Hello, and welcome to the Algonquin Power & Utilities Corporation First Quarter 2025 Earnings Conference Call. — Operator Instructions — I will now turn the conference over to Mr. Brian Chin, Interim Chief Financial Officer and Vice President of Investor Relations. Please go ahead.

Thank you, operator, and good morning, everyone. Thank you for joining us for our first quarter 2025 earnings conference call. Joining me on the call today will be Rod West, Chief Executive Officer; and Sarah MacDonald, Chief Transformation Officer. To accompany today’s earnings call, we have a supplemental webcast presentation available on our website, algonquinpower.com. Our financial statements and management discussion and analysis are also available on the website, as well as on SEDAR+ and EDGAR. We’d like to remind you that our discussion during the call will include certain forwardlooking information and non-GAAP measures. Actual results could differ materially from any forecast or projection contained in such forward-looking information. Certain material factors and assumptions were applied in making the forecasts and projections re- flected in such forward-looking information. Please note and review the related disclaimers located on Slide 2 of our earnings call presentation at the Investor Relations section of our website at algonquinpower.com. Please also refer to our most recent MD&A filed on SEDAR+ and EDGAR and available on our website for additional important information on these items. 1 On the call this morning, Rod will provide brief commentary on his first 60 days at Algonquin, followed by a review of key highlights and operational updates for the quarter. I will then detail our financial results. We will then open the line for questions. We kindly ask that you restrict your questions to 2, then requeue if you have any additional questions to allow others the opportunity to participate. With that, I’ll turn things over to Rod.

Thank you, Brian, and good morning, everyone. Before I provide my opening remarks on the quarter in my first 60 days, I first want to acknowledge the heartbreaking incident that occurred on April 9 in Lexington, Missouri within our gas service territory. As members of the community, our thoughts and prayers remain with the affected families whose lives have been devastated by the tragedy. Our hearts are with you. Nothing is more important to me and to this company than the safety of our customers, employees and communities. We remain fully committed to working with the authorities to support the ongoing investigation into the cause of the accident, and we will continue to work in partnership with the community on restoration and recovery initiatives. Moving now to my comments on the quarter. I’d like to start things off by thanking you for your interest in Algonquin, for continuing to support the company through this transformative journey and for welcoming Brian and I into our new respective roles. It’s been a busy first 60 days for me, having had the opportunity to meet with many of our stakeholders and visit several of our regional offices. My observations are consistent with the remarks I shared on the Q4 call. I see significant opportunity ahead, but there’s still a tremendous amount of work to do. Algonquin has real potential to be a premium utility. We have a solid, diversified asset base and many talented and hard-working employees. But we have yet to consistently evidence the practices that set premium utilities apart from the rest. 2 Some areas of improvement that come to mind include improving our customer outcomes first, and community engagement, leveraging our economies of scale. I look for- ward to sharing more insights on our path forward. As promised, we plan to provide a forward-looking multiyear update on June 3, which falls approximately 90 days from our Q4 2024 call and my first day in the seat. Also on June 3, I plan to share more of my observations regarding the company. And later this year, I do expect to provide a little more color into our longer-term strategic thinking and positioning of the portfolio. With that, let’s now turn to the operational highlights from the quarter. Starting with regulatory updates. On March 25, the New Hampshire Public Utilities Commission issued an order approving the Granite State Electric settlement agreement, with new rates having taken effect on April 1. On April 21, the New Hampshire Commission further extended a stay of the EnergyNorth Gas rate case proceeding until May 30, allowing more time for settlement negotiations to be completed. On our Empire Electric Missouri rate case, the commission extended the test year true-up period from September 30, 2024, to March 31, 2025, which provides an opportunity for us to capture capital invested during that time frame in our rate filing. Moving to a brief update on the Missouri Commission investigation into our customer service and billing issues. As stated on the Q4 call, the investigation opened at the end of February, and we have been working with the investigation team responding to data requests and providing answers to their questions. Shifting from state-level rate cases to transmission. As discussed last quarter, the Southwest Power Pool, SPP, approved its 2024 Integrated Transmission Plan, the largest port- folio of transmission projects ever undertaken by [ SPO ], totaling roughly $7.7 billion. A significant share of this transformative investment approximately $750 million to $800 3 million is dedicated to strengthening the Empire District Electric service area, underscoring the region’s critical role in the future of the grid. Within the Empire District Electric footprint, the approved upgrades encompass approximately 80 miles of 161 kV rebuilds or conversions, 9 miles of new 345 kV transmission lines and the construction of 2 large-scale transmission stations. On April 23, the Empire accepted the first tranche of notices to construct, or NTCs, for the 161 kV portion of the portfolio. Empire has also received the second tranche of NTCs, and the next step is the official acceptance of the second tranche of NTCs submitted to SPP on or before June 19. We’re excited for the opportunity these projects represent for our stakeholders. I’ll now turn things back to Brian to review the financial highlights from the quarter. Brian?

Thanks, Rod. In a short summary, it was an encouraging quarter for our key financial metrics. First quarter adjusted net earnings from continuing operations were $111.6 million, up from – up 39% from $80.1 million in 2024. 43% increase of $40.8 million in net earnings for the Regulated Services Group was primarily due to the implementation of new rates of $15.7 million and lower interest expense of $13.6 million as a result of debt repayment with the proceeds from the sales of the Renewables business and our Atlantica stake. Our depreciation expense was relatively flat year-over-year. Our usual organic growth and depreciation expense was partly offset by $8.2 million in nonrecurring favorable pickups related to regulatory orders in New Hampshire and Arizona. The $13.4 million increase in net earnings for the Hydro Group was primarily due to a onetime tax recovery related to the sale of the Renewable Energy business. Our expectations of an effective tax rate in the 4 mid- to low 20% range for the year has not changed. And as we have said before, we do expect a bit of lumpiness in our quarterly tax profile. On the Corporate side, our adjusted net earnings decreased by $22.7 million related to the removal of Atlantica dividends. Moving to our EPS walk. Q1 adjusted net earnings per share were $0.14, which is flat to last year’s Q1 2024 adjusted net earnings per share of $0.14, which includes Renewables, and yet above last year’s Q1 2024 continuing operations, adjusted net EPS of $0.11, excluding Renewables. Starting with last year’s $0.14, including Renewables. Year-overyear drivers include a negative $0.03 attributed to the Renewable sale, an increase of $0.03 for new rate case contributions from New York Water, BELCO and Midstates Gas, as well as increased customer demand and another $0.02 of contribution from lower interest expense from use of Renewables and Atlantica sales proceeds to pay down debt, net of financing for organic growth. Mirroring my earlier comments, we had approximately a $0.01 pickup from nonrecurring items, favorable items, based on depreciation related to regulatory orders in New Hampshire and Arizona. Aside from the Regulated business, we captured a $0.02 increase for the onetime tax recovery related to our Hydro Group, a decrease of $0.03 for the removal of the Atlantica dividend and a reduction of $0.02 for an increase in weighted average shares outstanding. For the last 2 quarters, our adjusted net EPS impact from dilution has been tracking to a $0.01 each quarter. But since our results are proportionally skewed to Q1, this mathematically increase our dilution to $0.02 for this quarter. Let me pause here on nonrecurring items embedded in this walk. If one takes the positive penny from regulatory orders related to depreciation and the $0.02 from the Hydro tax recovery, our adjusted net EPS includes a total of $0.03 of favorable nonrecurring items in the quarter. And given our unchanged view of an effective tax rate in the mid- to low 20% range, we expect a portion of the effective tax rate nonrecurring items to reverse 5 over the remainder of the year. In keeping with our goal of reducing complexity, the company’s financial disclosures now focus primarily on adjusted net earnings and adjusted net earnings per share and earnings per share, as we view these as our key financial metrics. Our simplified financial disclosure includes net earnings from continuing operations separated into Regulated, Hydro and Corporate segments in our financial statement footnotes. A few comments now on our credit metrics. Simply stated, our credit metrics are healthy. For year-end 2024, S&P indicated our FFO to debt was 12.5%, comfortably above the requisite BBB threshold of 11%. Fitch indicated our debt-to-EBITDA was 5.6x, appropriately below the requisite BBB threshold of 5.8x. These metrics were measured before net deleveraging proceeds to continuing operations were received from the sale of the Renewable Energy business on January 8. And now back to Rod for closing remarks.

Thanks, Brian. As per our press release this morning, I want to highlight to our listeners to save the date for our investor update call on June 3, which I referenced earlier. We expect this outlook, which will be primarily based on the current portfolio, will include projected adjusted net EPS ranges for ’25, 2026 and 2027, with more detailed thoughts on the company and its potential after my first 90 days. I also aim to share my broader strategic thinking on the broader portfolio later this year. Thanks to everyone for joining us on the call this morning. I am excited and motivated by the opportunities ahead, and now the management team is available to answer your questions. Operator? 6

— Operator Instructions — Your first question comes from the line of Robert Hope with Scotiabank.

I won’t ask about the forward outlook, but maybe a little bit backwards looking. Rod, you’ve been here for a number of weeks, months now. Can you maybe walk us through kind of what you think the most impactful changes you’ve made to the organization so far have been?

Yes, it’s interesting that you say months because it is literally 2 months. So the S and month look back is literally 1 month. But my focus and the initial sort of impact has been setting a vision for what a premium pure-play utility looks like. And setting the attributes of a pure-play utility to the corporation, which informs the work we’re doing to lower our overall cost profile to make room to do more on the capital and O&M front. But also a focus on improving our stakeholder engagement capacity and sort of discipline. Again, these things are notional because I’m communicating them to the organization as I’m setting ourselves up to actually execute on those plans. And the way that they will ultimately play out, our own outcomes for our stakeholders for the investment community, we’re talking more and we’ll be talking more about total shareholder return from the customer perspective. We’ll be talking about Net Promoter Score and specific customer outcomes that will drive our capital plan. And our sort of organizational health, the motivation to help the alignment of our employees’ actions to create sustainable value for those 4 key stakeholders. 7 And the metrics that we’re paying attention to are the types of things that will give us our stage gates along the way so everybody has a clear understanding of where we’re headed and what are the milestones along the way that will separate us from good to great. The good thing is that, that we have a lot to work with. And that’s the biggest part of my initial evaluation is that we have really quality assets, and we have a group of employees who are really motivated to turn our performance around.

All right. I appreciate that color. Second question, moving over to the SVP projects. So you have 2 tranches with good clarity right now. Do you know how much capital that could be versus the $750 million to $800 million that you referenced, as well as when would that capital start being spent?

We haven’t disclosed anything beyond what is currently public. So I don’t anticipate that we’ll do so until we’re further along. But the short answer is my expectation is that if we’re successful in executing on what’s in front of us, we’ll be in a better position to capture and execute on additional CapEx opportunities in that space.

Your next question comes from the line of Sean Steuart with TD Cowen.

A couple of questions. I want to start with investigations. So there’s another investigation in Arkansas and an audit in New Hampshire. And I’m just trying to gauge, are these the same billing issues that you’re dealing with in the Missouri investigation? And do you have any perspective on timing resolution for these various investigations and audits?

8 I don’t believe New Hampshire is a customer-related investigation, but the other investigations have to do with the billing issues, the timeliness of billing associated with the deployment of an overhaul of a new system. And we’re working with the regulators and the state in each of those circumstances. From my initial observation that our challenges were not unlike other utilities who have gone through system deployment, I think where we have fallen short and are seeking to remedy it, is that we did not do a good job of stakeholder engagement prior to the deployment of the system, which left a lot of folks surprised when the normal – what I would consider to be the normal hiccups associated with the scale of the system overhaul that we implemented – we didn’t, in my view, at least view the conditions precedent to making it a smoother transition for customers and regulators. But we’re closing that gap as we speak. And I don’t – I am not surprised at all by the attorney generals or whoever else who was initiating investigations because we put them in a position where they had to do that. I do expect us to work through them. And I have personally gone to those respective states to represent my commitment to follow through and cure the issues that the customers have been experiencing. But we’ll continue to participate and support the work of the states and closing out these customer complaints.

Okay. Second question, wondering if there’s any update on your thinking around the Hydro portfolio, potential time line towards divestiture, how the thinking has evolved and the current valuation environment?

Yes. And now if we do a double click, I’ll let Brian talk more about it, but my perspective is consistent with the position we’ve taken. We’re looking to transact, but the condition precedent has to be it being value-accretive. Not from a singular EPS perspective, but 9 certainly from a balance sheet and a strategy accretive perspective as well. And we’re monitoring the market environment for potential offtakers, but it has to be something that is – that we view as net accretive. And I don’t know that there’s a specific time line that we feel forced to pursue, but should that opportunity arise, I am – I have given the go ahead that we’ll transact if those conditions are met. Brian?

Yes. And Sean, as a reminder, our thought process is that we would be looking at that in the first portion of this year. Obviously, with the leadership transition and our thought process on the portfolio strategy has been evolving here. We’ve pushed back the timetable a little bit, but everything that we said before about it being value accretive on a number of fronts, that remains consistent.

Got it. Okay. Thanks very much, guys. Much appreciated.

Your next question comes from the line of Nelson Ng with RBC Capital Markets.

Quick question on the whole CRM implementation. Can you just comment about – I think in the past, you talked about how the CRM implementation would result in cost savings. And I just had a look at the operating expenses of the utility division, I think costs have increased by just 1.5% year-over-year. So that’s obviously lower than inflation. So that’s good. But can you just talk about realizing cost savings in the business, big picture and maybe give a bit more color going forward as well?

Sure, Nelson. It’s Sarah MacDonald. So the implementation was not just about cost sav10 ings. There were a lot of other customer benefits that we – are now coming to fruition. When we were starting to implement, we had multiple systems, no integration and issues in making sure that customers had access visibility, ability to go online and look at their bills. And so there was certainly a lot more benefits to the customer coming in. Ultimately, when the system is functioning optimally, you will start to see cost – we’ll start to be able to realize the benefits of that integration. But for now, we’re looking – we’re focused on getting it implemented right and making sure the customer experience is better.

And the cost benefits are not going to be specifically called out solely to the implementation of the platform. But you would expect to see more digital channels, lower calls from customers because we’re providing more self-help options and lower paper expenses, but those would be reflected in our overall O&M numbers and not just attributed to one specific platform, just on a future basis to understand where we’ll be coming from.

Okay. And then the second question probably relates to Brian. So just a quick one on the noncontrolling interest earnings of $18.9 million. I know in the past, you kind of singled out HLBV as a line item. Is this item, is it all HLBV? Or are there several items lumped together into earnings attributable to the noncontrolling interest absolutely...

So it’s primarily HLBV income. The other significant piece of that, and it’s a relatively small piece is the minority interest related to the ownership stake in Suralis down in Chile.

Your next question comes from the line of Rupert Merer with National Bank. 11

Good morning, everyone. If I could start with a follow-up on the operating costs. I think with the billing issues you’ve had in previous quarters, it did incur some added costs. Are you still seeing added costs related to those issues? Or is that largely in the rearview mirror now? And when we look at those operating costs, are they more representative of what we should expect in future quarters?

Yes, Rupert. So when we started experiencing those billing issues, the extra cost that we did call out in the Q4 materials was bad debt expense. And that’s where we saw the majority of that. You saw a little bit of that this quarter, but it wasn’t really enough for us to call out specifically. And definitely, the trend line is moving in a more improved direction. I think going forward from here, that we would expect that, that would temper off, just given the trajectory of where our customer billings exceptions are at. So the short answer, Rupert, is we reported the majority of that in Q4.

And last quarter, you talked about some dis-synergies related to the sale of the Renewable group. It seems like the costs in the Renewables and Corporate Group have come down significantly. Have you largely dealt with these dis-synergies? Or are there any other sort of plans you can discuss to lower cost in the near term? I understand some of this maybe things you want to talk about on June 3.

Yes, Rupert. So last year, if you look at the year in aggregate, we had roughly $18 million in dis-synergies that affected our OpEx numbers last year. For the first quarter, it’s at a smaller amount. It’s less than a $0.01 of dis-synergies that we’re seeing. We didn’t call it out specifically in the materials just because of the size. We do expect that as we’re 12 continuing to execute greater operational and capital discipline on the company that the eventual removal of those dis-synergies will manifest themselves through the outlook. But at this stage, for the quarter, it just simply wasn’t large enough for us to call out. So we do think that that’s a helpful stage, and that’s something you should expect for us here.

Your next question comes from the line of Ben Pham with BMO.

I had some of your peers on conference calls highlight customer affordability as a topic of interest these days with all that’s going on with markets and inflation, slight change. Can you add some flavor to that conversation and you think some of your comments previously on cost initiatives and narrowing that ROE gap towards the level?

Yes. I’ll certainly start on that. If I think about the guardrails of the company, you heard me make reference to premium utilities. We aren’t capital constrained if we have constructive regulatory mechanisms and we have a platform for customer-centric investment to meet evolving customer demand for our services. But I think the – at this point, the one thing that gives us credibility when coming in to our regulatory environment asking for support is that we’ve done everything that we can to lower the cost profile, the actual cost of service for our customers. And so from my vantage point, the one constraint is not capital constraint, it’s affordability. And so the conversation that we are having internally and for the entirety of my tenure here in our pursuit to be a premium utility is driving the cost down, so that we could put productive capital to work on behalf of our stakeholders in a way that minimizes the impact on customer bills. It’s embedded in what you just heard Brian make 13 reference to about capital discipline, but we’re also constantly going to be benchmarking ourselves against best-in-class on our overall cost profile so that I can make – we can make a credible case to our stakeholders that we’re responsible stewards of our service. So you’ll see that in our O&M numbers, and I’ll talk a little bit more about it in our outlooks on June 3. But I think discipline should be your takeaway. And we’re comparing our objectives. We’re not there yet. Obviously, we’re a ways away, but our objective is to compare ourselves to best in class on both capital and O&M discipline.

Okay. Got it. And I know you provided some details on the June update, you mentioned it’s also later in the year. I just wanted to clarify, the June portion with ’25 to ’27, is the focus on EPS numbers, rate base CapEx in that time frame? And then later in the year, it’s a beyond ’27 guidance?

It’s fair to say that you’re absolutely right on ’25, ’26 and ’27. And I know that there are going to be questions about the broader points of view on a portfolio strategy. And what we’re seeing is that we’re prepared to go public with the guidance and outlooks for that 3-year time frame. And while we are definitely thinking through the broader strategic portfolio questions, we think we’ll be in a better position to talk about it publicly later in 2025.

— Operator Instructions — Your next question comes from the line of Mark Jarvi with CIBC. Your line is open.

Sorry about that. Had questions on New Hampshire. You’ve got settlements now at En14 ergyNorth and Granite State. Obviously, there’s still the audit in terms of the systems there. Updated perspective in terms of the path forward there, when you could get back in to file for new rates and try to get through some of those revenue requests that didn’t come through on the prior settlements?

Yes, Mark. So just to be clear, we do have an order approving the settlement for Granite State. We are in settlement discussions at EnergyNorth, and that’s part of the prepared commentary that we’ve got a little bit more time as granted by the commission to negotiate that settlement. So just to clarify that. But with regards to when we can go back in for new rates. So for Granite State, what we have in the settlement is a stay-out period until we can file a new rate case on January 1, 2026. And that is a helpful data point in those. And given that similar parties, similar time scales for the rate cases, I think that’s something to think about as we’re looking at concluding settlement negotiations in EnergyNorth.

Got it. And then maybe just updated you in terms of at CalPeco, the application for interim rates. Any feedback yet in terms of whether or not that’s feasible? And just probably how you see time line progressing in CalPeco?

So, it’s absolutely feasible. We wouldn’t have filed otherwise. We haven’t got any feedback yet, but we’re continuing to answer any questions that come up. But it’s certainly an option open to us that we’re taking every advantage of.

When do you think you can get clarity? Because I believe the ask was for interim rates by 15 the middle of this year, and that’s not that far away at this point.

Yes. California is a slower jurisdiction to hear back. So I actually – I can’t say when we’ll hear.

There are no further questions at this time. I will turn the call to Mr. Rod West.

All right. Thanks again for your interest and your questions this morning, and we look forward to visiting with you again in just a few weeks on June 3. Have a great rest of the day.

This concludes today’s conference call. You may now disconnect. Copyright © 2025, S&P Global Market Intelligence. All rights reserved 16