Fortis Inc. (NYSE:FTS) Q2 2023 Earnings Call Transcript

Fortis Inc. (NYSE:FTS) Q2 2023 Earnings Call Transcript August 2, 2023

Fortis Inc. misses on earnings expectations. Reported EPS is $0.44 EPS, expectations were $0.46.

Operator: Good morning, everyone. Thank you for standing by. My name is Michelle, and I will be your conference operator today. Welcome to the Fortis Q2 2023 Earnings Conference Call and Webcast. During this call, all participants will be in a listen-only mode. Following the presentation, there will be a question-and-answer session. [Operator Instructions] At this time, I would like to turn the conference over to Stephanie Amaimo. Please go ahead, Stephanie.

Stephanie Amaimo: Thanks, Michelle, and good morning, everyone, and welcome to Fortis’ second 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. Before we begin today’s call, 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 second 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 David.

David Hutchens: Thank you, and good morning, everyone. Fortis continues to build on its strong momentum from the first quarter. Operationally, our utilities delivered safe and reliable service in the second quarter even with the extreme weather events in Western Canada. Notably, we replaced almost 1,000 poles and structures in Alberta damaged by wildfires. Fortunately, customer impacts were minimal given successful mitigation efforts and a strong response in restoration by the team. Our regulated rate base growth has supported EPS through the first-half of 2023 as we have invested capital of approximately CAD 2 billion. Our investments continue to focus on modernizing the grid, enhancing system reliability, and delivering cleaner energy.

During the quarter, we continued to advance our sustainability priorities and regulatory proceedings, which we will speak to in more detail shortly. And lastly, the sale of Aitken Creek is on track to close in the second-half of 2023, subject to approval from the British Columbia Utilities Commission. Today, we released our 2023 Sustainability Update Report, which includes our key ESG performance indicators for 2022. The report highlights our 29% reduction in Scope 1 greenhouse gas emissions, since 2019. This marks significant progress towards Fortis’ greenhouse gas reduction targets of 50% by 2030, 75% by 2035, and net zero by 2050. For the first time, the report includes limited assurance by a third party on certain key performance indicators, including Scope 1 and 2 greenhouse gas emissions data.

The report also highlights Fortis’ advancement in diversity, equity, and inclusion. The corporation has achieved its Board of Directors diversity targets, with 58% of the Board comprised of women, and two of the 12 members identifying as visible minorities. The report also highlights the further alignment of our ESG priorities with our approach to executive compensation. For 2023, we have increased the weightings for ESG leadership and safety performance in our short-term incentive plan, and added a new DEI measure to our long-term plan. With CAD 2 billion invested in our systems through June, our CAD 4.3 billion annual capital plan remains on track. Our CAD 22.3 billion five-year capital plan, consisting of virtually all regulated investments in a diverse mix of highly executable low-risk projects also remains on track.

We expect rate base will increase by CAD 12 billion to over CAD 46 billion in 2027, supporting average annual rate base growth of 6.2%. Outside of the capital plan, our utilities are pursuing regulated growth opportunities. Central Hudson is a minority investor in New York Transco. Recently, the New York ISO selected a proposal to construct transmission infrastructure to deliver at least 3,000 megawatts of energy from Long Island offshore wind facilities to the rest of the state by 2030. Transco’s portion of the project is estimated to be $2.2 billion U.S., with Central Hudson’s portion of this investment estimated at 10%. With a strong track record of increasing dividends for the past 49 consecutive years, coupled with our low-risk growth strategy, we remain confident in our 4% to 6% annual dividend growth guidance through 2027.

Now, I will turn the call over to Jocelyn for an update on our second quarter financial results.

Jocelyn Perry: Thank you, David, and good morning, everyone. Slide nine provides a summary of our second quarter and year-to-date financial results. For the second quarter, reported earnings were CAD 294 million or CAD 0.61 per common share. Reported earnings include timing differences related to mark-to-market accounting of natural gas derivatives at Aitken Creek. Adjusted earnings were CAD 302 million, or CAD 0.62 per common share, CAD 0.05 higher than the second quarter of 2022. Rate base growth was the key driver for the quarter. Timing of operating costs at Central Hudson and Fortis Alberta, as well as higher margins on gas sold at Aitken Creek also contributed to the increase. Lower earnings reported in Arizona were mainly driven by milder weather and the timing of wholesale sales.

At corporate, elevated finance costs and higher weighted average shares outstanding issued under our dividend reinvestment plan, yielding over 35% shareholder participation, were partially offset by favorable impact of a higher average U.S. to Canadian dollar foreign exchange rate of CAD 1.34 in the quarter, compared to CAD 1.28 in the second quarter of 2022. On a year-to-date basis, reported earnings were CAD 731 million or CAD 1.51 per common share. Adjusted earnings were CAD 741 million or CAD 1.53 per common share, CAD 0.19 higher than the first-half of 2022. Year-to-date EPS was impacted by many of the same drivers as the quarter, except on a year-to-date basis higher earnings at UNS were driven by favorable margins on long-term wholesale sales and transmission revenues.

The waterfall chart, on slide 10, highlights the EPS drivers for the second quarter by segment. Our Western Canadian Utilities and Other Electric segments each contributed a CAD 0.02 EPS increase, driven mainly by rate base growth. For our Western Canadian Utilities, timing of operating costs at Fortis Alberta also favorably impacted the quarterly result, while our Other Electric segment benefited from higher sales in the Caribbean. As I mentioned, our Energy Infrastructure segment contributed a CAD 0.02 EPS increase for the quarter, mainly driven by higher margins on gas sold at Aitken Creek. At ITC, EPS increased by CAD 0.01 for the quarter driven by rate base growth, tempered by higher finance costs. EPS was lower by CAD 0.01 for our U.S. Electric and Gas Utilities, with Central Hudson increasing CAD 0.01 and UNS down CAD 0.02.

Central Hudson’s results reflect rate base growth and the timing of operating costs. In Arizona, the quarterly results were mainly driven by milder weather and lower wholesale sales. Weather for the quarter impacted EPS by CAD 0.04. This was somewhat offset by customer growth, lower depreciation with the retirement of the San Juan facility, last June, and gains on investments that support retirement benefits. As I previously discussed, the remaining items on the waterfall chart were driven by corporate, foreign exchange, and weighted average shares, which together netted to a CAD 0.01 decrease. Year-to-date EPS was impacted by many of the same factors discussed for the quarter, except that Arizona contributed to earnings growth for the six months period.

As you may recall, favorable market conditions in the first quarter resulted in higher wholesale sales and for transmission revenues, and as expected, wholesale sales moderated in the second quarter; all in all, a very strong first-half of 2023. Our utilities were active in the debt capital markets with nearly CAD 2 billion of debt issued through June, primarily to refinance maturing debt and fund our capital program. Most notably, ITC issued $800 million in non-regulated debt in June at a weighted average rate of approximately 5% to refinance their maturities. Through the end of next year, we have holding company debt maturities at Fortis of approximately $500 million. And for our preference shares, we have dividend rate resets of CAD 230 million in 2023 and CAD 850 million in 2024.

We continue to maintain strong investment grade credit ratings. Last month, S&P confirmed our A- issuer credit rating and stable outlook. Our recent debt issuances coupled with over CAD 4 billion available on our credit facilities places us in a strong liquidity position. We remain comfortably positioned within our investment grade credit ratings as we execute our CAD 22.3 billion capital plan and pursue incremental organic growth opportunities. Turning now to an update on our regulatory proceedings since we last updated the market, in Arizona, TEP’s rate case continues to progress. In July, the administrative law judge issued a recommend opinion and order proposing a non-fuel revenue increase of $102 million with new rates expected to be effective in September.

The ALJ’s recommended rate bases of $3.6 billion and equity ratio of approximately 54% were consistent with TEP’s revised request. The ALJ also recommended and allowed ROE of 9.4% compared to TEP’s current ROE of 9.15%. In terms of rate design, TEP had proposed a regulatory mechanism to include recovery of certain investments associated with its clean energy transition. Although not recommended by the ALJ, TEP is hopeful the Commission will consider such a mechanism. Consideration of the ALJ’s recommended opinion and order is tentatively scheduled for next week’s ACC’s open meeting. At Central Hudson, a constructive interim agreement was reached last week with the New York Public Service Commission in related to its show cause order. As part of the agreement, Central Hudson will implement an independent third party verification of recent system improvements relating to its billing system.

Central Hudson will also accelerate the implementation of its monthly meter reading plan. While this system is now operating as intended, Central Hudson continues to work with key stakeholders and customers to address any remaining concerns. Earlier this week, Central Hudson also filed a general rate application with the New York Public Service Commission for their normal regulatory cycle as the current three-year plan concludes on June 30, 2024. Turning to Western Canada, Fortis BC filed its final reply arguments earlier this year and its generic cost of capital proceeding. And a decision is now expected in the third quarter. At Fortis Alberta, records are closed in the proceedings related to the generic cost of capital and the third PBR term effective in 2024.

A decision is expected from the Alberta Utilities Commission later this year on both proceedings. With that, I’ll now turn the call back to David.

David Hutchens: Thank you, Jocelyn. We are pleased with the progress we are making in 2023 to deliver sustainable growth. For the remainder of the year, we are focused on executing our annual capital plan, closing the sale of Aitken Creek, and securing constructive regulatory outcomes. We are confident we will deliver long-term value to our shareholders through the execution of our regulated growth strategy and 4% to 6% annual dividend growth guidance through 2027. For our customers, we are committed to providing safe and reliable electricity and natural gas as we deliver a cleaner energy future without comprising on affordability. I look forward to updating you all on these matters and our new five-year plan at Investor Day in September. That concludes my remarks. I will now turn the call back over to Stephanie.

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

Q&A Session

Operator: Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions] Your first question will come from Maurice Choy at RBC Capital Markets. Please go ahead.

Maurice Choy: Thank you, and good morning. I wanted to start with TEP rate case. What are your views of the ALJ recommendations and what area that still has substantial gaps between your expectations and other participants’. And maybe bigger picture as well, as you approach a decision in Q3, what is your take of the Arizona [regulatory] (ph) process, relationship with the regulator, recognizing that a couple of years ago a decision by the ACC on another utility arguably caused some distress?

David Hutchens: Good morning, and thanks, Maurice, for the questions. And we have Susan Gray, who is the CEO of UNS with us today. Actually, we have a lot of our team here, [in Novi] (ph), because we just got done with some board meeting. So, I’ll let Susan address that. And if we miss any of the multiple questions in there, just shoot them back to us. Go ahead, Susan.

Susan Gray: All right, great. Good morning, Maurice. Thanks for the question. So, in terms of the ALJ’s recommended opinion and order, I think we’re fairly close. We’ve got the normal things that were not included, like LTI and various things like that, but I think the biggest gap here is the ROE and the fair value increment. And so, that was the exception that we filed in our testimony last week, was really pressing back on that ROE, that we’ve requested a 9.75%, and the ALJ has recommended a 9.4%. And her recommendation for the fair value increment is 0.2%, and ours is 0.66%, so, pushing back on that a little bit. She also did not recommend the expedited or accelerated depreciation at Springerville, nor did she support the system reliability benefit.

So, expecting to have those issues heard in the open meeting, next week, and see where those turn out. But I think, largely, we’re mostly aligned on all the other recommendations. I’d say the other big thing is the cost allocation that she’s recommending to shift more of the cost to residential customers versus commercial. So, we did recommend that that take a more gradual approach than what she is recommending. In terms of relationship with the commission, I think the decision that you’re referencing was a different makeup of commissioners. And so, two of those commissioners have been replaced since then, and I think we have a good relationship with our commissioners now, and I think that they have a commitment to improving the regulatory environment in Arizona, and we’ve seen some good decisions come out of the commission.

So, I think they’re headed in a better direction overall. Did I answer all of your questions or did I miss anything?

Maurice Choy: Absolutely. And thanks for that answer. And maybe just to finish off, as you look forward to the next update, in September, and also recognizing that you’ve put out your sustainability update report, thoughts of areas where you feel that the next ramp up in investments might come from? Do you expect clean energy, be that renewables as well as transmission, being a priority on the next plan?

David Hutchens: Yes, Maurice, we always talk about those additional investment opportunities we have to expand and extend our capital plan. And, obviously, we’ve been working hard in the different categories, Tranche 2 at ITC, in the MISO long-range transmission plan, as well as the remaining part of Tranche 1 additional clean energy investments. I mean, there’s a lot of stuff, and adaptation, resiliency investments, et cetera; a lot of different categories. But I can’t steal the thunder before the September conversation as we pull together that capital plan and we’ll roll that out then. But this is a good time for our industry and our sector and particularly for our key, large utilities for the opportunity to really see the clean energy transition accelerate with, obviously, the big catalysts like the Inflation Reduction Act, et cetera.

So, we’ll give you a full update on all those goodies, come September. Just a little commentary to add to Susan’s, just on the regulatory construct, because we are seeing a lot of positive momentum, and I just want to point out that the UNS team has done a fantastic in executing this rate case. And the commission has, as well, done a very good job in getting us on the agenda in a very timely manner. So, that’s another really positive sign when you can prosecute a rate case. And this was a full rate case, it wasn’t a settlement. In a timeframe like this, it’s kudos to all parties involved.

Maurice Choy: Makes sense. Since you mentioned Tranche 2, any update on the transmission ROFRs, be that in Iowa or look-throughs from proceedings in other states?

David Hutchens: No real updates now. So, they’re going through the process in Iowa and nothing new on the fronts in any other states. Obviously, it’s something we’ll be watching going forward, and combating, and out there pushing for the benefits that our customers need and deserve. And we think the way that we get fast, affordable; reliable clean energy connect to the grid is through ROFRs and existing transmission providers. So, we’ll continue to tell that to anyone who listens.

Maurice Choy: Agreed. Thank you very much for that update.

David Hutchens: Thanks, Maurice.

Operator: Your next will come from Rob Hope at Scotiabank. Please go ahead.

Rob Hope: Morning, everyone. Can you maybe just talk to the business development activities that are happening in the background? Transco was a nice investment that was not in the books so far. MISO opportunities continue to percolate to the top as well. So, when you take a look at your transmission investment, where are you seeing the opportunities rise to the surface quickest, whether it be ITC, some additional Transco, or even some stuff in Arizona?

David Hutchens: Yes, it’s all three of those, Rob. Obviously, ITC is the biggest transmission play that we have. But we — don’t forget that we have transmission in New York and Arizona as well. So, we are looking for — you know what we like, we like regulated rate base, and we continue to look for regulated rate base investment opportunities across all those portfolios. Obviously, we talk a lot about ITC and getting the rest of the Tranche 1 portfolio built, looking for what we can get in Tranche 2, and going through those processes. And then the New York Transco was one that we’ve been involved with for a while, but you never know when some of those big projects will hit because you have to bid in into that process, in New York, for those.

And then in Arizona, it’s a bit different. We look forward to build our [indiscernible] alignment that we have in our existing forecast. We look to build those transmission lines as needed to support that clean energy transition there as well. So, always looking for those opportunities to increase those investments in transmission in all three of those footprints, for sure.

Rob Hope: Appreciate that. The second question is a little bit shorter-term in nature. At Central Hudson, the show cause order and [indiscernible] on some plan there, could that be a drag on income for the next, we’ll call it, year? And whether or not they are accurately reflected in new rate application?

Jocelyn Perry: Rob, this is Jocelyn. No, with respect to the agreement, we’re not expecting any material impact on the financials for this year for it to be a drag, so not expecting any there. Show cause order is proceeding as not complete, of course, so we don’t have the full picture of it. But what we see thus far, there’s nothing material on earnings.

Rob Hope: Thank you.

Operator: Your next question will come from Linda Ezergailis at TD Securities. Please go ahead.

Linda Ezergailis: Thank you. Maybe if we could just delve a little bit more on this ROFR in Iowa. What are next steps and bookends of timing of when this might be resolved? Maybe you can just update us on any sort of evolved arguments that ITC might have on that front? And how confident are you that this will not be a potential precedent for other jurisdictions?

David Hutchens: Thanks, Linda. I’m going to turn that right over to our Linda, Linda Apsey who is CEO of ITC, as you well know.

Linda Apsey: Great. Yes, good morning. Thank you, Linda, for the question. In terms of where the current status and in terms of the process, right now, the Supreme Court essentially remanded its decision back to the Iowa District Court. And so, the judge has essentially established a scheduling hearing. I think the next step is, it’s early August, I think the state of Iowa has to file its written response. And so, that’s sort of a near-term next step. As is always the case with the courts, there is no mandated timeline for a decision. And so, unfortunately, I can’t give you any specific indication as to what the timeline is. I think as I’ve stated before on ROFRs in terms of our arguments and our position, if you recall, the key issue that was — the Supreme Court rendered their decision on was that it was the sort of the process in which the Iowa legislature passed the ROFR law.

It did not need the statutory — or they claim that it did not meet the statutory requirements in terms of it has to be a single-issue piece of legislation with the appropriate title of a piece of legislation. And so, that was what the Supreme Court had found was unconstitutional, and therefore remanded it back to the district court for the — essentially now that LS Power, who was the applicant in the case, claiming that they now have standing to then challenge the legislation. So, our view is, obviously, we are going to continue to vigorously defend our position, both as it relates to the process and certainly the state of Iowa. The attorney general will obviously take the lead on defending the legislature’s authority. And obviously, to the extent there are additional arguments and claims around constitutionality of a ROFR around the context of competition, we will be vigorously defending our view, and our role and position along with the other parties in the case.

In terms of is this precedential, I would just identify and remind you that there are 15 other states that have state ROFRs in place. The ROFR has been challenged, for example, in Minnesota. It was challenged the circuit court — or the U.S. district court came to a ruling, a rendering that, in fact, state ROFRs were indeed legal. However, there is a case in Texas that essentially the court essentially deemed that the ROFR was not legal, and that case has been sort of — I guess is now in the hands of the U.S. federal court with the Department of Justice weighing in to render a decision. So, Linda, I would say with all of that, no doubt there is certainly a lot of activity around ROFRs. Ultimately, we fall under federal jurisdiction. Transmission, because of interstate commerce falls under federal jurisdiction.

So, ultimately, to the extent that these issues continue to be litigated, it ultimately will fall under the jurisdiction of federal courts. And if it continues to be pursued, I would imagine this will take years to work its way through the process ultimately, given that multiple parties will challenge and use their appeal rights to whatever extent necessary.

David Hutchens: I would just add one thing, and that’s that not all ROFRs are the same. So, each state has some different definitions there, and the Texas one is a bit different. So, that the challenge that may be seen in the Texas one may not be obviously applicable to ones that are designed differently in the other states.

Linda Ezergailis: That’s helpful context, I guess, just high level. Now, just moving on as a follow-up in terms of Central Hudson’s offshore wind transmission Transco potential project, how do you think about any sort of incremental construction and operating risks associated with offshore transmission? How might that translate into either financing or return expectations? And is this a potential new avenue for growth with the potential for additional similar investments over time?

David Hutchens: Yes, Linda. So, it’s transmission for offshore wind facilities, but our portion is the onshore portion. So, it’s nothing different than the transmission risk profile that we see in any type of project that we do. And of course, being that part owner of New York Transco, we expect them to be bidding in on other projects on a going forward basis and seeing some potential pickup from those as well.

Linda Ezergailis: Thank you.

Operator: Your next question will come from Mark Jarvi at CIBC Capital Markets. Please go ahead.

Mark Jarvi: Thanks. Good morning, everyone. Just on New York Transco, can you remind us again, what is the ROE and equity thickness for that Transco?

David Hutchens: I’ll turn that right over to Chris Capone, our CEO from Central Hudson.

Chris Capone: Sure. Good morning, Mark. The equity layer is 53%. The ROE is 9.65%.

Mark Jarvi: Got it. And then, just with the FERC’s order 2023, just your thoughts in terms of what that means. Does that impact at all in terms of how MISO goes forward, the long range planning in terms of decision making in that process?

David Hutchens: Go ahead, Linda.

Linda Apsey: Great, thanks. I think, you said 2023 the generator interconnection ruling is that what you’re referring to? Okay. Clearly, obviously our perspective is, I think that it was a well expected, anticipated decision in order. I think it’s consistent with how we felt FERC would rule on it. As you likely know, it essentially allows generation developers sort of first ready, sort of first out. They’re going to study generator projects in clusters, and then obviously, it imposes timelines for transmission owners to study the interconnection request. So, I think all of that told, I think as we step back from it, I will say we’re still digesting the order. It was 1,400 pages. And so, our teams are busy, obviously digesting the order, but I would say from sort of a broad perspective, I think we view it as very constructive and positive in terms of it will no doubt allow more generators to continue to move through the queue more quickly and bring those generators obviously online quicker, faster, sooner.

So, certainly, I think from a broad perspective that will likely drive more generator interconnection requests because more generators will have the ability to connect. So, we view it as constructive and positive. And certainly, I think it was in line with our expectations.

David Hutchens: Yes, Mark, just a little additional color on what this does, big picture wise, transmission, from a transmission perspective as well, again another positive piece of the puzzle, it does break the log jam from an interconnection perspective so that we can hopefully get these, as Linda mentioned, get more projects connected more quickly. But in the end, what that’s doing is pushing obviously the need for the transmission development downstream in order for us to deliver all that, the interconnections and the system upgrades and the things that are needed then to support the renewables and other generators that get connected is going to push towards more transmission development, which is obviously what’s going on in the MISO long range transmission plan.

But that’s followed on the heels of the siding and permitting reform that was part of the Fiscal Responsibility Act as well. So, all these pieces are starting to fall and none of it’s perfect by any means yet. And there’s still always work to be done on cost allocation and things like that. And the next step, hopefully in siding and permitting reform that we can get in the U.S. related to some of the bigger issues around, basically the level of legal reviews, et cetera that are needed for some of those permits and siding. But the pieces are starting to fall in place. And that’s, again, another positive from the transmission front.

Mark Jarvi: Yes, certainly encouraging. Just in terms of the tranche, too, at MISO, does this change at all timelines, and when do you think you’ll have clarity there?

David Hutchens: No, the assumption is mid-year 2024.

Mark Jarvi: Got it. Okay. And then, just coming back to TP rate case with the open meeting next week, should we assume that you’ll have a decision at the end of that, or is there any risk that the decision gets pushed or they don’t review your specific rate case decision next week?

David Hutchens: Well, it’s on the agenda. It’s scheduled. It’s hard to say whether or not there’s never 100% guarantee that the agenda goes through as designed, but we’re obviously very hopeful, and we’ll be doing everything we can from our team’s perspective on getting it through the process there during next week’s open meeting. So, we can’t give you that level of certainty, but we sure are hopeful and definitely positive on getting that done.

Mark Jarvi: Sounds good. Okay. Thanks, everyone.

David Hutchens: Thanks, Mark.

Operator: Your next question will come from Ben Pham at BMO. Please go ahead.

Ben Pham: Hi, thanks. Good morning. I got a question on your Slide 24 to Q2 sales trends. And I’m looking at some of the sales numbers, and it’s interesting to see the Canadian side of things with some pretty good growth on consumption and then some other data points in the U.S. with some milder weather conditions. Can you give me the comment on it is quite a divergent difference? Do you think that’s more of a regional situation in Q2 or is there some sort of customer consumption behavior changes that you’re seeing?

David Hutchens: Yes, let me take a crack at that as I’m rustling through well, I’m not really rustling. I’m scanning through pages here on my iPad here to get to that page. I would say that in general, most of what we’re seeing variability wise in the U.S. was weather related. I think that was really consistent across the entire U.S., even though these are disparate jurisdictions in Arizona and New York, that mild weather was pretty prevalent. So, there’s no underlying read through to commercial industrial economic activities on those for sure. And then on Fortis Alberta, that actually probably is due to some more underlying it’s not really weather related, but a little bit more underlying economic activity and growth that we’re seeing in the commercial and industrial sectors.

And similarly, BC is probably in that same bucket. So, I would expect and this is me just going out, looking out into the future, particularly at the U.S. utilities. I’ve been one who thinks that the level of onshoring, reshoring additional manufacturing that’s going to be needed for the clean energy transition and that is really pushed by the Inflation Reduction Act and the way that the domestic content rules are in there. I really think that we’re standing on a cusp of good economic development, strong economic development in some of our key areas particularly like the Midwest and MISO and Michigan in particular here and Arizona. So, we’re looking forward to seeing some of that increased economic activity as we go forward.

Ben Pham: Okay, that’s good context. And my second question is, when you look at just some of the North American utility activity with moves towards Pure Play names, I guess that’s kind of what you’ve been doing the last few years, shedding Oneita and then the storage business become Pure Play. We saw a pipeline company last week also look at a restructuring. Can you maybe just comment high level, just thoughts on really your observations there? And do you think that Fortis is well positioned now from just the overall corporate structure?

David Hutchens: Yes, for sure, Ben. I would say that even before we did any of those transactions, we were at most a couple of percent that was not regulated utility investments, and now basically post Aitken Creek will be essentially rounding 100% regulated. So, that was some things that we were working on over time. And it was it was more opportunistic finding value where we could at the times that we could. Aitken Creek specifically, as I mentioned on the last call, it’s a great opportunity because we found someone who can squeeze more value out of that asset than we can, and that ends up being good for everyone. But yes, I mean as we sit here today and as we hopefully wrap up Aitken Creek by the end of this year, that’s about as pure play as you can possibly get.

Ben Pham: All right, so there’re no plans. Another theme is to get small, to get big, any up happening in the board conversations?

David Hutchens: Say that again, Ben. You broke up a little bit.

Ben Pham: Yes, another theme that we’ve seen is companies getting smaller to get big, like whether carving out assets and a high growth company, and you have a lower growth company. Is that anything that Fortis is reviewing or looking at?

David Hutchens: I mean as part of any utilities, fiduciary responsibility. We’re always looking at our portfolio, but there’s, you look for opportunities and be opportunistic, but nothing here on the horizon.

Ben Pham: Okay, got it. Okay, thank you.

David Hutchens: Your next question will come from Andrew Kuske at Credit Suisse. Please go ahead.

Andrew Kuske: Thanks. Good morning. In the quarter, you had milder weather in Arizona, and I guess for the last month or so, it’s been anything but mild in Arizona. And may be if you just give us some context on system sales, system reliability, any issues that have sort of perked up in the last little while, given the heat wave?

David Hutchens: Yes, we can’t give you any numbers related to that other than I can give you a bit of an additive. It’s been really hot, so that we can say with certainty, a lot of heat in Arizona, particularly in Phoenix, but also down in our service territories around Tucson. So, the context that I give you is operationally. And so far we have been managing successfully without any operational issues to maintain the generation that we need to serve that load. And one of the things that’s a bit different this time around than it was in 2020, we’re probably every bit as hot as we were in 2020 and loads are probably at those kind of similar levels, but there isn’t the coincidence heat out in California. So, from a regional perspective, there’s a little bit more resources available. And also there’s been a lot of battery additions in California as well. So, it’s a little bit more stable of a system that we’re riding through this heat wave on.

Andrew Kuske: Okay, appreciate that. And then, maybe just more broadly across the entire portfolio. You do cover a fair amount of geography. Are you seeing any differences in inflationary pressures across the portfolio? Are there certain pockets that maybe have greater wage inflation and obviously your cost of service and virtually everywhere you operate, but are there pockets of different inflationary pressures coming across the whole asset portfolio?

David Hutchens: Not really. I mean it is fairly consistent. I mean, there’s higher cost of living areas like in Southern Lower Mainland and British Columbia that can lead to a little bit more wage inflation there. But I can’t really call out any as I’m thinking around the horn in my head on the different utilities. I can’t really think of any of those that are standing out to me. So, if they’re not standing out to me, they probably don’t need to stand out to you.

Andrew Kuske: Okay, I appreciate that. Thank you.

Operator: [Operator Instructions] Your next question will come from Michael Sullivan at Wolfe Research. Please go ahead.

Michael Sullivan: Hey all. Good morning.

David Hutchens: Hey, Michael.

Michael Sullivan: Hey, Dave. Just wanted to ask on the Investor Day, are there any new disclosures you’re kind of kicking around as potentially rolling out beyond the traditional capital plan, dividend growth refresh, any consideration given to — starting to give longer term earnings guidance?

David Hutchens: So, right now we are still putting together all the things that we are going to cover on that Investor Day. So, we really can’t cover anything new before then. But we are looking forward to seeing our analysts and investors in St. John’s, and having a good conversation about how we see the company going forward, but really no additional details to give around that at this point.

Michael Sullivan: Okay. And then, in Arizona, are you still planning to file an updated IRP this month? And then if we assume that that you don’t get the assisted benefit rider in a rate case, what does the process look like for pursuing something like that beyond the case?

David Hutchens: Yes. So, we have pushed back the filing of the integrated resource plan in Arizona to November. We needed some additional time because we are running so many scenarios down there that we do need that additional time during the stakeholder process along with it, because that’s where a lot of these scenarios are coming from as stakeholders asking to run a bunch of different scenarios and models. So, we are not filing that until November. What was the second-half of your question?

Michael Sullivan: Just as it relates to the renewal — [multiple speakers] the rate case, what’s the plan?

David Hutchens: Yes, if we don’t get now. And we have a couple of more bites at the apple. We’ll see how the opening goes next week. And if we still don’t have any clarity on what the process might be in getting that going forward; hopefully, we can get some sort of generic docket going so that we can evaluate what a track would look like, what would be considered inappropriate from both our perspective and the rest of the stakeholders, go through a process define something, which we have done many times on renewable portfolio standards and energy efficiency standards et cetera down there. So, go through a general process. And then, look to file something to implement in the next rate case. So, a couple more bites at the apple. Most of our renewable energy investments are later in the five-year plan. So, we’ve got time. So, we are hopeful that we can still get something like that done over the next few years.

Michael Sullivan: Great. Thanks a lot.

Operator: As there are no further questions at time, I would like turn the call back to Ms. Amaimo.

Stephanie Amaimo: Thank you, Michelle. We have nothing further at this time. Thank you, everyone for participating in our second 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: Ladies and gentlemen, this does indeed concludes your conference call for this morning. Thank you again for participating. And at this time, please disconnect your lines.