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spk00: Good morning, everyone. Thank you for standing by. My name is Ludi, and I will be your conference operator today. Welcome to Fortis Q3 2023 Earnings Conference Call and Webcast. During the call, all participants will be in a listen-only mode. There will be a question and answer session following the presentation. At that time, those with questions should press star followed by the number one on their telephone. If at any time during the conference you need to reach an operator, please press the star zero. At this time, I would like to turn the conference over to Stephanie Amamo. Please go ahead, Ms. Amamo.
spk08: Thank you, Ludi, and good morning, everyone, and welcome to Fortis' third quarter 2023 results conference call. I'm joined by David Hutchins, President and CEO, Jocelyn Perry, Executive VP and CFO, other members of the senior management team, as well as CEOs from certain subsidiaries. Today, Jocelyn will speak to the prepared remarks on behalf of Dave as he is recovering from laryngitis. Both Dave and Jocelyn will address questions at the end. Before we begin today's call also, I want to remind you that the discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slideshow. Actual results can differ materially from the forecast projections included in the forward-looking information presented today. All non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U.S. GAAP financial measures in our third quarter 2023 MD&A. Also, unless otherwise specified, all financial information referenced is in Canadian dollars. With that, I will turn the call over to Jocelyn.
spk01: Thank you, and good morning, everyone. The third quarter proved to be a busy and positive quarter for Fortis. We received a number of key regulatory decisions in Arizona and Western Canada, which I will speak to shortly. Together, rate-based growth and the recent regulatory outcomes in British Columbia and Arizona supported strong earnings growth in the quarter and year-to-date. And for those that attended in person or tuned in virtually, you know we held our Investor Day in September, outlining our new $25 billion capital plan for 2024 to 2028. This capital plan supports 6.3% average annual rate-based growth and 4% to 6% annual dividend growth guidance through 2028. Lastly, the pending sale of Aiken Creek is progressing as expected, with the British Columbia Utilities Commission, or BCUC, approving the sale last week. With all regulatory requirements satisfied, we expect the transaction will close in the fourth quarter. With decisions in the TEP rate case and the generic cost of capital or GCOC proceedings in Alberta and BC, we have completed a number of large regulatory applications. In August, the Arizona Corporation Commission issued its decision in TEP's general rate application, approving an increase in non-fuel revenue of $100 million, a 9.55% allowed ROE, and a 54% equity layer. New customer rates became effective on September 1st. Also, last month, the BCUC issued a decision on the GCOC proceeding. The decision resulted in an allowed ROE of 9.65% for both Fortis utilities, reflecting a 90 basis point increase for Fortis BC Energy and 50 basis point increase for Fortis BC Electric. The equity thickness levels also increased from 38.5% to 45% for FortisBC Energy and from 40% to 41% for FortisBC Electric. The new cost of capital parameters are retroactive to January 1st. I'll speak later to the related financial impacts. In October, the Alberta Utilities Commission, or AUC, issued a decision on FortisAlberta's third performance-based rate-setting mechanism, as well as the 2024 GCOC procedure. Overall, the PBR decision was generally in line with management's expectations. Fortis Alberta continues to evaluate the annual capital provisions included in the PBR decision, which were premised on 2018 to 2022 historical levels. In the GCOC decision, the AUC adopted a formulaic approach in determining the allowed ROE, which will be calculated annually. Although the 2024 allowed ROE calculation won't be finalized until later this year, Using today's inputs, we expect the allowed ROE for 2024 to be modestly higher than the notional ROE of 9%. All in all, we receive balanced regulatory outcomes for our customers and stakeholders in Arizona and Western Canada. With $3 billion invested in our systems through September, our $4.3 billion annual capital plan remains on track. Major capital projects continue to advance in line with our plan. In August, FortisBC Energy commenced construction on the Eagle Mountain Wood Fiber Gas Line project, and just a few weeks ago, TEP announced it will build the Roadrunner Reserve Project, a 200-megawatt battery energy storage system. The system is expected to be operational in the summer of 2025, capable of serving approximately 40,000 homes for four hours when deployed at full capacity. This project supports system reliability as TEP exits from coal and expands its renewable resources. TEP expects to file its next integrated resource plan on November 1st. The preferred portfolio is expected to align with Fortis' Scope 1 greenhouse gas emissions reduction targets of 50% by 2030, 75% by 2035, and net zero by 2050. A five-year, $25 billion capital plan is comprised of virtually all regulated investments and a diverse mix of highly executable, low-risk projects. This new plan is $2.7 billion higher than the previous five-year plan. The increase is driven by regional transmission projects at ITC associated with tranche one of the MISO long-range transmission plan, as well as investments in Arizona to support TEP's exit from coal. Investments supporting system adaptation and resiliency and economic development are also driving capital growth for the benefit of our customers. We expect rate base will increase by $12.6 billion to over $49 billion in 2028, supporting average annual rate base growth of 6.3%. In the third quarter, our Board of Directors declared a fourth quarter dividend increase of 4.4%. marking 50 years of consecutive increases in dividends paid. Fortis is proud to be one of only two companies listed on the Toronto Stock Exchange to achieve this significant milestone. In September, we also announced the extension of our 4-6% annual dividend growth guidance through 2028, supported by our Sustainable Growth Outlook. Slide 8 provides a summary of our third quarter and year-to-date reported and adjusted earnings per share. Reported earnings include timing differences related to mark-to-market accounting of natural gas derivatives at Aitkin Creek and the revaluation of deferred income tax assets related to a change in the corporate tax rate in the state of Iowa. Adjusted EPS was $0.84, $0.13 higher than the third quarter of 2022. On a year-to-date basis, adjusted EPS was $2.37, $0.31 higher than the same period last year. Key earnings drivers center around continued investments in a regulated rate base, the recent regulatory orders in BC and Arizona, as well as warmer weather in Arizona. I'll get into the details of each on the next couple of slides. The waterfall chart on slide 9 highlights the EPS drivers for the third quarter by segment. Our Western Canadian utilities contributed a $0.09 EPS increase, reflecting the new cost of capital parameters approved by the BCUC in September 2023, totaling approximately $0.08, including $0.05 per common share associated with the retroactive impact to January 1st. Rate-based growth also contributed to the increase, which was partially offset by the timing of operating costs at Fortis Alberta. EPS was higher by one cent for our U.S. electric and gas utilities, with UNS increasing two cents and Central Hudson down one. In Arizona, the quarterly results were mainly driven by new rates at TEP effective September 1st and higher retail sales due to warmer weather. New rates increased EPS by approximately two cents, while weather in the quarter favorably impacted EPS by 4 cents, with July being the hottest month on record in Tucson. Lower wholesale and transmission revenues, higher operating costs, and lower production tax credits for Oso Grande tempered the results at UNS for the quarter. Central Hudson's results reflect higher operating costs, as expected, due to the timing of costs in the first half of the year, partially offset by rate-based growth. At our other electric segment, EPS increased one cent, driven by rate-based growth and higher sales. Our energy infrastructure segment contributed a two-cent EPS increase for the quarter. This includes higher earnings at Aitken Creek, reflecting market conditions, net of lower hydroelectric production in Belize. Elevated finance costs at corporate and higher weighted average shares outstanding issued under our dividend reinvestment plan were offset by the favorable impact of a higher average U.S. to Canadian dollar foreign exchange rate. And although not shown on the slide, ITC's rate-based growth for the quarter was largely offset by higher non-recoverable finance and stock-based compensation costs. Year-to-date EPS was impacted by many of the same factors discussed for the quarter. On a year-to-date basis, an increase in the market value of certain investments that support retirement benefits and lower depreciation associated with the retirement of the San Juan Generating Station in 2022 also favorably impacted results. Before I move on from earnings, I would like to take a moment to explain where we are with respect to the pending sale of Aiken Creek. As I mentioned, we expect to close the transaction in the fourth quarter. Until close, we continue to recognize earnings associated with Aiken Creek in accordance with U.S. GAAP. Upon close of the transaction, adjusted earnings will exclude the gain expected to be recorded on the sale as well as the earnings recognized since the March 31st effective date. For the third quarter, we recorded adjusted earnings of Aiken at Aiken Creek of $13 million, or $0.03 per common share, and $24 million, or $0.05 per common share, for the six-month period since March 31st. Through September, we have raised over $2 billion of debt, primarily to refinance maturing debt and to fund our capital program. With regards to upcoming maturities, we currently have about $1.7 billion due through the end of 2025. including almost $200 million in non-regulated debt at Fortis, Inc. Our primary exposure to elevated interest rates pertains to holding company debt as our regulated utilities ultimately recover changes in interest rates through regulatory mechanisms and the periodic rebasing of customer rates. We'll continue to monitor the debt capital markets and consider interest rate hedges or pre-funding opportunities. With proceeds from our debt issuances, and the expected sale of Aitkin Creek, as well as over $4 billion available on our credit facilities, we remain in a strong liquidity position and are comfortably positioned within our investment grade credit ratings as we execute our $25 billion capital plan. To summarize, we have made significant progress in 2023 to advance our growth strategy. We have executed our capital plan as expected, concluded key regulatory proceedings, and delivered strong earnings growth through the third quarter. And with our recently announced five-year capital plan, we are continuing to deliver regulated growth to support a more reliable and cleaner energy future. When combined with our regulated and geographic diversity, strong ESG story, and good governance model, we are well positioned for the future. That concludes my remarks. I'll now turn the call over to Stephanie.
spk08: Thank you, Jocelyn. This concludes the presentation. At this time, we'd like to open the call to address questions from the investment community.
spk00: Thank you. We will now conduct a question and answer period. If you would like to register a question, please press the star followed by the number one on your telephone. If your question has been answered and you would like to withdraw your registration, please press the pound sign. If you're using a speakerphone, please keep your hands up before entering your request. And we kindly request you speak loudly and slowly to ensure all participants can hear your questions. One moment, please, for the first question. Your first question comes from the lineup. Maurice Choi from RBC Capital. Your line is open.
spk10: Thank you, and good morning. I just want to start with ITC. I assume you would have seen U.S. Solicitor General's comments earlier this week to the Supreme Court regarding the Texas roe fur. Admittedly, this feels consistent with the past commentaries, but any thoughts on that submission? Do you think FERC will do anything on the backs of that, and what does a U.S. Supreme Court decision mean for your existing roe furs?
spk02: Yeah, thanks for the question, Maurice. I'm going to kick that over to Linda Apsey, our CEO of ITC, to give you a little bit of color on that. But, yeah, we did see that. She can explain some of those differences between what we have in Iowa and what Texas sees.
spk07: Great. Thanks, Dave. And good morning, Maurice. Yes, we, too, saw that Solicitor General opinion on the Texas ROFR. And I think standing back from it, it was sort of a mixed bag, I think, in terms of some of the reflections of the Solicitor General. I think most importantly is that it sort of calls out a distinction between the Texas ROFR, which in essence does not provide any opportunity for any non-incumbent utility to participate in investment and transmission in the states, versus, for example, the Minnesota ROFR, which had also been challenged and was upheld by the district court that covers the Minnesota area. Essentially, the Solicitor General indicated that they did not feel as though the issue was ripe for the Supreme Court to take up the issue. and that there was still sort of opportunity for this issue to continue to play out. So I would say, by and large, it was sort of a mixed opinion, not clear what the Supreme Court will do, if anything. Certainly, as I said, it was the Solicitor General's recommendation that the court not take up the issue. And I think from our perspective, it does, I think, demonstrate that the ROFRs, whether it be in Minnesota, Michigan, or what had been proposed in Iowa, is distinctly different from what the Texas ROFR was.
spk02: Great, thanks. Linda, just a little additional color on that as well. I thought one of the interesting parts about That argument that it's not ripe was the fact that FERC is obviously looking at things like reinstating federal rofers for some projects, and that's part of the planning and cost allocation, Oprah, that they have out there. So that's an interesting, I think, deference to FERC as well.
spk07: Yes, thank you, Dave. Absolutely.
spk10: Maybe on any thoughts on timing of that potential FERC reinstatement?
spk07: Dave, I don't know if you want to take that or me.
spk10: What was the question, Maurice? You referenced the reinstatement of the federal offer by FERC. Any thoughts on timing? Do we need a full slate of commissioners first? Any thoughts on that?
spk02: Yeah, I think it probably will be a bit of time there because that's part of the planning and cost allocation NOPR program. And I think that they're really probably waiting to move that forward until they have a fuller complement for commissioners.
spk10: Great. And maybe just finishing off on FX. Clearly, FX is higher today than the 1.30 you have assumed in your five-year plan. I know you provided sensitivities on slide 22 for EPS and CapEx. But could you remind us of your cash flow or earnings hedges for the upcoming years? And assuming these FX rates hold, clearly helpful to earnings, but how would you approach funding the additional capex?
spk01: Maurice, this is Jocelyn. Yeah, we do hedge cash flows. We actually go out two years about, and 100% of our cash flows. And but you're right with the rates where they are today. We are we're always watching that and we hedge a little more sometimes and we hedge a little less sometimes. And it does impact earnings, but particularly we watch it around cash flows. So we like we used to do it actually one year out, but we moved to two years a few years ago and we continue to watch it and we continue to change as the rates change.
spk10: And can I ask what rate you've hedged those two years of cash flows at?
spk01: Well, I'd have to get that average rate. It's actually a good rate today because we've been in the market recently. But I'd have to get the specific rate for that. We have a lot of little hedges that we put in place.
spk10: Great. Thank you very much. And get well soon, Dave. You do sound good, I will say.
spk02: Thank you. I'm okay in the lower register.
spk00: Thank you. Your next question comes from the line of Rob Hope from Scotiabank. Your line is open.
spk11: Good morning, everyone. I was hoping you could give some additional color on the Tucson IRP, which will be filed in the coming days. Maybe can you just talk about how it has changed with the IRP and whether we could see some upside or downside in your CapEx plan, depending on the eventual outcome of the transition there?
spk02: So Robert I'd love to give you a bunch of details on that but we're just around the corner from releasing that that publicly and we really don't want to front run our commissioners and in the process. So those that filing and all the details and comments that will make around that are just around the corner. So I'd ask for your patience and then call us back and we'll we'll give you as much information as you'd like on that.
spk11: Sounds good. And then maybe follow up there. So how are you dealing with some of the supply chain issues that we're seeing there? Are you seeing them improve, or are there still some headwinds? And how are you managing kind of the supply issues right now?
spk02: Yeah, so far we haven't really seen that impact because we're kind of doing – I mean, we're not doing a whole ton of any one thing. So we're not – We're not dependent on some huge amount of panels or wind or batteries, et cetera. It's a very balanced portfolio approach that we're doing. So we have not to date, as we sit here today, feel like we have any issues there. Now, obviously, those change as we go forward, and we'll be watching that. But I think we're going to be just fine.
spk09: Thank you.
spk02: Thanks, Rob.
spk00: And your next question comes from the line of Mark Charby from CIBC Capital Markets. Please proceed with your question.
spk03: Yeah, thanks. Good morning, everyone. So I just want to come back to the comments around higher interest rates and, Jocelyn, you mentioned about the holding company debt. Just at the operating subsidiaries, where are you feeling the most, I guess, pressure from any regulatory lag or, I guess, the leakage on interest rates versus deemed debt? And Where will you see a carryover of that impact in the 2024, if at all?
spk01: Thanks, Mark. Yeah, so most of our utilities actually have mechanisms to capture the interest rate changes from year to year, like ITC in Alberta and BC. But the one, I think you've already hit it, the one that there is a lag is at UNS. So until they go in for their next rate case, well, then they've reset any new debt issuances that they have done. So I would say in large part, most of our utilities actually have those mechanisms, but that's probably the one area where it's, and it's small, right? It would be a small impact relative to Portis.
spk03: Any way you can kind of put some metrics around it or quantify it at some level?
spk01: Well, I can't believe it to be material because I'm thinking about really what you're talking about is the delta on any new debt issuances over the next couple of years. And I don't know if Susan has that number in front, but it's probably a couple hundred million in probably not that over the next two years. And so it's the delta between probably their current rate and about 2% delta on that. So again, not big for Fortis. And as you know, with UNS, with the way that their rates are set, some things are positive, some things are negative. So it's not necessarily a drag on earnings. So you have to look at the full picture as well.
spk03: Got it. And then just given where you think rates are today, and you think about the maturities in 2024 even, Any idea in terms of when you look to address that? Is it something you'd be patient with? Is it something you just want to kind of address and clear off earlier than later? Any sort of updated views in terms of how you deal with those maturities in the next 12 months?
spk01: Well, we watch it daily, right? And so we make these decisions quite frequently. But what I will say is I tend to – get that risk behind us, right? So in the past, we've actually hauled a lot of debt forward, and we continue to do that. So it is a strategy that we've deployed before, and I suspect we'll deploy again. But we'll keep watching the market. I mean, it is still very volatile, but it's something that you really have to reset your thinking on week to week.
spk03: Got it. Okay. Thanks, everyone.
spk00: And your next question comes from the line of Ben Tom from BMO Capital Markets. Please proceed with your question.
spk04: Hi, thanks. Good morning. Maybe to continue on the last question on refinancings, I'm wondering, is there any meaningful differences between when you think about the Canadian and U.S. market and refinancing upcoming debt, such as the 24 or 26, when you think about just where interest rates are going between the two countries, your FX exposure, where you want that to be, and cost of hedges.
spk01: Ben, that's what we do all day long. So every time in both markets, we're looking at where we're issuing, what we're issuing, the tenor, the currency. I mean, we've done some FX currency swaps on Canadian debt. We've We're active in that market, but as I said on the previous question, it is something that you sort of have to reset your mind every week because it is changing, but all of those things are considered every time we go to market.
spk04: And would you say on your FX matching then, and what I'm getting at is if you have a U.S. dollar maturity coming up, you can issue in Canada at a 1%. benefit, but then your FX exposure comes off a bit. Right now, your FX exposure mostly is in line with where you want to be?
spk01: Yeah, I think we're comfortable where we are today. But again, yeah, no, I would leave it at that. We're comfortable where we are today, but we're always watching it.
spk04: Okay. And I know the cost of capital decisions post Investor Day provided the details and EPS sensitivities. That's very useful. How do you think you'll flow through that impact on just credit metrics and if there's an impact on your equity needs?
spk01: So sorry, Ben. So that question is what impact is the GCOC having on our cash metrics? Okay. Okay. Yeah, I think it's around 20 bits. But, again, that's going to depend on how that's recovered in rates. And I know that the folks in Western Canada are still looking at how – well, we don't have the order, I should say, on how that's actually going to flow through customer rates. But I think when it all settles and it all gets into customer rates, it's probably about 20 bits in B.C. And with respect to equity, we have actually – filed our compliance filing with the BCUC. We're expecting that they will require about $300 million. Not quite sure yet when we have to fund that, but it will likely be late, late this year or early into next year.
spk04: Okay, got it. Thank you.
spk00: And your next question comes from the line of David Quesada from Raymond James. Your line is open.
spk09: Thanks. Morning, everyone. Maybe I have a question just from a regulatory perspective. You've had a few big decisions recently. I'm just wondering where you'll be turning your focus to going forward and any updated thoughts around when we can see some development on the outstanding items at ITC?
spk02: Yeah, I'll turn it over to Linda to comment on the ITC for timing because some of that stuff is still up in the air, but You know, we have always got something in the hopper related to regulatory filings. You know, we've still got a very small UNS electric case going down in Arizona. We're getting ready to file another multi-year rate plan at FortisBC. So, you know, a couple in, a couple out. We're always in this process for sure. But no real big regulatory decisions that we're waiting on yet. today other than those ones from FERC? And Linda, if you want to pine on your opinion on those, you know, like the base ROE and, you know, some of those other ones that are hanging out there.
spk07: Sure, of course. Yeah, certainly we don't have any clarity around when FERC might act. I think as we have discussed and spoken about before on these calls, certainly the composition, I think, of the FERC commission is is somewhat, you know, kind of, I think, standing in the way of some progress on decisions around many of the pending matters before FERC. Certainly as a transmission owner group at MISO, you know, we continue to be engaged around the base ROE matter, and certainly with MISO TOs as well as the industry, you know, continue to be engaged and discuss the other pending NOPRs, the incentive NOPR, as well as other issues. I would say particularly on the base ROE issue, I think we're going to have to wait until we have a full composition of commissioners until we see any progress or traction on that issue. And then on the incentive NOPR issue, it is our view and it's our read that it is not a priority issue amongst the commissioners at this point in time. And so we just continue to track and monitor and be engaged to the extent that we can on those issues.
spk02: Thanks, Linda. I totally forgot. I do the round the horn in my head there at all the different utilities and what's coming up. But Central Hudson obviously has a rate case that's currently filed and pending as well.
spk09: Excellent. Thanks for that. And then maybe just one more for me. Thinking about the MISO long-range transmission plan, I'm wondering if you have any thoughts around some of the things the IMM has put out there about fleet assumptions, and do you see that having any material effect on how things could play out there?
spk02: Linda?
spk07: Yeah, of course. Look, I mean, we have great confidence in MISO's expertise, experience, and abilities around you know, putting these future scenarios together. I think the futures reflect, you know, all of their member utilities, carbon reduction goals, obviously assumptions around, you know, electrification and other, you know, how that impacts load demands, you know, as well as, you know, FERC has the insight and perspective around the generator interconnection queue and And so we remain very confident and comfortable in MISO's scenarios, their assumptions, and we think that MISO is best prepared and equipped to respond to the IMM's issues and concerns, and we have comfort and confidence that MISO will continue forward with the futures that they've developed and ultimately continue to work towards the transmission projects that will comprise the Tranche 2. And we obviously continue to be optimistic in terms of MISA's ability to continue to push forward.
spk09: Excellent. Appreciate the call. Thanks, Linda. Yep.
spk00: And your next question comes from the line of Linda Isser-Guinlis from TD Securities. Your line is open.
spk06: Thank you. Recognizing it's not as impactful to Fortis overall as ITC, but I am curious to hear your views on Alberta and your expectations around your utility's ability to kind of outperform and over-earn under PBR 3.0. and what sort of efficiencies might be further squeezed out, realizing you've already likely done a lot on that front?
spk02: Yeah, that's a great question, Linda. Thanks. And I'm going to turn that over to Janine Sullivan, our CEO of Fortis Alberta, to provide some color on the PBR and any other questions you have related to Alberta.
spk05: Good morning, Linda, and thanks for that question. As you know, we've been working through the process to come to this conclusion on PBR 3.0, for some time and many of the issues that we were contemplating in the process, we were prepared for and filed evidence on. So we've been planning for and thinking about how we would adjust or accommodate some of the findings in this decision for some time. And the findings were in keeping with where we kind of expected things to go. I will say that we are kind of reconsidering the capital portion of the decision. where they are premising future funding on historical additions. It really doesn't consider what was approved for 2023 when we rebased under cost of service. And it does include years, of course, that were impacted by the pandemic. So looking forward, we see a need for additional capital. Now, there are provisions in that plan that allow us to go forward and ask for that capital. So that's helpful. But we are thinking about that particular element. With respect to the efficiencies in particular, there has been a lot of conversation because of the affordability narrative in Alberta about the need for identifying efficiencies for customers, and we're very committed to that. And we continue to evaluate any and all opportunities to deliver those for customers in our day-to-day operations. And we'll actually have to report on them to the Commission in future periods as part of the PBR plan. Yes, being a third term, it obviously requires us to look deeper into our organization for efficiencies, but that's what we do. We were prepared for that expectation, as I said, given the narrative around affordability and given the discussion in the PBR proceedings.
spk06: Thank you. Just as a follow-up, a bigger picture, the Alberta government's focus on Customer affordability, where do you see the levers being most likely in order to achieve that? Do you think there's anything really material that can be done on the distribution wire side or transmission wire? Do you see that more coming from other parts of the bill like generation or other components?
spk05: I will share with you that in Alberta right now there is a very detailed process going on led at the provincial government level around all issues related to bills. And they are taking a very fulsome approach to understanding exactly what's driving the affordability concerns. And I will say that all things are on the table with the government right now. With respect to distribution in particular, we work with them on, I guess, opportunities to assist customers in managing the affordability concerns. So things like DSM, demand-side management, energy efficiency programming, which hasn't been clearly defined in Alberta. We believe that as the front-facing customer utility service, we should be the one delivering those types of programs. So we are working with them to advance that type of programming and the role the utility plays in that. And that's one space in particular where we think we can assist customers. Thank you.
spk02: Linda, I'd add my own, I suppose, personal opinion, I guess, is that of all the components of the bills in Alberta, the distribution one is the last one to focus on from the position of cost reduction and efficiencies, because that's not the part of the bill that's growing or is as volatile as the other couple parts of the bill. So I think we're not in the bullseye on this conversation, although they are casting a a wide net to mix a couple metaphors there for you.
spk06: Thank you.
spk00: Thank you. And once again, if you would like to register a question, please press the star followed by the number one on your telephone. Your next question comes from the line of Darius Lozney from Bank of America. Your line is open.
spk12: Hey, good morning. Thanks for taking my question. I just wanted to ask one on Arizona. Obviously, without wanting to front-run the IRP announcement that's coming next week, I just wanted to ask about the prospect for getting concurrent recovery in some form. Obviously, there was a robust stakeholder process this time around, certainly some interest there, but it didn't seem like, still seems like there's some opposition there. So, Curious what learnings you can talk about or maybe perhaps adjusting your strategy on a go-forward basis as you pursue that concurrent recovery. And a related topic, perhaps just how that manifests in your planning for owned generation on a go-forward basis versus PPAs. Thank you.
spk02: Yeah, thanks, Darius. And there's a couple data points. The first one is the TEP rate case where we asked for the resource transition mechanism, which is what we called it, and got morphed into something called the System Reliability Benefits Adjuster, which is meant to recover some of these investments between rate cases and get a more concurrent recovery and obviously reduce regulatory lag. We did not get that in the TEP case. Now we're in the process and asked for the exact same thing and the same name now in the UNS Electric, the smaller electric utility that we have down in Arizona. And so far we have got support from from staff and others for that now that just came out of the hearing process and we're waiting on a recommended opinion in order that we would expect towards the end of this year with rates maybe in Q one of of next year. So that will be kind of that next indication of whether or not there's you know some way for us to look at get this. If we don't, then there's always the opportunity of looking at a more generic docket to have these conversations and try again in the next rate case. It isn't nearly as urgent for TEP, obviously, with the investment tax credits and production tax credits that provide some benefits between rate cases as well and do serve to reduce some of that regulatory lag. That helps for sure. And, of course, we can always ask in the next rate case and see how, you know, take the temperature the commission and other utilities are asking for these same kind of mechanisms as well. And sooner or later, I think we'll get something like this. It's just defining those parameters and seeing how that will work going forward.
spk12: Okay, great. Thank you very much. Appreciate it.
spk00: Thank you, and there are no further questions at this time. I would like to turn it back to Ms. Amaymo.
spk08: Thank you, Luda. We have nothing further at this time. Thank you, everyone, for participating in our third quarter 2023 results conference call. Please contact Investor Relations should you need anything further. Thank you for your time, and have a great day.
spk00: Thank you, Ms. Amaymo, and this concludes today's conference call. Thank you for participating. You may now disconnect.
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