Algonquin Power & Utilities Corp

TSX:AQN

Earnings Call Analysis

Algonquin Power & Utilities' Strategic Transition and Financial Performance

Algonquin Power & Utilities reported a 1% revenue increase and 4% growth in adjusted EBITDA in Q3 2024, driven by new rates in their regulated business. However, adjusted net earnings fell by 5% and adjusted earnings per share decreased by 20%. The company is on a path to become a pure-play regulated utility, with litigation paths for $205 million in rate increases set for 2024. Notably, they expect to receive $1.7 to $1.8 billion from their pending renewables sale. Guidance for 2025 will be provided later, but emphasis was placed on optimizing the balance sheet and stabilizing returns.

Strategic Transition to a Pure-Play Utility

Algonquin Power & Utilities Corp. is undergoing a significant transformation aimed at focusing entirely on regulated utility operations. As part of this strategic decision, the company plans to separate its renewable and regulated businesses to enhance capital efficiency and long-term growth potential. By closing the sale of its renewables business for up to $2.5 billion, expected in late 2024 or early 2025, Algonquin will streamline its operations and reduce complexity. This transaction, along with the anticipated closure of the Atlantica sale on December 12, 2024, will position Algonquin primarily as a regulated utility.

Financial Performance Overview

In the third quarter, Algonquin reported a year-over-year revenue growth of 1% and a 4% increase in adjusted EBITDA for its continuing operations. However, the company's adjusted net earnings and earnings per share (EPS) decreased by 5% and 20%, respectively. The lower earnings were attributed to higher operational costs and debt-related expenses, as well as the issuance of 76.9 million common shares that diluted EPS. Despite these challenges, the regulated business unit reported a 3% increase in adjusted EBITDA, benefiting from newly implemented customer rates and improved revenue collection from regulatory assets.

Key Rate Case Developments

Algonquin is actively pursuing several rate adjustments to enhance its revenue base. Recently, the company secured approval for a $38.6 million revenue increase for its New York water utility effective September 1. Additionally, applications for significant rate increases of $39.8 million in California and $92 million in Missouri are underway. The anticipated review period for these rate cases could take up to 18 months. The cumulative impact of these filings could exceed $700 million in potential revenue increases, with a focus on ensuring timely returns on invested capital from previously completed projects.

Debt Management and Strategic Financial Goals

With outstanding debt totaling $8.7 billion after refinancing maneuvers, Algonquin is targeting a reduction in debt through the proceeds from the upcoming sales. The net proceeds from the renewables sale are estimated to range from $1.7 billion to $1.8 billion, with a portion earmarked for paying down legacy debt. The firm is committed to maintaining an investment-grade credit rating while ensuring that the majority of these proceeds will go towards self-funding future capital expenditures. This approach aligns with their long-term goal of reducing operational costs and optimizing the overall financial health of the utility business.

Looking Ahead: Challenges and Opportunities

While Algonquin’s near-term results may experience pressure due to delayed regulatory approvals and anticipated operating expenses, the long-term outlook remains positive. The strategic initiatives instituted by the management team, including the integration of a new IT platform and enhanced operational efficiencies, aim to create a more resilient utility structure. Company executives are confident in their ability to enhance the overall value proposition as the regulated business matures into a streamlined utility model, which is expected to yield significant customer and shareholder value in the coming years.

Future Guidance and Performance Expectations

Currently, Algonquin has not issued formal 2025 guidance as many of its operational metrics are still being evaluated. However, management indicated a strong focus on emerging from the transitional period with stabilized earnings streams from ongoing rate case activities. Stakeholders are advised to expect updated guidance during the fourth quarter results announcement, where further clarity on the EPS impact from recent share issuances and operational adjustments will be provided.

Earnings Call Transcript 2024-Q3

[Operator]

Hello, and welcome to the Algonquin Power & Utilities Corp. Third Quarter 2024 Earnings Conference Call. [Operator Instructions]

I will now turn the conference over to Mr. Brian Chin, Vice President of Investor Relations. Please go ahead.

[Brian Chin, executive]

Thank you, operator, and good morning, everyone. Thank you for joining us for our third quarter 2024 earnings conference call. Joining me on the call today will be Chris Huskilson, Chief Executive Officer; Darren Myers, Chief Financial 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 would like to remind you that our discussion during the call will include certain forward-looking 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 reflected in such forward-looking information. Please note and review the related disclaimers located on Slide 2 of our earnings call presentation at our website. Please also refer to our most recent MD&A filed as indicated earlier and available on our website for important information -- additional information.

On the call this morning, Chris will provide an update on the company's ongoing strategic transition to a pure-play regulated utility. Darren will then review key highlights pertaining to our regulated business and our third quarter financial results, followed by some final remarks from Chris. We will then open the lines for questions. We ask that you kindly restrict your questions to 2, then requeue if you have any additional questions to allow others the opportunity to participate.

And with that, I'll turn it over to Chris.

[Chris Huskilson, executive]

Thank you, Brian, and good evening -- good morning, everyone. Thank you once again for your interest in Algonquin and for supporting us on our continued journey towards a pure-play regulated utility. I'd like to start with a quick review of how far we've come in our strategic transition. But first, I want to welcome Sarah MacDonald, our Chief Transformation Officer, to the call. Welcome, Sarah.

In 2023, we had the strategic -- we made the strategic decision to simplify and focus the business as a core regulated utility. It was and continues to be our belief that separating the regulated and renewables platform would after a transition period, allow both businesses to be more ideally capitalized and ultimately lead to longer-term growth and value. We began to streamline our capital structure early for this year. This started with paying off our margin loan with Atlantica and collapsing our development joint venture this past winter and successfully remarketing our green equity units this past spring.

In May of this year, we announced our support for Atlantica's strategic sale agreement which is now expected to close on December 12, 2024. In August, we announced an agreement to sell our renewables business, excluding the hydro fleet, for up to $2.5 billion, representing an attractive valuation for our platform. This transaction is expected to close in the fourth quarter of 2024 or the first quarter of 2025. These changes are a considerable evolution for the business.

And on upon close of Renewables and Atlantica transactions, we will effectively be a regulated utility business with significantly reduced complexity. As we've mentioned in the past, we will be looking to monetize our hydro fleet as part of the separation transaction. We continue to focus our efforts on successfully closing the Renewables transaction. And as such, we have not yet officially launched the process for hydro.

We would expect to begin the sale process sometime in the first half of 2025 once the renewables transaction is closed. It's important to note that the hydro business represents an annual EBITDA run rate of approximately $25 million, and we intend to only enter into a transaction if it creates value for our shareholders. At the end of the day, we are confident in the actions we are taking to position the business to deliver customer value and growth through simplification and focus. While the journey at times has been challenging, I'm excited to lead the company through this transition period to a brighter days ahead.

While we've been executing our strategic simplification plan, we've also been busy optimizing the core regulated business. When I started as CEO, I highlighted that 1 of my main priorities was to get the regulated business up and running. Early in the company's history, the primary growth -- sorry, early in the company's history, the business primarily grew in a piecemeal fashion. Our opportunity is to more effectively standardize and apply best practices to create additional value for our customers and shareholders. Despite near-term challenges, I'm confident we're taking the right steps.

First, we completed the rollout of our customer first SAP-based IT platform in the spring. We're in the typical stage where we're adapting to our new system and our processes. We recently rolled out the next phase of business services, which will help simplify and harmonize customer service and back office processes, leveraging our new platform. These key milestones in our transition to a more focused regulated utility business. Although our system implementation has caused some short-term regulatory lag and has in part impacted the timing of rate cases, we are excited by the longer-term potential these steps will provide.

Second, we're evaluating our regulated utility infrastructure expertise. And we've just added in the last few quarters, new members to our Board and new executive leadership all of which have extensive regulated experience. Third, we're reorganizing our utility structure to group by commodity to drive best practices throughout our network. We have revamped a number of our internal processes in an effort to drive more consistent results.

These approaches are approaches that I've successfully used in the past and I'm beginning to see positive change and increased accountability within the organization. To be clear, this is a journey but we're heading in the right direction. Looking ahead, 1 of our main priorities is to recover and earn a return on capital that we've already invested but have not yet captured in authorized rates. There are 3 large rate cases that we expect to improve our return on capital.

I'm pleased to say that we recently filed rate cases for Empire Electric in Missouri and CalPeco in California and expect to file Litchfield Park in Arizona in the first half of 2025. The general rate case for Empire Electric Missouri was filed yesterday and includes a request to increase rate base by approximately $534 million. The filing includes a 53.1% equity layer and 10% allowed return on equity, resulting in a requested revenue requirement increase of approximately $92.1 million. Historically, Empire's Electric rate cases take about 1 year to resolve.

CalPeco's general rate case was filed in September and includes a request to increase rate base by approximately $154 million through 2025. The filing is based on a 52.5% equity layer and 11% allowed return on equity, resulting in a requested revenue requirement increase of approximately $39.8 million. Based on typical timing, we would expect this rate case to be resolved sometime in the first half of 2026. Concurrent with the rate case, we filed a request to adjust rates retroactively.

We're aiming to file a rate case at the Litchfield water and sewer facility in Arizona in the first half of 2025. As we indicated on prior calls, the Sarival wastewater plant is a substantial investment in the community, and it serves significant manufacturing development along a key corridor in the Greater Phoenix area. The plant itself represents approximately $108 million in investment, offset by approximately $23 million in connection fees. This results in our seeking approval to increase rate base by approximately $85 million.

Historically, Arizona rate cases can take up to 18 months to complete, so we expect financial benefit from the rate case to start in 2026. These 3 rate cases constitute over $700 million in potential net increases in our authorized rate base. As we turn to 2025, it will be the first year we will be in a position to focus completely on our regulated business. As I mentioned on our last call, there's no question that our short-term results will be impacted by the timing of rate cases.

On the other hand, we are taking the right steps, and I'm confident that we have a tremendous opportunity to improve our rate case outcomes, leverage our IT platform and run the business more effectively. The filings of Empire and CalPeco along with other actions I've described are positioning us well to increase our momentum beyond 2025.

And with that, I'll ask Darren to review this quarter's operational and financial results. Darren?

[Darren Myers, executive]

Thank you, Chris, and good morning, everyone. I'll start off my commentary today with an overview of key rate case developments. During the third quarter, we received the final order for our New York water utility authorizing a $38.6 million increase in revenues over a 3-year rate plan which came into effect on September 1. As highlighted by Chris, in the third quarter, the company filed an application at our CalPeco electric utility in California, seeking an increase in revenues of $39.8 million based on an ROE of 11% and an equity ratio of 52.5%. We also recently filed an application at our Empire Electric Missouri utility seeking a revenue increase of approximately $92 million based on an ROE of 10% and an equity ratio of 53.1%.

As we look forward, we plan to file rate cases at Litchfield water and sewer, New England Gas, St. Lawrence Gas in either the fourth quarter of 2024 or the first half of 2025. As we have mentioned on prior calls, 2024 represents the largest number of concurrent rate cases in the company's history. At this time, the company has pending 13 rate reviews, which represent approximately $205 million in revenue request.

Turning now to financial results. This quarter, we separated our results into continuing operations and discontinued operations. Let me provide further color to help you better understand the moving parts. Our continuing operations includes our regulated business, hydro business and ownership stake in Atlantica. It also includes all debt except debt specific to our renewables business.

We continue to record our ownership stake in Atlantica and associate dividends in continuing operations based on the application of generally accepted accounting principles. We now expect Atlantica to close on December 12, 2024. Our discontinued operations includes our non-hydro renewables business, including taxes and associated tax credits and $1.25 billion in specific debt related to our Renewables business. In terms of the numbers, our third quarter financial performance for continuing operations saw year-over-year growth in revenue and adjusted EBITDA of 1% and 4%, respectively primarily due to the implementation of new rates across several of the regulated business electric, natural gas and water facilities.

Our revenue growth was partially offset by lower pass-through commodity costs. We recorded year-over-year decreases in adjusted net earnings and adjusted net earnings per share of 5% and 20%, respectively. While our results benefited from new rates, they were more than offset by higher operating expenses as well as depreciation and interest expense. Adjusted net earnings per share was also negatively impacted by the previously disclosed issuance of 76.9 million common shares in connection with the company's green equity units through a mandatory conversion back in June.

On a segmented basis, adjusted EBITDA growth for the regulated business in the third quarter was up 3% year-over-year due to the implementation of new rates at several of the company's electric, gas and water facilities as well as higher HLBV income as a result of normalized wind resources and the recovery of securitized regulatory assets at Empire. These gains were partially offset by higher operating expenses, as mentioned earlier. A few other comments on our balance sheet as we move closer towards closing our Atlantica and Renewables transaction. Our Q3 balance sheet debt, including continued and discontinued operations is $8.7 billion, which increased from Q2, in part from the buyout of a construction loan at Carvers Creek.

We expect to have approximately $1.7 billion to $1.8 billion in net proceeds from the renewable sale after off-balance sheet construction loan obligations and other renewable liabilities are satisfied. Final net proceeds received may vary due to items such as construction spending variances, tax credit timing and monetization. It's worth noting, including -- included in the $1.7 billion to $1.8 billion we now expect to receive approximately $150 million of net proceeds associated with tax attributes in certain projects in late 2025. Let me have a few call-outs on our year-to-date earnings and some reminders for next year.

Year-to-date, our continuing operations adjusted net earnings is $187 million and our adjusted earnings per share for continuing operations of $0.25. Included in that is $65 million in Atlantica dividends year-to-date or approximately $0.09 in adjusted net earnings per share. So as you think about next year, there's a few pieces merit calling out. If you combine the proceeds of both transactions ignoring timing, we would expect to receive $2.8 billion to $2.9 billion.

As you consider our pro forma adjusted net earnings per share, you need to take into account that based on our Q3 balance sheet, $1.25 billion of proceeds would go towards discontinued operations debt pay down leaving $1.55 billion to $1.65 billion for deleveraging against the continuing operations. So as you think about our pro forma continuing operations number, you would need to incorporate the continuing operations deleveraging and then remove the Atlantica dividends. As we've noted before, we are not providing 2025 guidance at this point. As a reminder, our results on a per share basis will be affected by the full year effect of the settlement of our equity units from earlier this year.

We plan to provide guidance when we report our fourth quarter results. In summary, we are on track to achieving a number of key milestones on our path to simplification and becoming a pure-play regulated business. This is a journey, and we are focused on taking the right steps to create long-term value.

With that, I will turn the call back over to Chris.

[Chris Huskilson, executive]

Thank you, Darren. We're pleased with the progress that we're making on our journey to transform Algonquin into a pure-play regulated utility. We've already achieved several of the key initiatives we listed at the start of our strategic transition. And we believe we have provided the meaningful steps on how we intend to get there. These steps past, present and future have the same goals. The strength in the balance sheet, optimize the payout ratio, support future earnings and dividend growth, simplify and refocus the business and ultimately provide exceptional service and value to our customers and our shareholders.

With that, I'll turn the call back over to the operator for some questions. Thank you.

[Operator]

[Operator Instructions] Your first question comes from the line of Rupert Merer with National Bank.

[Rupert Merer, analyst]

If I could start by asking about your rate case submissions. I believe you've now submitted rate cases for $700 million of your target recovery. Well, that includes Litchfield coming up, of course. I believe there's another $300 million to come. Can you give us more color on that? What would be included in that $300 million? And what would be the timing on submitting rate cases to get you up to your full $1 billion?

[Darren Myers, executive]

Rupert, we're not going to give that walk in terms of that -- of what's left. I mean, obviously, we're going to continue to file rate cases. We've got a number of other cases to file. And we're definitely pleased that we got a significant -- 2 significant rate cases behind us now, and we're focused on Litchfield next and a number of other ones.

[Chris Huskilson, executive]

And I think, Rupert, 1 of the things we've been fairly clear that, number one, the number is going to be a moving target as we continue to invest in the business. And number two, we see this occurring out into 2027.

[Rupert Merer, analyst]

If I could just focus on the Empire rate case then, that one, of course, is the largest. It seems like it has the potential to be completed the most quickly and possibly to be completed before the end of next year. So what impact could that have on 2025? And how much of it could be retroactive?

[Darren Myers, executive]

Well, I think as we said in the prepared remarks, if you look at history, obviously, you can't predict exactly when these will settle. But if you look at history, it's about 12 months. So we just put the rate case in and it would be prospective. So there'll be a small amount of impact next year, but not meaningful for '25. And then, of course, in 2026, we'll be getting the full benefit.

[Rupert Merer, analyst]

Maybe 1 quick follow-up here. I think you were looking also at some deferrals of depreciation, which you'd have to go to the regulators to see those allowances. Can you give us an update on how that might be progressing?

[Chris Huskilson, executive]

I think where we are right now, Rupert, is we've submitted applications in New Hampshire and in Arizona, and we don't have an answer yet.

[Operator]

Your next question comes from the line of Mark Jarvi with CIBC.

[Mark Jarvi, analyst]

Thanks for that commentary on some of the helpful measures to get us to sort of pro forma business outlook here. A question on the base set of earnings. I appreciate versus [ strip ] out AOI and then there's obviously interest savings. But the earning on the utility business today, do you think there would be erosion as you get into 2025 with regulatory lag? Or do you think that can be flat to up on what you've shown year-to-date?

[Darren Myers, executive]

I would say we're certainly not going to give guidance today because there's -- we do have the benefit of some rate cases that we've been able to settle this year that will go into next year. And then, of course, we're all over our OpEx spend, and there's areas where you have some increases in noncontrollable spend, but we're also looking for all efficiencies we can get. So it's a little early to say what next year is going to be, and we're working hard on our plan there and we will provide further color on that as we close Q4.

[Mark Jarvi, analyst]

And when you say color on that when you closed Q4 before the Q results?

[Darren Myers, executive]

No, no. Thanks for that clarification. [ During ] our fourth quarter results. Thanks, Mark.

[Mark Jarvi, analyst]

All right. And then on the rate case filings, I think in Missouri, in particular, as part of your submission, is there anything you guys will be advocating for in terms of writers, measures to minimize regulatory lag just given what you've been through the last couple of years?

[Chris Huskilson, executive]

Well, so you have to remember that in Missouri, we have the PISA opportunity and pretty much everything that we are applying for is in PISA today. So we do have that advantage. There are a few things that we're applying for relative to our fuel adjustment mechanism and a few other items. So those are all listed in the case filed.

[Mark Jarvi, analyst]

And last question for me is just on New Hampshire, expectations on the path forward there. You've had some sort of extensions there, I think, to November 15. Is there a view that you can work through a settlement? Or is a refiling more likely path?

[Chris Huskilson, executive]

No, no, we're expecting to settle both of those cases. And I think we've had good discussions with interveners and with the staff. And so we're optimistic that, that will come to a conclusion.

[Operator]

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

[Sean Steuart, analyst]

And thank you for all the detail on the rate case filings. Just 1 question for me. Wondering if you can give us any updates on the process for hydro at this point? Is that underway? If so, any context on expressions of interest at this stage?

[Chris Huskilson, executive]

Well, for once we've had lots of expressions of interest. That has not been a problem. But no, we haven't really started the process there. What we've been focused on, obviously, is selling the bigger asset base. And also on the carve-out of the hydro, those 2 things are busy activities. And so what we've said is sometime in the first half, we'll actually go to market with the hydro but through my eyes, it's not a certainty that they will sell just simply because they do make a fairly substantive contribution to the business. They won't affect our ability to be considered pure play. And so we'll sell if we can create some economic value. But if they're better off in the business, we'll keep them there. But we will go to market and test that.

[Darren Myers, executive]

Yes, Sean. And I know in the past, we said we would be hoping to do that this year. But with all, as Chris mentioned, with everything going on and with the fact we want to maximize value here, we're just going to time in next year when we have a bit more bandwidth to give it the attention it needs.

[Operator]

[Operator Instructions] Your next question comes from the line of Rob Hope with Deutsche Bank (sic) [ Scotia Bank ].

[Robert Hope, analyst]

Scotiabank.

[Chris Huskilson, executive]

I didn't think you move, Rob.

[Robert Hope, analyst]

Anyway, okay. So a follow-up to Sean's question there. So it doesn't seem like you need to sell the hydro assets from a strategic point of view or even a balance sheet point of view. So when you think about use of proceeds on the hydro assets, could that push you to share buybacks? Or would that help you accelerate investments into the utility business? Or how do you think about kind of the potential levers for proceeds from hydro if you do choose to sell those assets?

[Darren Myers, executive]

I'll repeat maybe comments that we've said in the past. First, as we continue to say, we're committed to the investment-grade rating. We intend to use proceeds to maintain flexibility. We want to be self-funding. That is the bigger priority. We certainly don't want to do a buyback and go back to the market after that. I will say that the amount of flexibility we have is dependent on getting the regulatory lag lower. Obviously, there's earnings and FFO that's created by those rate cases. So a lot of it is going to be timing dependent. But ultimately, we're looking to have flexibility, bring the more discipline internally on how we time capital spend with our regulatory recovery and then from there, invest in the business.

[Chris Huskilson, executive]

And Rob, we will take a look at the balance between what the value that we get from the Hydro inside the business and the value we can get if we continue to take that capital and reinvest. So I mean that will be the test that we're looking at and whichever comes up with the most economic value, that's what we'll do.

[Robert Hope, analyst]

And then sticking with the power business. As we look through the balance of closing, could we see the purchase price move again? And just to clarify or confirm, the movement that we saw on the net proceeds will be offset by the debt being brought back onto the balance sheet. So the overall economics haven't changed?

[Darren Myers, executive]

So it moved up by $200 million on the high end to 1.6 to the 1.8 because of us bringing $200 million on balance sheet. So that would have been in the construction JVs before and now they're on our books, you naturally get -- go higher. So there's no economic effect. We do have a range in here as we get closer. There's a handful of projects that we need to complete. We're responsible for completing even through the time where LS would take ownership. And so some of those have been pushed to the right with some additional costs. So we've put a range in here. It's our best estimate at this time. We're comfortable with that range of what it's going to take to finish those projects.

And Rob, just for clarity, that also impacted, the timing of those also impacted. You would see I noted that we're going to get about $150 million of proceeds kind of in the back half of next year. that's around tax attributes of those projects. So as they've pushed out, we don't see it being timed with the closing in the same way anymore. So no change in our overall economics is just some nuances to it.

[Operator]

There are no further questions at this time. I will now turn the call to Mr. Chris Huskilson.

[Chris Huskilson, executive]

Well, thank you very much for your interest in Algonquin and for your time today. We'll be heading to EEI, the financial conference in a few days, and we look forward to seeing many of you there. So have a great next rest of your day. Thank you.

[Operator]

This concludes today's conference call. You may now disconnect.