Fortis Inc (FTS) 2023 Q2 法說會逐字稿

Good morning, everyone. Thank you for standing by. My name is Michelle and I will be your conference operator today. Welcome to 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.

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 US 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.

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 and 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 marked 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 2 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 and 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 5-year capital plan consisting of virtually all regulated investments and 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 US$2.2 billion 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.

Thank you, David, and good morning, everyone.

Slide 9 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 favourable impact of a higher average U.S. to Canadian dollar foreign exchange rate of 1.34 in the quarter compared to 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 of the quarter except on a year-to-date basis higher earnings at UNS were driven by favourable 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-based growth. For our Western Canadian utilities, timing of operating costs at Fortis Alberta also favourably impacted the quarterly results, 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-based growth, tempered by higher finance costs. EPS was lower by CAD 0.01 for our US electric and gas utilities with Central Hudson increasing CAD 0.01 and UNS down CAD 0.02. Central Hudson's results reflect rate-based 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 6-month period. As you may recall favourable market conditions in the first quarter resulted in higher wholesale sales and FERC 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 US$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 US$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 minus 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 recommended opinion and order, proposing a non-fuel revenue increase of US$102 million with new rates expected to be effective in September. The ALJ's recommended rate base of US$3.6 billion and equity ratio of approximately 54% were consistent with TEP's revised request. The ALJ also recommended an 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 it's 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 the 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 per their normal regulatory cycle, as the current 3-year plan concludes on June 30, 2024.

Turning to Western Canada, FortisBC filed its final reply arguments earlier this year on 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.

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're 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 a 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 compromising on affordability. I look forward to updating you all on these matters and our new 5-year plan at Investor Day in September.

That concludes my remarks. I will now turn the call back over to Stephanie.

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

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.

I wanted to start with the TEP rate case. What are your views of the ALJ recommendation and what areas 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 process, your relationship with the regulator recognizing a couple of years ago, a decision by the ACC on another utility arguably caused some distress?

We have Susan Gray, who is the CEO of UNS, with us today. Actually, we have a lot of our team here in Novi because we just got done with some Board Meetings. 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.

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 in 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, we'll 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 is 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 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.

And maybe just to finish-off as you look forward to your next update in September and also recognizing that you've put out your Sustainability Update Report. Thoughts on areas where you feel that the next ramp-up and investments might come from? We expect clean energy, be that renewables, as well as transmission being a priority in the next plan.

Yeah. 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 and 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 steal the thunder for 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 job in executing this rate case and the Commission has as well done a very good job in getting this 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, and the timeframe like this it's kudos to all parties involved.

And since you mentioned Tranche 2, like any update on the transmission ROFRs be that in Iowa or look through from proceedings in other states?

No real updates now. So they're going through the process in Iowa, and nothing new on the front in the 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 connected to the grid is through ROFRs and existing transmission providers. So we'll continue to tell that to anyone who listens.

Your next question will come from Rob Hope at Scotiabank.

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

Yeah, 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 of 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 like our Vail-to-Tortolita line 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.

And then the second question is a little bit shorter term in nature. At Central Hudson, the Show Cause order and acceleration on some plans there. Could that be a drag on income for the next, for call it, year and whether or not they're accurately reflected in the new rate application?

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 proceeding is not complete, of course, and we don't have the full picture of it. But what we see thus far, there is nothing material on earnings.

Your next question will come from Linda Ezergailis at TD Securities.

Maybe if we could just delve a little bit more on this ROFR in Iowa. What are the 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?

I'm going to turn that right over to our Linda, Linda Apsey who is CEO of ITC as you well know.

In terms of 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 steps. 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 kind of what the timeline is. I think as I've stated before on ROFRs in terms of sort of our arguments and our position, if you recall, the key issue that was the Supreme Court render their decision on was that it was the sort of the process in which the Iowa Legislature passed the ROFR law, it did not meet 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 kind of is this presidential, 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.

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 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.

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?

So it's transmission for offshore wind facilities, but our portion is the onshore portion. So it's nothing different than 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 other projects on a going forward basis and seeing some potential pickup from those as well.

Your next question will come from Mark Jarvi at CIBC Capital Markets.

Just on NY Transco, can you remind us again what is the ROE and equity thickness for that Transco?

I'll turn that right over to Chris Capone, our CEO from Central Hudson.

The equity layer is 53%, the ROE is 9.65.

Got it. And then just with the FERC order 2023, just your thoughts in terms of what that means? Is that impact at all in terms of how MISO goes forward the long range planning or in terms of decision-making in that process?

Go ahead, Linda.

I mean, I think you said 2023 the generator interconnection ruling --

Yes, exactly.

Is that what you're referring to. Okay. Yeah. So clearly, I mean, obviously our perspective is, I think that is a well-expected, anticipated decision and 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.

Yeah. Mark, just a little additional colour on what this does big picture-wise from a transmission perspective as well. Again, another positive piece of the puzzle, it does break the logjam 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 siting 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 siting 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 that are needed for some of those permits and siting. But the pieces are starting to fall in place, and that's again another positive from the transmission front.

Yes, certainly encouraging. Just in terms of the Tranche 2 and MISO does this change at all timelines when you think of clarity there?

No, that's still -- the assumption is mid-year 2024.

And then just coming back to TEP 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 of the decision gets pushed or they don't review your specific rate case decision next week?

Well, it's on the agenda. It's scheduled. It's hard to say whether or not you can -- there's never a 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, 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.

Your next question will come from Ben Pham at BMO.

I had a question on your slide 24, 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 some other data points in the U.S. So some milder weather conditions, can you maybe comment on -- it is quite a divergence difference, do you think that's more of a regional situation in Q2 or is there some sort of customer consumption behaviour changes that you're seeing?

Yeah, let me take a crack at that as I'm rustling through -- well, not really rustling, I'm scanning through pages here on my iPad here to get to that page. I would say, 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 that mild weather was pretty prevalent. So there is 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 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 in 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 in 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.

And my second question is, when you look at just some of the North American utility activity was moved towards pure-play names, I guess, that's kind of what you've been doing the last few years, shedding Waneta and then the storage business become pure-play. We saw pipeline company last week also look at restructuring. Can you maybe just comment high-level just thoughts on really your observations there? Do you think that Fortis is well positioned now from just the overall corporate structure?

I would say that even before we did any of those transactions 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 more opportunistic finding value where we could at the times that we could, Aitken Creek. And 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 yeah, 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.

So there is no game plan, so, I mean, another thing is that they get small to get big, is any of that happening in the Board conversations?

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

Another theme that we've seen is companies getting smaller to get big, like whether carving out assets and higher growth company and you have a growth company, is that anything that Fortis is reviewing or looking at?

I mean, as part of any utilities fiduciary responsibility, we are always looking at our portfolio, but there is -- you look for opportunities and be opportunistic, but nothing here on the horizon.

Your next question will come from Andrew Kuske at Credit Suisse.

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. Maybe 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?

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'd 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 hard as we were in 2020 and loads are probably at those kind of similar levels, but there isn't a coincident 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.

And then maybe just more broadly across the entire portfolio business. 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 to service in virtually everywhere you operate, but are there pockets of different inflationary pressures coming across the whole asset portfolio?

Not really, I mean, it's fairly consistent, I mean there is higher cost of living areas like in Southern -- lower mainland in 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.

(Operator Instructions) Your next question will come from Michael Sullivan at Wolfe Research.

Hey David, 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?

So right now, we're still putting together all the things we're 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.

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

Yeah. So we have pushed back the filing of the integrated resource plan in Arizona to November. We needed some additional time because we're running so many scenarios down there that we do need that additional time to bring 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.

So what was the second half of your question?

Just as it relates to the reliability rider, what's the plan?

Yeah. If we don't get that now and we have a couple more bites at the apple, we'll see how the open meeting goes next week. And if we still don't have any clarity on what the process might be and getting that going forward. Hopefully, we can get some sort of generic docket going so that we can evaluate what a tracker would look like, what would be considered an appropriate from both our perspective and the rest of the stakeholders go through a process and define something, which we've 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 the next rate case. So a couple of more bites at the apple, most of our renewable energy investments are later in the 5-year plan. So we've got time. So we're hopeful that we can still get something like that done over the next few years.

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

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.