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Operator: Good morning, everyone. Thank you for standing by. My name is Ludy and I will be your conference operator today. Welcome to the Fortis Q3 2023 Earnings Conference Call and Webcast. During the call, all participants will be in a listen-only mode. [Operator Instructions]. At this time, I would like to turn the conference over to Stephanie Amaimo. Please go ahead, Ms. Amaimo.

Stephanie Amaimo: Thank you, Ludy, and good morning, everyone, and welcome to Fortis’ Third Quarter 2023 Results Conference Call. I’m joined by David Hutchens, 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 slide show. 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.

Jocelyn Perry: 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 base growth in 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 base growth and 4% to 6% annual dividend growth guidance through 2028. Lastly, the pending sale of Aitken 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 B.C., 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 nonfuel revenue of USD 100 million and 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 FortisBC Energy and 50 basis point increase for FortisBC 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 mechanisms as well as the 2024 GCOC placebo. Overall, the PBR decision was generally in line with management’s expectations. FortisAlberta 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 received 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 Woodfibre 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. This system is expected to be operational in the summer of 2025, capable of serving approximately 40,000 homes for 4 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. Our 5-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 5-year plan. The increase is driven by regional transmission projects at ITC associated with Tranche 1 of the MISO long-range transmission plan, as well as investments in Arizona to support TEP’s exit from coal. Investments supporting system adaptation of 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 1 of only 2 companies listed on the Toronto Stock Exchange to achieve this significant milestone. In September, we also announced the extension of our 4% to 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 Aitken 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 our regulated rate base, the recent regulatory orders in B.C. 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 turn 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 and including $0.05 per common share associated with the retroactive impact to January 1st.

Rate base growth also contributed to the increase, which was partially offset by the timing of operating costs at FortisAlberta. EPS was higher by $0.01 for our U.S. electric and gas utilities with UNS increasing $0.02 in Central Hudson Down 1. 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 $0.02, while weather in the quarter favorably impacted EPS by $0.04, 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 base growth.

At our Other Electric segment, EPS increased $0.01 driven by rate base growth and higher sales. Our Energy Infrastructure segment contributed a $0.02 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 base growth for the quarter was largely offset by higher nonrecoverable 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 Aitken Creek. As I mentioned, we expect to close the transaction in the fourth quarter. Until close, we continue to recognize earnings associated with Aitken 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 at Aitken Creek of $13 million or $0.03 per common share and $24 million or $0.05 per common share for the 6-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 2021, including almost USD 200 million in nonregulated 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 prefunding opportunities. With proceeds from our debt issuances and the expected sale of Aitken 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 5-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.

Stephanie Amaimo: Thank you, Jocelyn. This concludes the presentation. At this time, we’d like to open the call to address questions from the investment community.

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Operator: [Operator Instructions]. Your first question comes from the line of Maurice Choy from RBC Capital.

Maurice Choy: I just want to start with ITC. I assume you would have seen the U.S. Solicitor General comments earlier this week to the Supreme Court regarding Texas ROFR . Admittedly, this feels consistent with the past commentaries, but any thoughts on that submission? Do you think FERC will do anything on the back of that? And what does your Supreme Court decision may mean for your existing ROFRs?

David Hutchens: 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 yes, we did see that you can explain some of those differences between what we have in Iowa and what Texas sees.

Linda Apsey: 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’s strong — 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 in transmission in the state 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 sort of 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 a 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.

David Hutchens: Linda, just a little additional color on that as well. That 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 ROFRs for some projects. And that’s part of the planning and cost allocation that they have out there. So that’s an interesting, I think, deference to FERC as well.

Linda Apsey: Yes. Thank you, Dave. Absolutely.

Maurice Choy: Maybe like any thoughts on timing of that potential for clean statement?

Linda Apsey: Dave, I don’t know if you want to take that or me?

David Hutchens: What was the question, Maurice?

Maurice Choy: You mentioned — you referenced the restatement of the federal offer by FERC. Any thoughts on timing? Do we need a full slate of commission is first? Any thoughts on that?

David Hutchens: Yes, I think it probably will be a bit of time there because that’s part of the planning and cost allocation ROFR — NOPR — and I think that they’re really probably waiting to move that forward until they have a fuller complement for commissioners.

Maurice Choy: And maybe just finishing off on FX. Clearly, FX is higher today than the 1.30 you have assumed in your 5-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 helps to earnings, but how would you approach funding the additional CapEx?

Jocelyn Perry: Maurice, this is Jocelyn. Yes, we do hedge cash flows. We actually go out 2 years about and 100% of our cash flows. And — but you’re right, with the rates where they are today, 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 used to do it actually 1 year out, but we moved to 2 years a few years ago. And we continue to watch it, and we continue to change as the rates change.

Maurice Choy: And can I ask what rate you’ve hedged those 2 years of cash flows at?

Jocelyn Perry: Well, I’d have to get that average rate. It’s actually a good rate today because we’ve been in the market recently. So — but I’d have to get the specific rate for that. We have a lot of little hedges that we put in place.

Maurice Choy: Thank you very much. And get well soon Dave. You do sound good, I will say.

David Hutchens: I’m okay in the lower register.

Operator: Your next question comes from the line of Rob Hope from Scotiabank.

Robert Hope: 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 kind of the eventual outcome of the transition there.

David Hutchens: So Rob, I’d love to give you a bunch of details on that, but we’re just around the corner from releasing that publicly, and we really don’t want to front run our commissioners in the process. So those — that filing and all the details and comments that we’ll make around that are just around the corner. So I’d ask for your patience and then call us back, and we’ll give you as much information as you’d like on that.

Robert Hope: Sounds good. And then maybe a follow-up there. 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 entities right now?

David Hutchens: So far, we haven’t really seen that impact because we’re kind of doing mean we’re not doing a whole ton of any one thing. So 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.

Operator: And your next question comes from the line of Mark Jarvi from CIBC Capital Markets.

Mark Jarvi: So I just wanted 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 a regulatory lag or, I guess, little leakage on interest rates versus deemed debt? And where will we see a carryover of that impact into 2024, if at all?

Jocelyn Perry: Thanks, Mark. Yes, I — so most of our utilities actually have mechanisms to capture the interest rate changes from year-to-year, like ITC and Alberta and B.C., 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 we set 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 will be a small impact relative to Fortis.

Mark Jarvi: Anyway you can kind of put some metrics around that or quantify it to the level?

Jocelyn Perry: 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 of hundred million in — probably not that over the next 2 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.

Mark Jarvi: 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 to 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.

Jocelyn Perry: 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 had a lot of depth 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’s still — it is still very volatile, but it’s something that you really have to reset your thinking on week to week.

Operator: And your next question comes from the line of Ben Pham from BMO Capital Markets.

Benjamin Pham: Maybe to continue 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, ’26 when you think about just where interest rates are going between the 2 countries, your FX exposure, where you want that to be and cost of hedges?

Jocelyn Perry: 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 and Canadian debt. Like we’ve we’re active in that market. And — 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.

Benjamin Pham: 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 1% benefit, but you then your FX exposure comes off a bit. Like are you — right now, your FX exposure mostly is in line with where you want to be?

Jocelyn Perry: Yes, I think we’re comfortable where we are today. But again, yes, no, I would leave it at that. We’re comfortable where we are today, but we’re always watching it.

Benjamin Pham: And I know the cost of capital decisions post Investor Day provided details and EPS sensitivities, that’s very useful. How do you think low, flow through that impact on just credit metrics and if there’s an impact on your equity needs?

Jocelyn Perry: So sorry, Ben. So that question is what impact is the GCOC having on our cash metrics. Okay. Yes, I think it’s around 20 bps. 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 — or we don’t have the order, I should say, on how that’s actually going to flow through customer rates. But I think in the — when it all sells and it all gets into customer rates, it’s probably about 20 bps in B.C. And with respect to it, we have actually filed our compliance filing with the BCUC. We are expecting that they will require about $300 million not quite sure yet when we had to fund that, but it will likely be like late this year or early into next year.

Operator: And your next question comes from the line of David Quezada from Raymond James.

David Quezada: Maybe 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 could see some development on the outstanding items at ITC?

David Hutchens: 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 we have always got something in the hopper related to regulatory filings. We 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 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 opine on your opinion on those, like the base ROE and the — some of those other ones that are hanging out there.

Linda Apsey: Sure. Of course. Yes, certainly, we don’t have any clarity around when FERC might act. I think as we have discussed and spoken about before in these calls, Certainly, the composition, I think, of the FERC commission is somewhat 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, we continue to be engaged around the base ROE matter. And certainly, with MISO TO as well as the industry continue to be engaged and discuss the other pending nope, the incentive or as well as other issues. But 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.

David Hutchens: Thanks, Linda. and 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.

David Quezada: 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?

David Hutchens: Linda?

Linda Apsey: Yes, of course. Look, I mean we have great confidence in MISO’s expertise, experience and abilities around putting these future scenarios together. I think the futures reflect all of their member utilities, carbon reduction goals, obviously, assumptions around electrification and other, how that impacts load demands as well as FERC has the insight and perspective around the generator interconnection queue 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 IMMs 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 are — continue to be optimistic in terms of MISOs ability to continue to push forward.

Operator: And your next question comes from the line of Linda Ezergailis from TD Securities.

Linda Ezergailis: 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 utilities’ 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?

David Hutchens: Yes, that’s a great question, Linda. Thanks. And I’m going to turn that over to Janine Sullivan, our CEO of FortisAlberta to provide some color on the PBR and any other questions you have related to Alberta.

Janine Sullivan: 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 they — 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 promising 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 have — there has been a lot of conversation because of the affordability narratives in Alberta about the need for identifying efficiencies for customers, and we’re very committed to that. And we continue to evaluate 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. So yes, being a third term, it obviously requires us to look deeper into our organization for efficiencies, but that’s what we do.

And we were prepared for that expectation, as I said, given the narrative around affordability and given the discussion on the PBR proceedings.

Linda Ezergailis: And just as a follow-up, bigger picture, the Alberta government’s focus on customer affordability. Where do you see the levers being most likely in order to achieve that? Like do you think there’s anything really material that can be done on the like distribution wire side or transmission wire. Do you see that more coming from other parts of the bill like generation or other components?

Janine Sullivan: 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 and 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.

David Hutchens: 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 as volatile as the other couple of parts of the bills — that’s — I think we’re not in the bull’s eye on this conversation, although it is — they are casting a wide net to makes a couple of metaphors there for you.

Operator: [Operator Instructions]. Your next question comes from the line of Dariusz Lozny from Bank of America.

Dariusz Lozny: 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 prospects 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 — it 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?

David Hutchens: Thanks, Dariusz. And there’s a couple of 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 done in Arizona. And so far, we have got support 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 Q1 of next year.

So that will be kind of that next indication of whether or not there’s some way for us to look at getting 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 take the temperature of 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, is just defining those parameters and seeing how that will work going forward.

Operator: And there are no further questions at this time. I would like to turn it back to Ms. Amaimo.

Stephanie Amaimo: Thank you, Ludy. 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.

Operator: Thank you, Ms. Amaimo, and this concludes today’s conference call. Thank you for participating. You may now disconnect.