would provide the production forecasts that were supplied to the ISO under these market rules.
I think one of the things we'd maybe ask Mr. or Cherk to speak to is um if this data that you're providing to the ISO is on a combined basis in terms of prescribed assets and non-prescribed assets. I I think that'll you know if we're looking to get information that's submitted on a combined basis and includes assets that are with outside of the scope of this proceeding obviously we have some concerns with that.
>> It's our understandable it's it's our understanding that this this document that the ISO um receives from market participants is on a facility basis. So we would not expect or request any information related to non-regulated stations.
I think at most we can do right now is take this away at the break and and see what can be done. So not not prepared to give you an undertaking on it because I think there's some clarification that might be required at the break in terms of this particular uh set of information you're referencing.
>> Thank you.
Sorry. Just give me a moment to calibrate as I'm trying to scrub time here.
Okay. Uh final kind of set of questions for me on this topic. Uh if we could go to E1 staff 136 part C please. And so in the question or in the interrogatory OB staff's uh requests OPG to confirm that the 2027 production forecast would be the basis for the water conditions variance account for the entire term. And then in the response uh OPG uh confirms this.
And so I I would like to kind of build on Miss Lee's question about the um upgrades or improvements to the production forecast.
And I just like to generally confirm whether any of those upgrades that were discussed with Miss Lee are affected by water flow. Like could do changes in water flow affect affect any of those items that were discussed with Miss Lee?
Yes. Any production increase resulting from capacity or efficiency increases would be impacted by water flow.
>> Okay. Thank you. Um and then the other thing that Miss Lee kind of asked about was was capacity increases. And so I'd like to confirm OEB staff's understanding that under the water conditions variance account, for example, how we discussed Otter Rapids, if there is a an actual increase in the capacity of a hydroelectric generating station, but that's not reflected in the production forecast that underlies the water conditions variance account. Is it correct that the variance account is agnostic to that change? like it can't capture that variance.
>> I would agree with that statement.
>> Thank you. And then the other variance account that's listed here is the surplus base load generation variance account.
So again in the most general terms at the resolution I just asked if there is a if there is an increase in the capacity of a generating station would this variance account capture it or would it be equally agnostic as the water conditions variance account?
the SBGVA methodology would capture those increases just based on due to different methodologies and used in terms of calculating those amounts.
>> Thank you. The third um item that's kind of listed in the response is the changes of laws deferral account. And again trying to just understand at a general basic level how could how could changes in law affect or be an input into the production forecast.
Can we turn up uh exhibit H111 page 61?
And I'm not sure if you need this reference uh Mr. Armenovitz, but uh we do give an example in exhibit H of a potential change in law. Sorry, I will wait for this to come up.
That's perfect. Thanks. So you can see on line 16 there's discussion around uh changes potential changes to endangered species acts and continuing on in from line 25 potential changes um there and and through that discussion this is potential impacts on OPG regulated hydro stations and there could be some potential on uh impacts on production in that Thank you very much. That's that's all that I have.
>> I think we're moving. Thank you, Mr. Emanovich. Uh we're moving now to Ms. Zu. Um who I see there. Tina, would you mind introducing yourself? I'm not sure if the court reporter has caught that yet.
>> Keep it really close to your mind.
>> Thank you, Mr. Miller. My name is Tina Zu. I am a senior advisor at the Ontario Energy Board. I have a few questions.
They're relating to the hydroelect electric FTEES and the project OMA.
First, could we pull up F1 staff 164 please?
So in the preamble of the interrogatory, OPG states that hydroelect electric overhaul projects are typically required every 25 to 30 years.
And now could we move to interrogatory response chart one?
So on the chart is showing the overhaul project OMA spending.
The spending is showing a upward trend since 2021 and the trend is keep going all the way to 2027.
Uh so it's going for seven years so far.
My first question could you explain what is the time duration for OPG to complete this round of overhaul projects because it's been going for seven years and uh it's happening every 25 years. So we want to understand the pacing of your overall projects.
Uh, if I could refer you to D112, sorry, uh, sorry, D1 staff 311, please.
Uh yeah, that's uh D1 staff 311.
My apologies.
So if I just refer you to lines nine and 10 uh we uh describe that overhauls are typically required every 25 to 30 years.
So um and we do this uh at a planning horizon that to sustain the reliable operation of turbine generator equipment and and related systems. Um this is in line with effectively what you'll see in industry guidance from external third parties seat uh that's typically the planning horizon when you think about um hydro assets.
So when you look at the fleet um and you look at the the nature of the program, uh we have um 207 units operating across the province in over 50 stations.
In this rate period we have coming up, we're doing roughly 53 units. So just sort of rough math, uh we're doing about a quarter of the fleet.
Um so this is a rate case of 7 years. So again, just to kind of extrapolate it out a little bit, um if we're doing a quarter of the fleet in seven years, you could make a reasonable assumption, you do the entirety of the fleet over, let's call it 28 years, 30 years for convenience.
So we're entering a phase of refurbishments but in reality if if our objective is to sustain the reliable operation of turbine generator equipment and related systems effectively the cyclical nature of this investment is should continue. So the question of when does it start and when does it stop is somewhat of a moot point. There'll be periods of more activity and periods of less activity. But I don't think I could say on day X it started on day why it stops. It's somewhat continuous in nature.
>> Thank you for the explanation. Uh because OPG doesn't provide the project OMA detail beyond 2027.
So based on your response, I do want to better understand if you anticipate the overhaul project OMA continue to show a high spending trend in 2028 all the way to 2031 because this relates to the fundamental of how the hydroelect electric payment is set.
I'll uh I'll pass to my colleague, Miss Hannon.
Thank you. If you can refer to IR A1 SEC012, it provides the total project omn uh for 27 to 31.
So, thank you for pointing this out. uh because I guess my question was more specific about the overhaul project OMA.
I believe here is the uh high level project OMA. Um yeah, but if this is the level that you provide um I understand.
>> Thank you.
>> Okay. Uh and now could we uh continue with the same interrogatory? So that's F1 staff 164. Um I want to look at chart two.
So the chart two is showing the refurbishment project OMA spending. As we can see on the chart, the spending was very immaterial up until 2025.
And if you move to the next page, please.
So suddenly in 2026 and 2027, OPG is anticipating a increase in refurbishment project.
uh in the same interrogatory response OPG responded that for the removal costs to remove the existing assets they are treated as OMA costs. Um so I do want to uh understand if you could clarify the reason for refurbishment project OMA increase in 2026 and 2027 is due to the increasing of the removal costs of the existing hydro assets.
>> That is correct.
Uh could you further explain compared to prior years uh say between 2025 to 2026 it's only one year difference but why within the one year the removal costs that would be treated as OMA in refurbishment projects suddenly increases for over 10 times.
So the significant increase that you see in 2026 and 27 is directly tied to the execution phase of our major refurbishment pro. So when they start the execution that's when the demolition and everything starts. So currently uh in 2425 we're we're in the planning we're in the development stages of of most of our larger refurbishments where the bigger dollars start towards the end of this year and into 2026.
>> Thank you for the explanation cuz I do understand that the hydroelect electric business has started refurbishment work since 2021.
But if we look at the actual refurbishment project OMA uh the spending was very small uh from 2021 all the way to 2025.
Would that mean in the prior years there was no project moved to execution phase of the refurbishment uh project work?
>> No, that's not correct. there would have been definitely projects that were in execution. The the cost would have just been minimal.
>> Yeah. So I I think that's part of the um the question that I wasn't sure um prior year versus now versus a year later why the asset removal costs suddenly increase so much. Um would you would you be able to uh clarify whether there is a portion to do with the labor cost increase or uh anything to do uh beyond the the workload itself like any market market factors here?
>> No, I wouldn't say that labor is a component of it. It is more uh the amount of removal that we're doing. So, as we're going to into these large uh refurbishments, for example, the Saratom Beck where we're doing s significant refurbishments or uh our redevelopments, we're we're removing a significant portion of that equipment.
>> Thank you. And now I want to look at F1 staff 174, please.
So in this interrogatory originally uh the OEB staff was asking if OPG could provide a breakdown between the inflationary factor and the uh workload factor that could explain the project OMA escalation year overyear. So in the in interrogatory response, OPG is saying that the project OMA costs attributable to market inflationary related impacts cannot be isolated.
So based on OPG's response, I further explored your pre-filed evidence from exhibit A2, tab 2, schedule one, attachment two.
and page 10 please.
Uh I think I'll say that again. So that is exhibit A2 tab two schedule one attachment to page 10.
So on the page 10 the table showing inflation assumptions on the right side funding area OMA OPG is saying that the inflation is indexing based on existing contracts or supplier estimates or 4.5% if estimate is not available.
So based on the assumptions that OPG made in the business plan uh versus the interrogatory response in staff 174 I want to further clarify how OPG determined the 4.5% as the project OMA escalation and uh how much of the regulated hydroelect electric project OMA labor uh escalation year overyear is based on the 4.5% versus is based on the existing supplier or contractor's estimate.
I think I get what you're asking. Uh okay. So the 4.5% escalation for procurement was provided through um uh an analysis that was done through our supply chain team. 4.5 was determined to be a reasonable estimate uh across the board. If you do look at uh IR F1 staff 177, it does speak to very specific um indices that uh are impacted in the renewable generation equipment procurement.
This percentage uh has been applied in the business plan on our purchase services. our labor has been uh done separately. So I don't have in front of me the breakdown specifically between labor procurement material etc. >> Thank you for the answer. And now I have a couple of more questions there to do with the FTEES. Uh first could we go F1 staff 172 please?
In the interrogatory response, OPG is saying that the 2025 budget versus actual regulated hydroelect electric regular and no regular FTE that the actual is lower than budget by 98.4. for my first question.
Could you provide which job functions are currently understaffed and what's the impact to 2026 and the 2027 business plan due to the actual FTE are behind budget?
Specifically, I want to understand for those jobs that are currently under budgeted uh underst staffed are they mailing to do with the jobs in the day-to-day operation at the hydro station or they're to do with the project works that hydro business is picking up uh over the over the last few years. Thank you.
Thank you. I'll start and then I'll pass it over to Mr. Pender to to finish it up. So, out of the uh 98 FTEES that we are under for 2025, approximately 20 of those FTEES relate to base omina work.
uh out of that 20 FTE there's about 18 that uh we're under in the engineering uh job family specifically the remaining 78 FTEES that we are under is in our capital uh both project omen and our capital portfolio a lot of that was um intentional as some of our project timing and schedules were delayed and deferred therefore we made the the intentional decision to uh hold off on bringing in those FTEEs until the projects were fully up and so I will pass it on to Mr. Pender now to speak to uh I think your second part of the question was the the work program.
Thank you.
So I think uh Miss Hannon's described the uh the capital impact. So roughly sort of 60 FTE so call it 2/3. Um from a base perspective um uh really in in two areas uh it it's had an impact. uh we talked about predominantly in engineering is where the unridge is um and and that's really on our equipment reliability program. So uh we we talked this morning about equipment health monitoring um e- health ELCM um and providing support to stations. Uh we've we've we've not we've focused on our largest stations at the outset and really the the slight temporary delay uh receipt of those staff is um just slowed up the roll out to other station sets.
So predominantly from a from a um an operations perspective um it's had an impact in and what we call our excellence plan uh which is uh really a set of criteria in our business of how we're focused on getting better.
Um and that the reference for that um is F1 SEC 151. We we don't need to go there but I just wanted to uh just put it on the record. So really it's it's really about our drive for excellence. um just some of the challenges of bringing in the engineering staff um means we haven't done it quite as quickly as we would have hoped >> and thank you for that answer uh cuz now it's mid 2026 and OPG filed in the pre-filed evidence of its original 2027 plan in the OMA FTEES and the capital FTEES as a undertaking request as would it be possible for OPG to provide a updated 2027 FTE plan breakdown into the OMA FTE and the capital FTE that would incorporate the reality that the actual FTEES currentling at the hydroelect electric business is below the original budget and the original on.
>> Can I just clarify your ask? Is it to restate what you you're believing we should change our plan to or is it giving you what we have as of today? So uh since the last time we heard from OP that was the time when you replied the interrogatory at that time the actual FTE was still behind the 2025 budget and because now we are halfway through 2026.
So I believe it will take time for OPG to hire FTEES that will be able to reach the original level that you guys uh budgeted as 2026 and what you planned for 2027.
Uh according to our conversation just happened now it seems that OPG is potentially holding back some of the hirings until later when it's mature. Um so based on all these conversations I'm wondering I if if it's necessary for OPG to provide a updated 2027 plan for the hydroelect electric FTE into the OM FTE and the capital FTE that reflects the reality. Okay, >> sorry. Can I Miss Hannon, maybe I can offer perhaps we can take an undertaking to explain how we are going to catch up or the expand further on the explanation that you and Mr. Pender provided and perhaps we can give maybe a current view on the current FTE levels, but I don't believe a reforcast of the 2027 amounts um we will be doing.
>> Okay, thank you. I think that's a reasonable uh undertaking. Thank you. Uh that'll be JT 1.14.
>> And uh I have last question. Um could we go F1 CCM MBC 002 please?
I want to look at part A of the response is showing that regulate regular stuff in capital increased by 188.6 6 FTEES.
In my understanding, capital FTEES work for projects and the projects are defined as temporary in nature.
And if this is the case, could you explain why the 188.6 FTEES were hired as regular FTEES? If that means OPG's intention is these additional capital FTEES will be kept in the hydroelect electric business on a ongoing basis after the project work concludes.
So, it was decided to bring in these uh 188.6 FTEES uh full-time because as Mr. Pender mentioned before, we're we're starting on a very long uh refurbishment program where we have regular full-time FTEES.
uh the benefit that can be provided from using the same staff on sequential units is is deemed to be more beneficial than bringing in temporary employees uh that turn over every two years.
>> Uh could you elaborate when you say OPG is anticipating a long term of refurbishment work? So how long that time duration will look like?
>> Uh maybe we could refer back to the record 30 minutes ago uh where we talked about the construct of uh when the program starts and finishes. I said it's very hard to define when it starts and when it finishes. It's somewhat continuous in nature. Um we talked about we're doing roughly a quarter of the fleet in the next rate period. Um and we extrapolated from that that if we do a quarter in let's say sort of seven years it's not unreasonable to say in about 30 years we would do the whole fleet and then we talked around the planning guidance from seat and the US uh army corps of engineers that about 25 to 30 years is a sensible planning horizon for refurbishments.
uh to build off Miss Hannon's question um it's reasonable to assume um subject to asset condition as we spoke about earlier that we would be in a cycle of refurbishments and again we're really doing that to um if we refer to evidence here on page 30 so line 34 our core objective is to sustain sustain 1500 megawatts of the existing regulated hydroelectric freight um from a capacity perspective and add an incremental sort of approximately 50 megawatt.
So on the assumption that we are going to meet that strategic objective, it's a reasonable supposition that having um regular FTE uh we think is a more prudent way of driving out efficiency in our projects over time as opposed to having temporary FTE who will cycle through more regularly.
>> So thank you so much for the explanation. Um in the same response it's showing that the OMA regular FTEES increased by 173.3.
Um in the response narrative OPG is saying that uh it's on the third paragraph of the response it says the 173.3 increase reflects the addition of personnel across project management operations maintenance engineering as well as address the recommendations from the auditor general's 2022 into value for mounting audit.
Um my first question could you explain how many of the 173.3 FTE increase is supported by the auditor general's 2022 value for money audit.
I I I can't do it specifically because I don't have the information to hand but I'd happily give you generalizations if that's helpful. Uh so why not if we could take it as a say under taking request if you could provide the specific section from the 2022 value for money audit report um that's showing that the recommendation is OPG needs to add certain personnels into the hydroelect electric business to support its ongoing operation. uh things like that if that's possible.
>> So we we can turn to the audit general report and look at the recommendation.
Uh but that report does not specify a specific number of FTE to go and do an activity. So that that wasn't a recommendation from the AG. There was a recommendation uh to address backlog and work deferral.
um we can pull it up if if needs be to go and look at the specific recommendation but it wouldn't give you the exact number of FT required to do that. That would have been a decision from within the business to meet the requirements of that recommendation.
>> I see. So the recommendation is a general recommendation then OPG uh came up with its own analysis and hired uh so many FTEES coming on board. So is it possible that as an undertaking you could provide more reasonings on how you determined that you needed to hire 173.3 FTEES as OMA and 188.4 FTEES as capital over the last a few years. um that be able to address the recommendation saying um that OPG needs to catch up with the backlogs.
So the auditor general came in in 2022.
They did a 2024 um follow-up, a check-in. Uh we haven't completed the 5-year review of that process with the auditor general. Um so I I'll leave it to our council to guide whether we can answer this question.
So, if I understood your question specifically, you're looking for a a more detailed explanation of the FDA increases that you took us through and um sort of how they're connected to the auditor general's recommendations and being able to to implement those recommendations. I think subject to the qualification that some of that work is ongoing we can on a best effort undertake provide additional explanation.
>> So um I think right now because we are deter payments for the next five years.
So we want to get enough information and the evidence that's supporting the FTEES that you put in the plan in 2027 and uh that plan is built on what was the actual FTE that's building up over the years. Right.
>> Understood. So you're looking for not just the the auditor general but sort of a a more wholesome explanation of all the drivers behind those >> FD. Yes, >> that's JT 1.15.
>> And that's all of my questions. Thank you so much.
>> Thank you, Mu. I I think we're almost done, but I think one question got punted away from this panel and then perhaps punted back to Mr. Amanovich.
So, over to you, >> Thomas Emmanovich, Ontario Energy Board staff. Um, yes. So, with the benefit of uh side discussion, I'm I'm back. Um so I've been asked to revisit uh my question that I was having uh with the panel about the details of some projects and the components of of refurbishment projects. So I think uh especially for me to help kind of jog uh my memory if we could please go to exhibit D112 attachment one tab 8. So this should be the auto rapids G1 overhaul and refurbishment.
And in the recommendation section for this project, uh we were generally talking about uh maintenance and operating costs uh relating to the Otter Camp and and the road. And uh so I guess to to kind of pick up where we left off, I just wanted to confirm how how common is it for a project to overhaul and refurbish a generating unit like this as an example to include work that is not directly related to the actual like generating equipment.
I'm not sure I can answer how common, but I can give you some context.
So, Otter Rapids is, as we discussed earlier, uh, broadly in the middle of nowhere. Um, so if we want to bring large equipment to site, um, you either choose road or rail or water.
The only option here is road or flying it in. Um, so a prerequisite for doing this refurbishment work, uh, we're talking about heavy engineered equipment that's heavy and bulky. So to to commence that work, there will be activities required to enable staff to get to site, equipment to get to site.
Um provision of health and safety requirements. Um so in the case of Otter Rapids, this is the camp, the road, the staff are all necessary to undertake the the um the refurbishment.
>> Yes, thank you. that's certainly helping um my memory. And so what I think I had kind of asked as a followup was relating it back to the eligibility of a project for the capacity refurbishment variance account. And I thought I had understood that the the assessment at at the very least could or generally is done kind of at a detailed level where components of the project could be assessed for whether it's it's uh eligible for varianc treatment. And I had asked uh for some sort of summary or identification of the projects in the IR term. So in 2027 to 2031 where there would be examples of subcomponents where certain portions of a CRVA eligible project may not have like those certain subcomponents eligible for variance account treatment.
So I I assumed I was asking for an undertaking for the period and if there was none in the period I was asking for just any general example to understand how that happens. Thank >> thank you. So I don't have that in front of me so I will have to get back to you on that. Um, typically what we would do is look at the scope of the project and then determine the eligibility for many of the projects that are in our plan currently. They are unallocated, right? So, the scope hasn't been fully defined. Uh, and we're just taking it as a a general assumption that it is eligible. Um, with I can take that back though for you and get an answer.
>> Yeah, thank you. I'm just looking for examples of projects to just illustrate how how that comes about.
>> Thank you.
>> The undertaking is JT 1 16. Um could we have a a recitation again of what the undertaking is for? Yeah, I was asking for examples of projects that are identified as eligible for capacity refurbishment variance account treatment where there are components of the project that are not eligible for variance account treatment.
And if there are none in the proposed term or the plan that's presented, just any example from the past, if there's nothing that's easy or available in the future term.
Okay. And so the the kind of followup that I had uh on that was related to just the the idea of the generality as Mr. Pender was explaining the beautiful yet remote part of the province where Otter Rapids is. Um in exhibit D112 table one which is where we have kind of like the list of projects we have I think almost or just over $4 billion of capital expenditures summarized I think that's column I as in India and then in column M as in Michael there's I think almost two half billion dollars of capital and service additions for these projects and I was Wondering if OPG would be able to somehow give a sense of the proportions of like these amounts where there's project work but where the actual tasks are not directly related to generating equipment.
So I'll I'll kind of take a step back.
So we talked around Aguasan this morning I recall.
Um that's a surge tank to supply water to the generating facility to undertake its intended purpose to generate power. Uh we've got dams that hold water to provide fuel to the stations to create power. I I think you can see where I'm going. There is a system involved with generating power. So there is a turbine and the and it has equipment electrical that allows it to be distributed out. So for me if we if we want this product this product has a certain system requirement to have fuel do it safely leave site. So our work to do that is predicated on the function of power generation. Uh that's the business we're in. So I think we to to draw a distinction to say that is power generating that is not power generating is a highly subjective perspective.
Um so I'm not sure how to be helpful on your question. Well maybe if it's easier to just focus on the work that is easily attributable to the generating equipment however your judgment would interpret applicability to.
So for me generating equipment is equipment that's used to generate and then con inject electricity into the ISO system. So like a road even though it's necessary for the project to get to bring the equipment is the road itself is not equipment required to generate energy and inject it into the grid.
I would 100% agree with you. Can I give you an alternative terms of reference?
To maintain that station and to have it providing electricity into the grid, I need to get people to site.
Uh how I choose to get people to site is one of cost prudency. Um there are multiple ways to transport people. Road is a fairly economic means to transport people to a site. So we can there's delineations of directness and the orders of magnitude, how far you go back. Um, and I I I feel like I'm being difficult. I'm really not. I'm just trying to understand where do you where do you cap the system at this is power generation and this is something else um linked to safety systems, public safety systems, regulatory systems, environmental systems, all for the purpose of power generation because that's the game we're in. The delineation is a real problem for me.
I would leave it to your judgment of how to delineate like the physical thing that's used to generate and convey energy. I'll just leave it at that. Up to you if you think that's an undertaking you can take or I'll just drop it.
>> No, I don't I don't think it's a proper undertaking on the exchange we had. um you know OP OPG's position is that the work is eligible for CRVA if in the course of a detailed assessment something is identified as not being eligible as Miss Hannon called out you know that'll be brought forward in the normal course but to try to delineate at at this point in time on on some kind of distinction I I think would be unhelpful.
>> Thank you. That's all for me. Thank you.
>> Uh thank you Mr. Emmanovich. And I think that is it for staff. Uh we'll take our afternoon break now um for 15 minutes.
So till uh say 255 or so and then uh Mr. Rubenstein, you're up. Okay. Thank you.
>> Um Michael, it's Mark Garner.
>> Yep.
>> Now that we're off the record, um Michael, I'm going to have to um drop off sometime between now and probably your end of day. I don't expect I don't expect to be up the way things are going, but if I am, um, just move past me. Okay. I don't want to hold anything.
>> Okay. Thanks, Mark. Yeah, it looks very unlikely you'll be a anyway.
>> Okay. I'm here for >> here for a bit, but I'll drop off at sometime before 5. Okay. Thanks.
>> Thanks, Mark. Bye.
Uh Christopher, are you there and ready to go?
>> Yes sir.
>> Okay, great. Um I see everyone is back. So uh let's get started again. Uh good afternoon everyone. We are moving now to Energy Coalition. I believe it's actually you uh Miss Scott who's going to be doing most of the questions.
>> Yes, I am. Can you hear me? Okay, >> I can hear you. So, over to you.
>> Thank you.
Um, though, uh, staff did cover some of our questions. I would like to return to D1 SEC041 if we could.
And in the response, part A says uh OPG assesses asset condition through its equipment health monitoring process for the hydroelectric systems, structures and components provided in attachment one. And attachment one is a health monitoring and reporting procedure.
And then in part C of this response, it states condition assessments are documented in multiple ways.
Historically, this has at times included plant level assessments that addressed a broad range of equipment and were not prepared for project specific decisionmaking. So maybe if we could go to that attachment one and page 8 of 23 and right under report generation and format it refers to these plant level health reports.
So maybe can you explain what these reports entail and if not for project specific decisionmaking then what are the these reports for?
This is Nicole Fabro. In response to your question, the plant level health plant level health reports um essentially would be a summation of the um assessment of condition of major components inside of the plant. And as part of this new process that we are in um varying stages of implementation um on an annual basis, the engineering team will sit down um with the plant leadership staff and review um based on a myriad of information um an assessment of the health of the major components of the plant. With that being said, um I would like to distinguish that engineering will provide an assessment of asset condition and based on that asset condition um the engineering will also recommend uh short-term and long-term mitigating actions and as I have re or as I have noted previously on the record based on those actions in some cases a a greater investment may be required to address the asset the asset condition. Um this is at times distinct and separate from a projectbased risk assessment. And I also noted uh in prior uh discussions earlier today that at times in order to manage some potential project risks uh decisions need to be made around the appropriate scope of work to be included in a particular project. So that would be my best response on how to delineate between the two.
So I think on that same page it talks about these reports being provided to the regulators. So I'm assuming the regulator is the Ontario Energy Board or is it referring to some other regulator?
I do not have the list of the regulatory bodies that is referenced in page eight of 23 in attachment one in front of me.
Well, um, what we're going to ask for is that could you provide us with the plant level health reports for the stations related to the renewable generation projects greater than 30 million both for those projects that have been completed um before the work was done and the impending projects >> as I have noted previously we are in varying stages of implementation of the health monitoring and reporting software. However, uh what I can provide is a representative example or sample of what a plant health committee um I guess slide deck would look like. Um and and that would be in reference to one of the projects listed in SE 41 attachment 3.
>> Okay. So maybe if you could if for the projects that are listed in attachment three where you have that information provided to us I guess because the one you know you have provided us with attachment three um but it's very in some ca well it is very high level. In some cases, you know, the condition of the stator is poor to good, which doesn't really tell us.
Um, sorry, Miss Scott. Just trying to get some instructions here. Um I think as we heard from Miss Fabro um we can provide you a representative sample but I we're not at this time we're not prepared to to go through that entire list there and and sort of go through it and figure out what is and isn't available. So we'll give you a sample so that you can look at the the rigor of the information um but not able to do the whole thing. Sorry. Can you Why not?
If they're for just to be clear, these are for project these are for the plants where as I understood the evidence because you're implementing this, you'll have it for some plants and not others.
Is that my understanding?
>> That's correct. As I noted previously, some of these projects were initiated before we implemented this new sort of live system, if you will. And as a result, um, I cannot confirm that a full plant health condition assessment in the new system is available for every single project listed in attachment three.
>> Yeah, sure. And I I guess our the question the we're asking for is for the pro the projects that Miss Scott discussed on that table where you have those reports are available to provide them. I mean a representative sample is not really that we're looking for the actual information. So at this stage representative sample is not to be frank not much it's not very helpful.
Sorry, this is the court.
>> Sorry, court reporter, you were about to jump in.
Uh, Mr. Rubenstein, we will take away that request to consider.
um we we'll still provide the the representative sample um that we committed to but going beyond that at best what we can do here is to take it away and consider it but I can't commit to to actually providing information.
>> Okay.
>> Uh the under is JT1.17.
Uh I just want to check in with our court reporter to ensure he's uh still here. Are you with us Mr. Siddle?
>> Sorry I this is the court reporter. I've just been reconnected to the session. Uh I was disconnected there momentarily.
>> Okay.
>> What we can do is I think there there there was a brief back and forth about an undertaking, but what I think makes the most sense is for Mr. Rubenstein and Miss Coban to restate what the undertaking is and then unless you lost more than a minute or so there then I think we can just proceed.
>> All right. Thank you. That's perfect.
Please do that.
>> Okay.
Uh Miss Coben, do you want to try to summarize the undertaking?
>> Sure. Um for um the information in SEC 41, um we will provide a repres representative sample of the um health condition report and we will consider if we're able to provide anything further than that.
sample and if we can we will and if we cannot we'll explain the basis for the refusal.
>> It's JT 1.1.7 >> and just so the records clear the request that the second part there that SEC is seeking is the plant level health reports that do exist for all of those projects.
So the dates on this procedure are PDF creation date of the of 2021 1201 and a compliance date of September 1st 2022.
So is this the first version of this procedure?
I do not have that information in front of me.
um if you could undertake to tell us because my second part of the question is was this produced in relationship with as a result of the auditor general's value uh for money audit and in response to the um recommendation that said OPG did not always assess the conditions of its hydroelectric stations and address engineering recommendations on a timely manner.
>> Again, similarly, I cannot confirm or deny um any relation to the auditor general report in the institution of this process at this time.
>> Can you undertake to tell us if there were previous versions of this procedure?
Yes, I can undertake to provide confirmation of any prior versions of this health monitoring and reporting procedure.
>> That's J JT 1.18.
>> Thank you. So the um in the followup to the auditor's general's report it said it OPG stated that they had reviewed the completion dates of the plant condition assessments for all 66 well I guess the auditor general had re reviewed that and found that approximately 20% did not have plant condition assessments completed in the last 10 years.
Do all 66 of the stations have PCAs done now?
Again, unfortunately, I do not have uh direct confirmation in front of me as to completion of a PCA for all 60 federal.
>> Maybe we could add that to the previous undertaking.
I can undertake to provide an assessment of the status of the PCA completion for all 66 hydroelectric stations today.
>> Thank you >> for regulated hydro.
>> Yes. Yes. Yes.
Um so attachment three staff asked about um when assets that were rated as fair or good were replaced and you did respond that there reasons why there may be reasons for doing that. Um I just take this one step further. Is does OPG have a process where they can cost the sort of cost benefit of replacing fair to good assets under a sort of a global outage versus maybe doing it later on.
What I can confirm is as part of the project management process that we follow and as part of the early phases of planning a project, as with any project, uh we will assess risks. s associated with the overall project. And one of those risks may be um concealed conditions or the risk of finding a greater degree of than perhaps what what we could have planned for. And um that process that we follow to uh further define um the total scope of the project is provided in D211.
In addition, I would like to highlight um and if we could please go to D1 staff 311, please.
And if we could specifically go to starting at line item 37.
Thank you.
So in this undertaking or sorry in this interrogatory response, we provide a series of factors that are considered as we move into the planning of a turbine generator unit uh overhaul or refurbishment.
and we identify assessment of risks and a series of bullets on page three of five lines 3 through 12. So these risks as I mentioned are assessed as part of the project planning process by a combination of engineering as well as plant staff and project management staff.
So does that and I include the risk of replacing perfectly good assets.
I I understand. I saw the the concealed I understand the concealed condition, but the idea of replacing a good an asset in good condition that didn't need replacing and the increased cost of doing that early.
the project teams in conjunction with support from engineering would assess the risks versus the benefits of making that decision as part of the overall project scope.
>> Okay. Maybe could we ask and it for one of the projects and maybe um the um Conniston Stinson project back on that the attachment three if you could sort of um provide us with a a breakdown of the cost between um fair to good assets being replaced versus um poor or unacceptable assets being replaced.
I think part of that comparison is already done in the business case for the reconnaissance in project in exhibit D112 attachment one tab five.
So in that BCS it presents a number of different alternatives. So the preferred alternative is highlighted there um with new dive units which is a type of turbine and generator units and also compares that to alternative four which is red redevelopment of both sites with new saxo units. So as part of that description, it compares how the new technology which would necessitate replacing some of the equipment in the SEC 41 attachment that may be rated fair with new equipment is due in part to this new the new technology that's being installed at this site and the cost benefit of doing so is highlighted between those two alternatives.
So, does that include replacing the power trans the transformers which were rated good?
>> That's correct. The existing power transformers weren't compatible with the new dive turbine technology.
>> Okay. Well, I we will have a look at that and see and uh thank you for that response.
Um I have some questions related to prioritization of projects. So if we can go to D1 sect 43 and in that um when we asked about the renewable generation turbine generator refurbishment pro program and we referred to D21-1 one. And so looking at page 413 of D2-1-1 under project selection and prioritization and it says produce a priority Prioritize list of candidate projects for inclusion in the business plan within unallocated capital projects and project OMA subject to the business planning um approval process.
So could you explain how allocated capital projects fit into then the prioritization process?
So as we conduct the prioritization process as part of our business planning function, projects that already have a business case approved in the form of allocated projects, they are at the top of the prioritization list essentially.
Um they are mustd do within our prioritization process.
>> Okay. I did I did actually see that in um because you did also refer us to um I think it's staff 3 11 and I was going to ask about how so if you if a a project that has a business case approved that must how could you not then approve more than the funds that are available. I'm I'm guess I'm within the projects that are approved.
How do you prioritize within those?
The projects that already have a business case approved are prioritized first and then remaining capital is then prioritized amongst the unallocated project.
So if there's a capital envelope for a certain year, the ones with approved bins, Mrs. um cases go first.
Is there a risk that that is going to be more than the capital envelope?
I guess my question is, is there a master list of all the projects and a priorit prioritization of all of those projects?
I guess there were two parts to your question there, Miss Scott. The first part with the scenario where if we had a capital envelope that was less than our allocated portfolio, then we would work with our allocated portfolio to manage it within our capital envelope.
And in your second question related to is there do we have a list of projects? We do we do provide in our our evidence a list of the allocated and unallocated projects, >> but as far as I could see, there's not a prioritiz they're not ranked in a certain order.
And maybe I can ask this in another way.
Um my understanding is you're using the copper leaf 55 program.
>> That's correct.
So based on experience from um other you know uh distrib uh utilities uh distribution utilities is the copperly 55 produces a score and they can provide us with a list that has a score for each project.
Are you able to produce something similar to that?
>> So, copper leaf is used to help us value our potential investments and we it's used to help us prioritize as you said our our selection of unallocated projects. So we did provide that list of unallocated projects along with their score in IRD2 AMCO2 and Lori perhaps you can bring it up.
>> Is that the value framework one? Yes.
>> Yeah.
>> And that was actually going to be my qu one another question is is the copper leaf score the same as the value framework? um >> the copper leaf tool. We apply our value framework and use the copper leaf tool to help perform those calculations to come up with that asset and investment net value that is highlighted in the table that we use to help us prioritize our unallocated investments.
But only the unallocated in investments.
The allocated ones have an approved business case and they go first. Is that what that's what you're saying?
>> Yes. In case of the in the case of the projects that have an approved business case, they they are prioritized and um they don't form part of the list that we provide an attachment one.
So maybe if could we pull up the um AMCO 22 spreadsheet just so that I can make sure that I understand the what the numbers are saying.
So there's a net benefit.
Maybe someone could make that just a little bit bigger so we can look at it.
Yeah. Um and go to the far right. Yeah.
So there's a net benefit score and a um in dollars and a cost in dollars. Correct.
Yeah, the net benefit score is is really a value the value of a summation of the value of the mitigated risks um with the cost of the investment uh netted out.
>> Okay. Is that is that similar to a copper relief score then that net benefit score?
Yeah, that net benefit score, that's the score that we look at to help us prioritize our unallocated portfolio.
But I should add just for context like we do use copper leaf as a tool and these scores to help us prioritize. But we do take into consideration other constraints that we highlight in more detail in D2 M code 23 resourcing um scheduling considerations environmental requirements and so on and so forth. So the score does kind of form our our foundation for our our prioritization.
the unallocated portfolio, but there are other considerations as well.
>> Okay, thank you very much. Um, if we can maybe move to um, well, I don't know if we need to pull it up, but A1CCC um, 009 in attachment 11 is the um, renewable generator generation turbine generator overhaul pro program.
Um, and that was an internal, as I understand, an internal audit of that program.
and it referred to RGP proc um a hydroelect electric optimization procedure document. Has that been completed?
Could we just scroll down to which page and line you're referring to in this attachment?
Oh. Um, let me I don't have the page.
was in one of the um recommendations.
You just scroll through that document.
Um findings I'm sorry I don't have the page. I don't know which p um well in actually if you go to um A14-1 attachment 4 which was a summary of the internal audits and it says management will continue to develop the hydro Electric optimization procedure document.
>> Sorry, Lori. Would you mind just scrolling down?
>> Yeah. Attachment 4, page 38 of 89.
No, that's Uh there there. Yes, right there.
Management will continue at the top of the page.
Could you just scroll up one page please, Lauren? Just so I can see.
Sorry, I just scrolled down again, Lori.
I'm just trying to find the one that's referring.
>> Mi Miss Scott, just because we've been trying to dig up the references, would you would you mind just restating your question so we have that before us?
>> Um, has that procedure been completed?
And if so, is there a copy on the record or could you provide one?
If there's not and just for our clarity, Miss Scott, we we had started on this exchange talking about um the overhaul program, but I believe this audit that you're taking us to now is related to a different topic.
Just want to make sure we're not getting confused.
>> Right. This is on the turbine generator overhaul program and >> no the a you pointed us to is on the generation revenue planning. So the the reference you're pointing us to is related to a different scope.
Sorry. Um, page. Oh, I'm sorry. Yep.
That was Well, I guess I'm I just I'm still looking for the RGP pro-00001 hydroelectric optimization procedure document is what I was looking for.
I think with without a reference it's it's hard for us to to really understand if that that is a an undertaking we can give you. So perhaps you could come back to us with that reference and we'll consider the undertaking.
>> Okay, I will do that then.
>> Thank you.
>> Okay. Um if we look at the summaries of the internal audits and um specifically related to maintenance and work orders. So in the internal audit um I think 20-9 renewable generation and power marketing asset management and maintenance followup.
The finding was that a significant number of maintenance work order tasks remain backlogged and the 2211 there was a recom that there was a statement saying there's no formal documented plan to reduce work order task backlogs and there was a similar recommendation in the 2022 audit auditor general's um recommendation number three action Item one.
So in that um 2022 auditor's general's recommendation number three, the backlo of work orders was 9,500 at the end of 2021.
Um so my question is can we get an update on that? But related to that, my understanding um there's in the nuclear benchmarking annual report includes tracking of the backload of maintenance work orders. Is there something similar for hydroelect electric that tracks the maintenance work orders and and where the status of them?
Can I just verify uh recommendation number three from the AG report was to do with Ontario power generation and ISO. Could you just give me the reference please? I'm trying to track it down.
Yeah, I'm and I'm looking at um this is F1 AMCO090 the um followup on the 2022 performance audit.
And recommendation number four was to better monitor, track and complete maintenance work on its hydroelect electric generation fleet.
And that's where the the reference to the backload was approximately 9,500 work orders at the end of 2021.
So there's no page numbers on this. It's just it's item three. The aging of hydroelectric stations and equipment has led to a continuous backlog of work orders which could result in increased maintenance costs.
So, I I've just gone to the AG follow-up report from 2024.
>> Mhm.
Right. So then yes and there was a recommendation for on page seven of 23 action item one.
>> Right. That's the page I was looking at.
Yes.
So and I think it yeah it references a legacy position as of 2021 some 9500 work orders. Um uh the account from here was that recommendation for action item one fully implemented. Um and uh so we've reviewed and revised our work management procedures to ensure appropriate work prioritization and completion uh by due dates. And then it lists a couple of examples around work management um master data procedure was revised in June 2023.
And then uh the bullet below around uh work management, assessing, planning and scheduling procedure was revised in February 2024.
And I know uh that the AG had classified this as fully implemented, >> right? But my question was, is there an update on the number of the backlog of the number of U maintenance work orders and if a backlog if it still exists or not?
>> This is something I don't something we could undertake to provide.
So there's no there's no equivalent report to this as part of the hydroelect electric annual report or anything that includes tracking of the backload of maintenance work orders.
>> We we've established a methodology to track status. Um, and that was um that that was how well I I can't go into exactly how the AG made its uh fully implemented assessment, but we provided enough information to close out this action item.
>> But you so you cannot provide the number of the backlog of of maintenance work orders for hydroelectric at this time.
I >> I don't have it to hand. No.
Can you undertake to provide that?
>> For sure. Yeah, we can undertake to provide the volume of uh backlog of of work orders uh within the context of recommendation for action item one which is fully implemented. Yes.
>> Great. Thank you.
>> It's um for the record, it's Ian Richler. taken over for Michael Miller as moderator and we'll note that as undertaking JT19.
>> Thank you.
Um I just want a couple of questions about opening rate base for hydroelect electric and we don't have to pull these ones up but there were a number of um IR responses that confirm that the Timmans building expansion and the diamond machine shop or common capital and therefore part of the asset service fee.
So just but just to confirm that doesn't change the 2027 hydroelectric capital expenditure uh expenditures there's still 880.9 million as shown in D1-1-1 table That is correct.
>> And so there hasn't been any update to the rate base for hydroelect electric for 2027 if I understand correctly.
>> There would not be. No, those two projects were coming into service post 2027.
>> Okay. Um B1 SEC 028 attachment one which was one of the motion IRS um IR responses. It's an Excel spreadsheet.
Shows the conversion from capex to inservice capital. If we could pull that up, it's an Excel spreadsheet. Um, right. If you just scroll down a little, there's a line called rec reconciling differences.
Um, which I understand.
Maybe you can explain what that line is for.
Sorry, can you repeat that? You went a little blurry there.
Sorry. Um, so this is capex and then inservice and there's a line at the bottom reconciling differences. I don't know is that related to sea whip or what is that line representing?
That line is representing all capital expenditures that do not go into service during this period.
>> But there is a line in in service 2032 or later. So >> yeah, >> it's >> so it it's it's essentially if you look at our narrative, there was about 126 million that we called out that are is included in our capital that never goes into service. That's what that line represents.
>> And so how maybe you could explain that a bit more.
Why does it never go into service?
There were a few projects that we identified that had included contingency on their unallocated amounts in their capital expenditure. The directions were that those were that contingency was not to be put into service because we couldn't validate that it was going to be spent. So that caused the discre discrepancy of 126 million with no impact to the rate.
And so that spreadsheet, but um so if I sum up line 15 for 20 27 on that spreadsheet and get 836 and six.
>> Miss Scott, you're your sorry 41.5 million is in service.
>> Jane, it's it's Ian. You were you were breaking up a bit. I think the the sound the the we're having a bit of a tech uh issue. Maybe you could just repeat the question, please.
>> Sorry. So if I sum up the line of of capital additions for 2027 and get something lower than what is shown in um the total capital additions on other sort of another table can I assume that that's the difference is before 2022 >> yes you are correct. Okay, thank you.
Um, now I'm not sure that this panel is the place to ask this, but I will.
Um, H1 staff 260 attachment three table 1D, which again is part of the emotion uh IR responses.
It's an Excel spreadsheet again.
not. So it's H1 staff 260 attachment 3 table 1D.
All right.
Yep. Table 1D. Um, so there's a note six and that stating that the line is the total capital additions.
So, and we talked a bit about this before about only some projects being eligible for CRVA only applies to a subset of the projects. So can you explain how why the total capital is used in this calculation?
Yeah, Miss Scott. Um, this question ultimately will probably be better suited for panel 4, but at a high level, I can tell you that um, the reference to total capital is in relation to threshold methodology that we use for clearing the hydroelectric CRVA uh, over a 5-year period.
Okay, I did I did read about that, but I maybe wanted a bit more explanation, but maybe I'll save that for panel 4. Thank you. Um, now I did have some questions about one of the projects that exceeded 10% of its firstution business case summary project 82089.
Um, there's a number of references.
I don't know if we need to pull them all up, but if the business case um exhibit D1-1-2 attachment one tab 6 I don't know. Are we getting that pulled up or I mean I can proceed without it.
So my understand the initial execution release of 136.5 million um and project overvariance. So it was rebaselined to 145 million and then my understand then the superseding business case summary increased it to 167.5 so an increase of 31 million or 22.77%.
Now there is a um project change form 016 attachment five.
>> Sorry Jane, it's it's Ian again. Uh we have a really poor we have a really poor connection and you keep breaking up. Um, no, sorry.
>> The only the only troubleshooting trick I know is to maybe try turning off your camera, which can sometimes take up some bandwidth. So, can I can I ask you to do that and we'll see if it improves at all. Thanks.
>> Okay.
>> But just just just go back 30 seconds because we didn't hear any of that.
>> Sorry. Okay. There's a project change form D1 MCO 016 attachment five.
And in that there's a change in budget for project management and my understanding it says added.2 25 a a person.
We can see that. And an increase of 1.1 million.
So I was hoping someone could explain that to me.
So, Miss Scott, the addition as per the change description in that attachment, we added an additional 0.25 uh FTE to the project team which was which would triggered the contingency change amount.
Maybe that's so if if you could just blow that up a bit. Um, do they have my understanding there was one project manager, one project engineer and one senior business development officer.
And then the new budget is for one project manager, one project engineer, one senior project engineer and 0.25 25 of a senior business development. So I read that to be an increase of 0.25.
>> That's correct.
>> And and but that but the budget increased by 1.1 million.
There may have been some other details that went into building that contingency draw amount that's noted in the attachment, Miss Scott, but I don't have them in.
>> Can I get an undertaking to have provide further information on that?
Yeah, we can take an undertaking to on a best efforts basis rationalize what went into that contingency draw down amount that's noted in that.
>> Thank you.
>> Let's uh record that as undertaking JT 1.20. 20.
So, um, if we go to D1 MCO13, the project closure report for this project.
Can we just have that reference one more time, Miss Scott, please?
>> Yeah. D1 MCO13 attachment three.
And I can't see I can't see the page number but just um scroll down to the next page.
Yeah. So at the top there and it says the project was completed successfully.
Project was completed with an actual cost of 167.2 million under the approved budget of 167.5.
But as we saw earlier, the actual original um execution release was 136.5.
So my question I guess is how why is this considered a success and that it came in under budget but the budget was updated compared to its original budget. It came it was over spent.
So the key to identifying this project as completed successfully is related to the fact that the 167.5 million was an approved budget and the project cost did not go over the approved budget. So acknowledging that there was uh an overvariance and a superseding release but as part of our project management process the changes that merited that those two documents and those two approvals were justified in changes in the conditions of the project and that's how we concluded that the project completed successfully.
>> Okay. I think I'm I've used up my um time my part of uh sex time. So I will turn it over to my colleague Mr. Rubenstein. Um maybe if there's any time left at the end of after he's asked his questions, I might ask a few more. But uh >> uh thank you very much panel.
just have a couple areas that I'd like to discuss with you and I want to follow up on the discussion about unallocated projects and allocated projects and all and how the budgeting works and at a high level as I understood from your answers to OEB staff and Miss Scott there's a annual or over multi-year there's annual budgets you have allocated projects which are those that have an approved business case and then you have a certain amount of the budget that's unallocated that you then run a prioritization process and that you essentially draw from to um you draw from to then select projects then I assume also then have to go through the uh business case process and then they become allocated. Is that at a high level how this works >> in general? Yes. There we have a a capital budget that we figure out every determine every year. There are certain projects that are classified as must do as you alluded to and then after those have been prioritized the remaining investments um we prioritize with the help of copper leaf and the AINV and other constraints to um maximize the value as much as we can within the constraints of our unallocated portfolio.
So when you select a project or you prioritization process now for the to what I'm calling sort of bringing up projects from the the list the unallocated list presumably then they also have to go through a business case process. Correct.
>> Yes. Once one of the potential investment that's one of the unallocated investments when it reaches the milestone to go into a gate one it turns into a project and then proceeds through the project management process with our various gates to get to execution. But you do you do any what type of work is then done for the purposes of getting a project onto the the list the candidate investment list in terms of identifying potential investments. They follow our our asset management process that we describe in exhibit D211.
And so when investments are identified, we then score them using our value framework with the help of copper leaf to come up with that uh net benefit score that helps us prioritize our our unallocated investments to be included in our business plan.
>> Now in the business cases often you'll see alternatives and I don't just mean do nothing alternative. There'll be some alternative solution to the issue. I have that right?
Yes, alternatives are often identified in our business case.
>> Now, that's at the business case, but now we're before we get to the business case, we're entering in investments into the into copper leaf. Is there multiple candidate investments for each of those alternatives or is you you've already or are you making that selection and then the project enters properly?
So the potential investments address the asset condition and the associated risks and working with our engineering group and our operations group they identified short-term and long-term mitigating actions and those recommended mitigated actions are which we translate into potential investments in copper leaf. So each copper leaf our our preferred investment is what you're kind of talking about. That's the one that we score in copper leaf for that particular investment.
>> So I'll just give you a a hypothetical just sort of at a an abstract layer.
There's sort of a there's a potential issue and you have two options. One is a more expensive upfront investment but it will last longer so to speak or a um you know a less costly investment but obvious will last the solution will be shorter in duration right those are two alternatives something like that sometimes you see in your business case want to understand for the purposes of the the copper leaf are both of those put in or are you making a determination over some analysis of which one of those is preferable and it enters copper leaf.
The alternative that's entered in copper leaf there is it's the this is the alternative for that investment to address that asset condition or risk the that selection of the alternative to be put into copper leaf is based on the discussion with engineering operations.
Once a project or a potential investment proceeds into the project management process, we do review those other alternatives or potential other alternatives um in through the project management process as well and the BCS's that you talked about earlier.
So you look at it twice so to speak once it's sort of scored through the value framework and then at the once you've sort of selected the project from the list to be allocated and you go through the BCS process you look at it again when potential investments are identified the scope is very preliminary and so as the scope and costs and other mature through the project management processer alternatives are often assessed and uh to to ensure we've selected the preferred alternative which may have been refined through as we progress through gate one gate three that scope and details are al are often refined.
Okay. Now with respect to the the list of projects I think you you mentioned in D2 AMC code 22 I think it's attachment one there's the list of the value framework outputs and I believe those correspond to the list of or supposed to or some variation of the the list of unallocated projects.
Do I have that right?
>> Yes. The list in attachment 1 D2 AMCO22 this is a list of the unallocated projects that were included in our business.
>> But the list that was prioritized to get to that is longer. Do I have that right or is that every potential investment?
>> We have potential investments that were not included in this. Can you provide a revised version of this table with all of the investments and then indicating which ones are in the list that's in the application and which not which were obviously not selected for whatever reason.
>> No, we're not able to provide that. I I think we looked at this issue as part of um AMC code 23 um in in the resolution of our motions. Mr. Rubenstein.
>> Well, I'm just understanding from this what I look I'm understanding from today's discussion how this works. I was was not clear at the time. So the list is long what you're I understood here there is a larger list of potential investments that you've done some work on but you haven't selected I'm not sure and so we're going to ask if that could be produced >> no >> and what's the basis of that >> well the first basis is that we understand to have resolved this issue through the resolution of AMCO 23 um And the second basis is that investments which did not make it into the plan, we don't believe are relevant because ultimately they don't form part of what we're considering here today.
>> And you don't think understanding which projects you obviously didn't chose helps inform doesn't help inform the prudence of the projects you're planning to do, how what you've selected, what you've not, and why those were not selected through your process. I'm that that confuses me.
I think you're you're free to ask the witness question around how that determination is made and certainly when it comes to the allocated projects we have detailed evidence on the record as to evaluation of alternatives with respect to many of those projects and so we we believe the record is complete and sufficient to allow the evaluation of prudence.
>> Well, let me ask you this. Is it based on is it going is what sits underneath the projects were not selected do they have is it just simply based on their net benefit scores are lower than those on this table?
>> No. As we talk about in exhibit D211, net benefit or AINV forms the basis for our prioritization, but we also apply constraints whether it be resourcing, scheduling, environmental constraint as examples that could inform how we prioritize those potential investments into our business plan. So there are projects that would have higher net benefit scores than the projects are on this list potentially. But they how we prioritize our unallocated potential investments are based on those constraints would have to be taken into consideration as some of those constraints determine the executability of the selection of unallocated potential investments that we add in.
Well, let me ask this. Let me ask the question a bit differently. Can you provide a list of all of the projects that were part of the longer list that you that h that had higher net benefit scores and and why they were not selected ultimately?
>> No, I I I think the witnesses explained that the selection of projects is not just on the basis of the net score.
There's other considerations that go into that and and we're we're not prepared to provide anything beyond what's included here in the application that ultimately doesn't form part of the amounts we're here to >> yeah just to be clear my question was and to provide the reasons why I think there was some discussion of sort of here the types of reasons but the specific reasons >> no we maintain the refusal >> now let me just ask about the overall budget how that's determined because if you go look as As I understand, there's an overall budget set that includes the allocated and the the non-allocated.
It's not clear to me from the evidence how that overall number is determined.
Can you help me?
So if we uh if we turn to a 221 page 18 line And uh yeah, okay, this is good. So, uh line 10. So, Starting at the top level. So the OPG business OPG business planning and budgeting process line 9 uh is a decentralized annual process undertaken with consistent top- down framework of strategic objectives, resource guidelines and costing assumptions.
Um so within this framework individual businesses such as ours in Hydro in this case uh set strategic and performance objectives to identify a plan um and the work required to achieve these objectives. So um we approach it in two ways. One is the the top down kind of global OPG perspective.
Me from the hydro we are as we kind of established we are condition based. So when we talk about sect 41 that's the foundational elements of identifying the work that we need to do um and then we set a plan in and around that to um to meet those kind of global capital objectives. Now we don't work in a vacuum and um and our our our core objective is really as a business to to maintain availability and reliability and it is really to manage within manage the bottom up requirements within the kind of top down scope of the business.
So you have a capital budget which is allocated or non-allocated that you're seeking approval for the regulated business for the five years. They have very specific numbers in which a sizable amount is obviously unallocated. You don't even know which of the specific projects in the list you're going to do.
So it's just not clear to me how you pick those specific numbers are determined.
Why is it not $10 million more, $40 million less? That's the type of question.
Uh, I'll refer you to D2 Ampco uh 023.
So line 37 please.
This is uh D2 amp code 23 just Yeah. Okay.
Yeah, sorry I've just updated the reference. Uh let's start on line 25 please. So when we talk about the unallocated portfolio um these are these are potential starts or potential future starts as my colleague Mr. Sixstrom as mentioned is selected and prioritized uh through our asset management process described in D211 section 3.2.
Um now we recognize these haven't been fully scoped.
Um and they are based on class 5 estimates. Um now as we review this portfolio um from time to time we may change what sits under this portfolio based on a prioritized basis but we use the combination of the unallocated and our known top- down requirements um allocated projects for which we have uh confirmed BCS's really to build together our kind of capital and OMA request so that that starts as the foundation into the into the business planning process.
this.
>> Can I ask move on to a different topic?
Can I ask you to go to F1 SEC 152 in this interrogatory? We had asked OPG for each historic or current continuous improvement or productivity initiative for the hydroelect electric business to provide for each year between 2016 and 2024 certain information uh quantified information and you say at line 29 OPG is unable to attribute discrete cost savings or isolated incremental productivity increases to individual initiatives as overall performance reflects the interacting effects of multiple initiatives external conditions and operational additional factors that together drive the aggregate outcome. Do you see that? So just so I can understand when I look through the list that you've provided here, which ones are focused on reducing cost, is it really just the organizational realignment one?
Uh no, I'd say it's broader than than as you've characterized. So when we think about cost, I think there is uh the efficiency with which the business operates. So, uh, on page two of four, we've detailed what I'm going to call two sets of safety safety initiatives. Um, one is what we would probably recognize as conventional worker safety. Um, and for me that is really about um driving down the level of incidences to our people uh and having a good strong safety culture uh has the net effect of um driving efficiency within our business. So if we have a safety event or people get injured, that takes time away from doing work to address the impact of it um and our safety performance um has radically improved um in recent times.
So we've we've set the strongest TRIF metrics in our history in the last three years. So for me that is that would be just one example of um driving for excellence and kind of continuous improvement. I I don't disagree and safety is incredibly important and I I recognize obviously there's a cost implication for an unsafe environment but so let me just put aside safety for a moment or safety related and non-safety is the regional realignment is that the only one that is just it's cost focused.
So I so I' the I'd then probably draw your attention to equipment reliability and maintenance. So I think you're going at what I'd kind of call headline cost whereas I as the business leader and focused on within business cost and how can I drive an efficient and and effective business. Um so one of the key areas I'd draw your eye to would be on page three or four um line 11 equipment failure reviews. So we've spent a lot of time talking about uh equipment reliability and so instituting um from 2020 a focused on forced outage causes to inform business and operational decisions. in my mind is a direct driver to how much cost we consume as a business to produce our product. Um really strengthening that cross functional ownership uh between equipment reliability as my colleague Miss Fabro mentioned earlier on plant health committee meetings um and really trying to drive down how we manage equipment condition risk mitigation and failure reviews and you can see that in our performance. So for me in each case it's really driving through um the cost of uh production in the business. I can give you further examples if helpful >> but as I understand as you mentioned at the beginning we there's you can't quantify the cost impact of it.
>> I can't isolate independently one variable because we run it as a business. We don't run it as a series of independent variables. So the um aggregate outcome produces our triple our scorecard equipment you know um availability cost performance safety performance but to isolate one individual component and attribute it solely to that it's a combination of factors. So that's it's just not how we run the business.
>> Now in any of the individual initiatives do they have KPIs that talk about cost that are specific to cost?
Um yeah, can I draw you to SE 150? Um attachment two.
So this is what we call our excellence plan. Um and so what I've just drawn out from there is I've drawn an example from people. I've drawn an example from third column plant about maximizing equipment performance. But if I draw your eye to measures of success on the bottom, um these are all measures of success of the performance value.
uh translating that directly into your question. The efficiency with which we achieve take your choice of any one of those that really translates for me into our unit production cost. Do this well will be run as an efficient business.
>> So these are the metrics that the KPIs that you have for any of the initiatives that you're showing on the screen.
>> These are the measures of success >> and I don't see any that have a target of cost savings.
And just as a reference not to just because it's cross panels for example which I'll take the nuclear folks to they there is reference in an audit report that one of the KPIs of one of the initiative that they talked about has a cost the measure was about um you know annual maintenance cost savings.
There's nothing like that for the hydro business.
>> Uh not in in we run so the way we run hydro is somewhat different to the nuclear business. Uh so comparables I'm going to extrapolate comparables to industry and hydro are somewhat difficult due to the nature of the business. So we have uh performance targets that doesn't say we have performance targets in the business um and if we can talk about our benchmarking um so our cost performance I can direct you to there in terms of how we bench relative to others um so we do have targets I've just drawn you to the measures of success but I haven't given you the targets that sit underneath I mean the targets are not specifically costbased.
So if I refer you to exhibit F11 page 29 chart 11 So this is our Thank you Lori. So on line six here, chart 11, this is our unit energy cost uh forecast and this sits under the section of uh hydroelectric cost effectiveness. So we have cost targets which are a function of um cost to run the business divided by um uh measures of generation.
>> Sure. But not at at a um productivity continuous improvement level.
That's the question I was asking. I took it from what you showed me. You don't have any for any of the initiatives.
uh they're inherent in our cost to your question directly and explicitly not as you framed.
>> Okay. Thank you. And just my last question, I assume it's going to be for undertaking. It's on a different topic.
Can I ask you to go to E1 SEC 132 in this IR we ask for underlying calculation um included in chart six in the pre-filed evidence and you provide some information underlying information on the second page.
And so the problem I'm having is reconciling the information on chart six with the the cost information in chart one in this interrogatory.
So for example, chart 6 in 2026 has payment to nonopg supply generator at uh negative 46 million. And I'm simply unclear and it I can't figure out which combination of costs that are shown here um reconcile with the 46 million. I mean I assume it's import cost, non OPG gas costs, wind costs, potentially OPG gas costs if we're talking about regulated, but I get different numbers.
So I was asking you so by way of undertaking, can you reconcile uh chart one in this interrogatory and chart six in the evidence?
So essentially you're just looking to map out the costs from chart 6 how we showed them here in sect 132. Yes.
>> And what components are included in each line item?
>> Yes.
>> Yes. We can undertake to provide that.
>> That will be JT1.21.
>> And if they don't reconcile why?
>> Sure.
Thank you, Mr. Rubenstein. Uh, Miss Scott, I think you said you might have some followup.
>> Um, actually, I'll just ask one on that F1 SEC 150 that you just had up the attachment. I'm not the strate strategy and excellence plan.
Yes. Um at the bottom it says right click on the table and select drill through. Um could you provide us with a copy that actually has that uh drill through So this is from our um PowerBI and so just to clarify your question is you you are interested in what we call the GAR which is the gap driver action uh result uh >> well Yes. Not knowing exactly what it was, it just I my understanding was it was going to provide more information on a specific on specific objectives.
uh yeah on a best efforts basis provide the uh the relevant GR for the strategy and excellence plan for renewable generation 2026 2028.
>> Thank you.
>> JT 1.22.
Anything else? Uh Miss Scott >> if is there still time? Yes. Um >> no not really. We're we're we're we're we're supposed to break now. Do you do you have much more?
>> Um no, I'm fine. Thank you.
>> Okay. So, let's uh call it a day and we'll be back here tomorrow morning at 9:30. Thanks everyone.
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