Algonquin Power & Utilities Aktie

Hello, and welcome to Algonquin Power & Utilities Corporation Second Quarter 2026 Earnings Conference Call. [Operator Instructions]

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

Thank you, operator, and good morning, everyone. We appreciate you attending our second quarter 2026 earnings conference call. Joining me on the call today will be Rod West, Chief Executive Officer; and Rob Stefani, Chief Financial Officer, who will share prepared remarks. Following their remarks, they will be available to answer your questions along with other members of the management team during a Q&A session.

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.

Additionally, all net earnings information to be discussed today is for continuing operations and is attributable to the common shareholders of Algonquin. 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 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.

On the call this morning, Rod will provide a business update, and Rob will follow with the details of our financial results. We'll then open the line for questions. We kindly ask that you restrict your questions to 2, then follow up with us after the call if you have any additional questions to allow others the opportunity to participate.

And with that, I'll turn things over to Rod.

Thanks, Brian, and good morning, everyone. Thank you for joining us. Our second quarter 2026 has been another step forward for Algonquin on our path to Premier. As I stated consistently since I've arrived, a premier pure-play regulated utility earns its standing through consistent execution, a constructive regulatory compact and disciplined financial and operational management. These attributes aim to position the company to deliver long-term sustainable value to shareholders, customers and communities we serve and our employees. As we will discuss in a moment, this quarter's results reflect all of those build on the measurable progress we've made since last year, and keep us on track to meet our adjusted net earnings per share forecast for 2026 and 2027. In short, we are once again advancing toward our goal of becoming a premier pure-play regulated utility.

Taking measure of our strategic priorities for the year, I'm pleased with the progress we've made in the second quarter. On the regulatory side, we are pleased to achieve progress on or conclusions to several of our rate cases. The Missouri Public Service Commission determined on July 15 that we had satisfied customer service and billing performance metrics required for implementation of the previously approved Empire Electric Missouri settlement.

I want to recognize the extensive and professional effort that commission staff and our employees displayed to reach this outcome. And for the tremendous patience exhibited by our customers and shareholders, as we underwent this process. Additionally, we received a proposed decision for our California proceeding, an order approving a settlement for Empire Electric Kansas, a final order for our California Water Utilities, and new rate case filings at New York Water, Empire Electric Arkansas, EnergyNorth Gas and 2 water utilities in Arizona.

We continue to await an order on our Arizona Litchfield Park water and sewer rate case and continue to work towards completing new filings at Granite State Electric, Empire Electric Oklahoma and a Missouri large load tariff before year's end. Moreover, we filed a case with FERC requesting conversion for our electric transmission projects to a projected test year versus a historic test year, including CWIP into rate base under a transmission formula rate. This rate request, though small, could set the foundation for regulatory treatment of our SPP transmission line project over the next few years.

And one additional update, in the second quarter, we captured approval from the Department of Energy for the reimbursement of $5 million of expenses related to an AMI grant in California that was reinstated earlier this year.

In summary, I'm pleased to see in the second quarter that we've made continued progress on this year's priority list. I do want to take a moment on Slide 6 to address our announcement regarding the intended redomicile of Algonquin to the United States. At a high level, we see this as an important strategic step for the company and one that we expect will create meaningful benefits for shareholders over time.

Today, over 80% of our operations are located in the United States with less than 5% in Canada. Redomicile into the U.S. would better align our corporate structure with our assets and where we expect to grow. As we've discussed before, it would also support our efforts to reduce cross-border tax inefficiencies. We've described them as tax friction. And over time, we believe it would strengthen our financial profile, broaden our access to capital and create a path to inclusion in certain U.S. equity indices and funds.

From a structural standpoint, we expect to complete the redomicile to Delaware through a quarter-proof plan of arrangement under the Canada Business Corporations Act. We expect to establish our headquarters in Chicago, where our senior executive leadership team would be based while maintaining our significant presence in Oakville, Ontario. I want to emphasize that this does not change how we operate our utilities, serve our customers or satisfy our regulatory obligations.

In terms of timing, we expect to seek shareholder approval in the first half of 2027 and to complete the redomicile following the receipt of the required shareholder and regulatory approvals and satisfaction of customary conditions. Overall, we believe this positions us to more effectively execute on our strategic priorities and enhance long-term shareholder value.

Turning to Slide 7 and 8, focusing a bit more on our regulatory strategy. We continue to prioritize earlier dialogue with stakeholders to identify areas of common ground as well as advancing more pragmatic filings. We expect this to deliver fair regulatory outcomes that allow us the opportunity to capture both recovery of reasonable cost and returns on our investments for the benefit of our customers. I'm pleased to note that in aggregate, this is playing out in a balanced manner.

In Missouri, the Commission's July 15 order approved implementation of $97 million in annualized revenue adjustments, effective on August 3. We continue to make regulatory progress in Kansas, where the Corporation Commission approved our settlement agreement for an $8.8 million revenue adjustment and a provision for 50% of wind revenues for year 1. The settlement included a black box stipulation for authorized equity ratios and ROE.

Out in Western California, the Public Utilities Commission issued a constructive proposed decision in our WEMA proceeding, which authorizes a $58.1 million recovery in wildfire costs or approximately 75% of our requested recovery. Consistent with standard practices of how other California utility peers have accounted for Lima and similar preceding outcomes, we excluded the impact of the final outcome from our adjusted net earnings per share results.

Also, in California, we received an order approving an alternate proposed decision for our Apple Valley and Park Water utility cases. For those utilities, the commission approved a combined revenue reduction of $2.7 million and a retroactive true-up to July 2025, totaling $3.1 million for that revenue reduction.

In Arizona, our settlement agreement and a final decision regarding formula rate plans remains pending at Litchfield Park Water and Sewer. The ALJ issued a recommended opinion and order, and we've asked the commission for a final decision this month.

For new rate cases, New York Water filed its rate case requesting a $38.1 million revenue adjustment based on a 10% return on equity and a 48% equity ratio for proposed rate year starting May of next year.

Empire Electric Arkansas filed its rate case requesting $8.4 million based on a 10% ROE and a 53.4% cap structure with the proposed implementation date of spring of next year. Energy North also recently filed its rate case with a $35.8 million rate request based on a 10.25% ROE with a 52% cap structure, and we expect to have permanent rates implemented in the summer of next year.

Turning ahead to Slide 9. I'll add a few comments regarding our evolving regulatory and legislative landscape. On the operations front, on June 17, we received our Certificate of Convenience and Necessity or the CCN, from the Missouri Public Service Commission. This milestone achievement is for one of our most significant capital projects where we're deploying 250 megawatts of new gas-fired generation to meet customer demand and Southwest Power Pool requirements.

This will be the first gas-fired generation project for us under Missouri Senate Bill 4, where we will take advantage of the construction work in progress, or CWIP, regulatory recovery mechanism. In aggregate, the point of these updates, and I recognize that there are many, we continue to make overall progress on rate cases across multiple jurisdictions in a more deliberate and intentional manner.

With that, I'll turn it over to Rob to walk through our financial update for the quarter.

Thanks, Rod, and good morning, everyone. Let's start with Slide 11, where you can see our reported second quarter GAAP net earnings of $4.9 million compared to $14.8 million for the same period in 2025. On an adjusted basis for the period, net earnings were $29.2 million versus $33.6 million for the second quarter of 2025. The Overall, the second quarter decline in adjusted net earnings from 2025 to 2026 reflects increased rates at several of our utilities, offset by higher financing costs slightly higher operating expenses and several nonrecurring favorable items from the second quarter of 2025.

In the second quarter, we also reported a $17.2 million write-down of a regulatory asset related to the previously discussed proposed decision in our California Lima proceeding. The impact of the proposed decision, which, as Rob previously mentioned, authorizes 75% recovery of recorded costs stemming from the 2020 Mountain View fire has been excluded from our adjusted net earnings.

Moving to year-to-date results. We reported GAAP net earnings of $88 million compared to $107.6 million for the same period in 2025. Year-to-date adjusted net earnings were $128.8 million versus $142.6 million in the same period the prior year. Taking into account $25.7 million in nonrecurring favorable items from 2025, results were higher year-over-year, as I will explain in more detail in a moment.

On Slide 12, I'll discuss the drivers behind our second quarter 2026 adjusted net earnings per share walk. Second quarter adjusted net EPS to common was $0.04 per share, which was flat year-over-year. Second quarter year-over-year results were driven by higher CalPeco approved rates of $12.1 million and were partially offset by higher wildfire insurance expenses of $5.7 million.

Net revenues outside of CalPeco rose at our water utilities in New York, Arizona and Chile as well as customer growth in Arizona and favorable weather year-over-year at Empire totaling $7.5 million. Net revenues were partially offset by a rate reduction on our Apple Valley and Park Water utilities in California, inclusive of an unfavorable retroactive adjustment to July 2025 of $31 million.

Interest expense grew by $9.3 million related to a new debt issuance at Liberty Utilities Company and higher commercial paper usage, partially offset by higher investment income of $3.1 million. Operating expenses were slightly higher due to an additional $3.3 million of higher gas safety and excellence costs and other gains and losses were slightly unfavorable due to a gain on an asset sale in 2025.

On Slide 13, we provide our year-to-date 2026 adjusted net EPS walk. Year-to-date, adjusted net EPS was $0.17 per share compared to $0.19 per share in the first half of 2025. We -- although a decline year-over-year, I'd like to highlight the 2025 experience $25.7 million in favorable items that did not repeat in 2026, including a tax basis step-up recovery of $15.9 million for Hydro as an example, plus pension adjustments at Empire and depreciation deferrals and rate proceedings in New Hampshire and Arizona. Absent these items, year-over-year net EPS was $0.01 favorable.

Similar to Q2 results, year-to-date year-over-year benefited from approved rate at CalPeco, net of wildfire insurance expenses of $38.7 million. New rates at New York, Arizona, Chile and Peach State all contributed to improved net revenues year-over-year of $11 million, less $3.1 million related to the Apple Valley and Park Water Retroactive Adjustment.

Operating expenses increased due to gas safety and excellence costs of $6.3 million and higher labor, maintenance and property tax expenses of $14.1 million. We experienced unfavorable weather of $9.9 million year-to-date versus the prior year.

And lastly, interest expense was unfavorable as previously discussed, due to a new financing at Liberty Utilities Company net of investment income.

Briefly touching on Slide 14, our balance sheet continues to be in a position of strength. We don't expect to issue equity through 2027. During the second quarter, we raised approximately $1.15 billion at Liberty Utilities Company through a private placement offering of senior unsecured notes and used the proceeds from offering to pay down $1.5 billion aggregate principal amount of notes at Algonquin Power & Utilities Corp that matured on June 15.

At Algonquin, we continue to be rated BBB by S&P and Fitch, and at Liberty Utilities Company continue to be rated Baa2 by Moody's and BBB at Fitch and S&P. As Rod indicated at the top of his remarks, our adjusted net EPS forecast is unchanged, and we remain on track.

With that, I'll turn the call back over to Rod for his closing remarks.

Rob. Before we open the line for questions, I want to take a step back and leave you with a few thoughts on where we are and where we're headed. Halfway through the year, we've made substantial progress as we expected, but we continue to have work to do. We've concluded rate cases or a resettlement agreements that reduce uncertainty for Empire Electric Missouri, Empire Electric Kansas and our California water utilities. We're pending approvals of key decisions and settlements for Heema and Litchfield Park and we continue to work diligently on our rate cases at New York Water, Empire, Arkansas, Energy North and in Arizona.

On the operations front, we've continued to improve our customer performance metrics and strengthen our standing with our regulators and customers while obtaining approval for CWIP treatment for our errors generation project in Missouri. In short, I'm pleased with our trajectory in the second quarter, extending our momentum from the first quarter and from our efforts of last year.

I couldn't be more excited for what's next, and I hope you will join us on our path to Premier. Thanks for your time this morning. And with that, I'll turn it back to the operator for questions.

One moment please for the first question. The first question comes from the line of Mark Jarvi from CIBC Capital Markets.

Thanks for the update on the U.S. redomicile. Can you maybe just walk us through what conversations you've had with the IRS and just overall expected tax implications, maybe effective tax rate but also cash taxes if you do reduce in the U.S. .

Yes, Rob, go ahead.

Yes. So we began discussions with the IRS earlier this year. We filed that private letter ruling. We'll expect a decision here in the back half of the year. As far as the tax implications, what the redomicile helps accomplish is elimination of a couple of cash taxes that we pay. Number one is cash on the funds that we send up to Algonquin to pay the dividend from the utilities. And so we pay about a 5% tax on that. And we pay subject to continued Board approval, $200 million of dividends about per year. So that's 5% on the $200 million.

And then, the other tax the redomicile would eliminate with the BEAT tax. And that tax is a tax on the cash funds that are set up -- set up to Algonquin to service the debt at the holding company level. And that's about a 10% tax rate on the funds that we send up to service bad debt.

So as far as the effective tax rate, obviously, that will be determined by a number of factors, but those are 2 instances of savings that we would point to that we would expect to realize through the redomicile to the U.S.

Robert, precall, you talked a climb back some of the headwinds you announced earlier on the effective tax rate assumption, do you still feel like that's possible to reverse some of those reductions? .

Yes. So the effective tax rate is certainly has the BEAT tax and the dividend tax kind of embedded in there. And so we would expect that effective tax rate moving forward to be lower. Obviously, we are targeting an approval to proceed in the first half of '27. And so as you think about ramping up to that, you need to consider the timing there.

Understood. And second question for me, just in terms of the filings now in New Hampshire. -- last time around, there were some issues with the data, just your confidence level that you've resolved those issues going in, you feel very confident in terms of the materials you're supporting for that reapplication?

I'm peer, well, I actually I got the signal that the improvements we've made in our systems give us far greater confidence that the data issues have been identified. Obviously, it's going to be ongoing in terms of our efforts to improve. But we spent a fair amount of time and energy addressing our structural deficits and making the case to the regulators that we got the message that the customer outcomes actually matters. So my confidence is high. And I think for us, the proof of concept has been the work that we've done to sort of restore the benefit of the doubt from our stakeholders in Missouri that we're making meaningful gains in that arena. And we expect to make a similar case in New Hampshire.

Is there some dialogue along the way with staff to show them the improvements you've done before you submit the applications? .

Always. But it's not what you know is what you can prove -- and if you've had a rough experience, whether it's in California, Missouri or in New Hampshire, Missouri is the show-me state, New Hampshire is taking a similar stance. And I would -- if I was them, they want us to prove it. And we put the work in to be able to do just that. So we're looking forward to making the case and it's been ongoing.

The next question comes from the line of Malte from National Bank of Canada. You may now begin.

Just a question on the redomiciling and timing. Just between now and the targeted shareholder vote in the first half of 27, are there any key regulatory tax, quarter legal milestones we should be watching for that could influence the timing or ultimate economics of the democile.

Yes. So as mentioned in the release, we -- as mentioned in my prior comment, we will expect an outcome from the IRS, just the guidance there in the second half of the year here. that filing. We continue to have a dialogue there. So we'll update you on timing, but would expect that here in the back half of the year. We also intend to pursue regulatory filings, and so you can expect to see those across several of our jurisdictions.

Reason I know you touched on the dividend and the debt tax implications of flowing the capital through the border to Canada, -- but could you directionally frame -- I know the vision the MD&A was significant cost and taxes. Could you correctly frame the magnitude of what could be expected in terms of those 2 factors?

Yes. So I think the expectation, if you do the math on the 5% on the run rate dividend assumption plus the beat tax on the current level of debt service, you would be in that kind of 2% to 2.5%, maybe slightly higher sense of impact on a run rate basis. So again, for 2027, you need to think about the timing of our guidance on when we expect to seek shareholder approval with that run rate impact being what we would expect on a recurring basis.

The next question comes from the line of Rob Hope from Scotiabank. SP1 You may now begin.

Question on tax on the redom. Can we dive a little bit deeper on to Slide 20. So you do comment that the redomicile is expected to be a taxable event in Canada as well as a foreign investment in real property tax toll as well. So rather than the ongoing tax savings, can you speak to the potential one-time exit tax liability, both deferred and current that you can incur? .

Do you want to speak to the actual -- the tariff itself, do you feel like you've got -- you want any kind of color on that or you're just looking for magnitude?

Both would be helpful. .

Okay. So the way the FIRPTA tax is calculated is effectively, we go back and look at non-U.S. shareholders that held the shares in the prior 10 years prior to the redomicile. We look at shareholders who were over 5% holders. And the tariff is then based on a rate based on those shareholders who sold over that 10-year period that held a greater than 5% position. So we've done that math. We are confirming methodology with the Internal Revenue Service, which is the purpose of the private letter ruling. We continue to have discussions with them. We've -- we've obviously -- we and our advisers have worked through those calculations.

And given the value creation opportunity, expected value creation opportunity of the tax savings relative to those onetime costs, we believe this is a beneficial move.

And then do you have an estimate of the onetime costs?

We have a range, and we aren't disclosing that at this point in time, just given the fact that we are confirming that methodology. But again, relative to the range of outcomes we believe that this is a value-accretive transaction and expect relative to those onetime transaction costs that the recurring benefit outweighs that onetime transaction cost.

And then maybe just going back to the regulatory approvals, can you just confirm which states do you think will need commission approval for the transaction? And do you have an expected time lines or past precedents you can help us with there? .

So we're going to pursue regulatory filings in Arizona, California, Georgia, Iowa, Illinois, New York and Texas and then in New Brunswick. These are filings, and we would expect the outcomes of the filings to occur and coincide with that timing that we had discussed earlier as far as when we would expect to take this for shareholder vote. So again, these are filings, and there'll be more there in the coming weeks. As you see them get filed.

Next question comes from the line of Michael Lonegan from Barclays.

So your trailing 12-month FFO to debt was 12.9% as of the first quarter. It went to 11.9% this quarter versus the downgrade threshold of 1% and Obviously, you said you had no equity still no equity expected through '27. I was just wondering if you could talk about where you expect to land this year through '27, and what kind of cushion you're targeting versus your downgrade threshold in general?

Yes. So I think you have to also consider like rate case, timing and implementation. So obviously, we'll begin to get the Missouri rates in August that -- and we've gotten the California rates in, and those will continue to benefit from those. And then all the rate implementation associated with some of the updates that Rod made. And so we will -- we expect on an FFO to debt basis to continue to be above our S&P downgrade threshold. We haven't put guidance out for FFO to debt, in particular, for beyond this year, but we continue to expect to on an S&P FFO to debt basis to maintain above that threshold.

Great. And then I was wondering if you could talk about the discussions you're having with data centers and large load in Missouri. I know you're planning on filing a large load tariff sometime this year. What is your pipeline there? And when could we potentially expect an announcement?

And -- it's Rod. And I very much appreciate the question. And the only thing I can say that whether it was a data center or any other customer, one, we're planning to file our large load tariff in the coming weeks, if not days. And the team constantly updates me on that. I would not and cannot disclose any conversation around any potential or existing pipeline as it relates to a specific customer, unless we were at a point in alignment with that customer to say something public about it.

The only thing that I've been able to say publicly, and it's consistent, is that the -- our service territory and particularly in this instance, Missouri, is in the heat map of interest of the types of load that are consistent with data center interest. The large loan tariff is an enabling aspect of our ability to further any conversations we might have with potential customers. And the moment that we're at a point where we could disclose any type of engagement with a specific customer, we won't hesitate to do that, but I cannot get ahead of any process, whether it existed or didn't exist just as a matter of course.

So I know that might be frustrating to here, but there are reasons why we have to be deliberate, and we will not disclose anything unless we're at the point where we're aligned. So I do appreciate the question, though.

[Operator Instructions] The next question comes from the line of Eli Jossen from JPMorgan.

Maybe just sticking with Missouri. I know that you guys have had a lot of activity in the state, and you just talked about not being able to provide much clarity on the -- or specifics on the large load tariff filing right now. But maybe just kind of the other filings for formula rates and CWIP incentives, any color there just in terms of potential time line or quantifying uplift at this time. I know it's an ongoing process, but just broader color would be great.

Yes. So I'm definitely excited about a couple of aspects. I think just the ARRIS project in particular, on that project being eligible for CWIP treatment and helping kind of stem some of the regulatory lag that you would otherwise see in part. And then, on a transmission filing, that will really apply mainly to the future -- the kind of future of transmission development in SPP. So obviously, that's a large project for us that extends over the next several years. But moving for those assets to a future test year as well as getting CWIP treatment, as well as part of that filing was a cancellation or abandonment provision. All of those are beneficial. And so that future test period will also help eliminate some of the lag component for us on that future development work.

Got it. And then I know there's been a lot of questions on the redom, but if we think about the broader index inclusion benefits, you talked about a $0.02 impact. Maybe does that include potential -- like how do you frame sort of the broader index inclusion upside? I guess if you've done any math there? And maybe broadly on the $0.02 impact from what you've already talked about, what would the timing look like just in terms of actually flowing through EPS? Would that be kind of phased in through '27 and 28? Or how would that look?

Yes. So as far as the tax savings and the expected EPS impact of that kind of $0.02 to $0.03, if the 2027 impact would be determined based on kind of when in the year we're able to achieve the approval. And then, 2028, assuming that we've been approved, that would be what we would expect to be more run rate. We haven't extended the guidance for the EPS out there, so -- but the -- as far as the kind of separate issue of index inclusion, based on the work that we've done with our advisers, the expectation is there would be some positive fund flow associated with inclusion in at least 1 of the indexes in the U.S. I think 1 of your peers has also done some work around that. But I think that's all we can say at this point.

The next question comes from the line of Ben Pham from BMO Capital.

You mentioned some of the tax benefits from the redomicile pushing beyond your guidance haven't extended the guidance. I'm just curious, more specific you had a 3-year through '27. Should we expect -- how should we think about when you do extend your guidance, I'm presuming it's not going to be until you get on the redomicile first half, you in from that? And is it -- do you think 3-year CAGR through end of decade is reasonable for you given the regulatory time line? Or is it maybe something less or even more than that? .

Yes. I think we've talked a little bit about this. I think that moving forward, when we do move to -- that's typically done at the 4Q results, end of year results call, we would look to be more consistent with our peers providing kind of prompt your guidance and then the long-term growth rate.

I wouldn't say right now how far out we will go. But I think your rationale is broadly consistent of a longer-term EPS growth rate would likely be subject to Board approval of that guidance, that mechanic would put us on par with our peer group. As far as what we bake in -- yes, as far as what we bake into those projections, we'll address at that point in time.

Okay. Could you also provide just on the OpEx kind of things you had guidance around OpEx trending lower as a percent of a growing revenue base. Could you perhaps update on progress on that? Where you are right now, have you surfaced the easy pickings, as it been some challenges along the way on some of these areas? And how should we look at the trends this year and next year?

We're continuing to target that kind of mid-30s O&M to gross revenue. We continue to make progress on our cost savings efforts. I wouldn't get into specifics here, but that continues to progress.

The next question comes from the line of John Mould from TD Cowen.

I'd like to go back to the large load opportunity in Missouri, not focusing on any specific customer discussions. More just about the ability in your system as it stands right now to handle incremental loads. I'm just wondering if you can give us a sense of the scale that might be available in your system right now, like what kind of revenue you got?

Yes. And again -- yes, go ahead. You had a second part to your question. Go ahead.

I was just -- thanks, Rod, I was just going to add, and the pace at which you think you might be able to add supply in the state, if you did see that as an incremental demand driver.

Yes. And again, we've been around in conversations before, and we're not seeking to obfuscate, I think the question the answer to that question, it would be premature because disclosing it would then signal the size, the scale of any potential customer. I commit and we commit to you the moment we are in a position, remember that we have multiple stakeholders who are part of this conversation, including the state of Missouri, the commission as well as any potential customers in shaping an integrated resource plan. It's premature for us to signal a size before we're in a position to actually match that integrated resource plan with expected loads. And all of those things are to be determined. And what we're framing up with the large low tariff is enabling a range of outcomes that would then allow us to get further along analytically around just what scale of generation and transmission either at or beyond our existing plans, we'd be able to go public with. It's just a little early.

I will signal this, we are internally putting more resources to work in anticipation, one, of our large low tariff filings and in furtherance of our efforts to bring economic development to our service territory. And I guess, I'm comfortable signaling internally that we're putting more resources to bear in anticipation of us having a greater impact in the areas that we're seeking to file a large load tariff, and I'll leave it at that. That's all I can communicate.

Okay. No, I appreciate that incremental insight on the thought process. I'll leave it there.

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

All right. Well then, if there are no more questions, I will simply say thank you for your continued interest, support and feedback. And with that, we will end the call.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.

Good morning, everyone, and welcome to the Annual Meeting of the Common Shareholders of Algonquin Power & Utilities Corp. My name is Randy Laney, and I'm the Chair of the Algonquin Board of Directors. Joining me today are Rod West, Chief Executive Officer; Robert Stefani, Chief Financial Officer; and Ryan Elger, Corporate Secretary.

Before beginning the formal session of the meeting, I would like to take a moment to thank and recognize the other -- the contributions of the other directors of Algonquin, Brett Carter, Chair of Human Resources and Compensation Committee; Amee Chande, Chair of the Risk Committee; David Levenson; Chris Lopez; Gavin Molinelli; Dilek Samil, Chair of the Audit and Finance Committee; DeAnn Walker; and Rod West, the CEO of the corporation.

On behalf of Algonquin's shareholders, I'd like to thank each of these directors for their commitment and dedicated service to the corporation. Chris Huskilson, former CEO of the corporation, retired from the Board in November of '25 after 5 years of service in his most recent term. And Dan Goldberg, Chair of the Corporate Governance, is not standing for reelection and retiring from the Board after 4 years of service. We want to thank each of them for their valuable contributions to the Board over the years, and we wish them the very best.

I'd now like to address a few procedural matters. Given the virtual format of today's meeting, we would request that registered shareholders and duly appointed proxy holders would have specific questions -- who have a specific question on a formal item of business, make such written submissions now, clearly identifying the applicable items of formal business. Such submissions will be addressed prior to the voting on the applicable motions.

Registered shareholders and duly appointed proxy holders can submit questions by clicking on the question icon on the left menu if you're on a web browser or on the bottom menu if you're on a mobile browser and then typing in and submitting questions. If you have any questions not specifically relating to an item of formal business to be discussed at today's meeting, please feel free to submit those questions at any time during the meeting.

Following the formal business of the meeting, there will be a general question-and-answer period conducted by Rod West and Rob Stefani. If you are attending as a guest, you may not only submit questions during the question period following the formal business of the meeting. We will do our best to ensure that all shareholder questions are addressed at the conclusion of the meeting. But if for any reason, we are unable to do so during the meeting, we will endeavor to follow up with the shareholder after the meeting.

Given this is a virtual meeting, the voting at today's meeting will be conducted by online ballot for all matters. If as a registered shareholder or duly appointed proxy holder, you have used your control number to log into the meeting and you accept the terms and conditions of the meeting, you'll be provided the opportunity to vote by online ballot. If you've already voted by proxy and you vote again by online ballot during the meeting, your online vote during the meeting will revoke your previously submitted proxy.

Accordingly, if you've already voted by proxy and do not wish to vote -- to revoke your previously submitted proxy, please do not vote again during the online balloting period. The polls will be open for all items of business to be voted on at the same time. This will allow you to vote on each item immediately or if you prefer, you may wait until the conclusion of discussion on each item prior to casting your vote.

The items of business to be voted on and your available voting options will be visible on the voting panel on your screen. To submit a vote, please click on the applicable voting choice displayed on your screen. Once discussions have concluded on all items of business, we will provide a few additional moments to enter your votes. I will then declare the voting closed on all matters of business. The results of the votes on each matter will be announced prior to the closing of the meeting.

During today's meeting or the question-and-answer period that follows, representatives of the corporation may make forward-looking statements. These forward-looking statements are neither promises nor guarantees of the corporation's future performance and are subject to risks and uncertainties that may cause the actual results, performance or achievements of the corporation or developments in the corporation's business or industry to differ materially from those anticipated by such forward-looking statements.

Certain material factors and assumptions were applied in drawing these conclusions and making the forecasts and projections reflected in the forward-looking statements. Additional information about the material factors that could cause actual results to differ materially from those anticipated by the forward-looking statements and the material factors and assumptions applied in connection with such forward-looking statements can be found in the corporation's most recent annual information form and management's discussion and analysis, which is available on SEDAR and EDGAR.

I'll now call the meeting to order. In accordance with the corporation's bylaws, I will chair the meeting, and Ryan Elger will act as Secretary. I appoint representatives of TSX Trust Company, the corporation's transfer agent, to act as scrutineers for the meeting. Based on the scrutineer's report, report proxies were received from the holders of a sufficient number of common shareholders to constitute a quorum. Accordingly, I declare that the meeting is properly constituted for the transaction of business. I now declare the online voting polls open on all items of business.

Further to an exemption obtained by the corporation of the Canada Business Corporation Act, the corporation used notice and access to send the notice of meeting and other requisite meeting materials to each intermediary and registered holder of common shares to close at the close of business on May 19, 2026, the record date for this meeting. Materials have been provided to each of the directors and the corporate auditors. I direct the confirmation of delivery of the notice of meeting and the scrutineers' complete report on attendance be annexed to the meeting -- to the minutes of this meeting.

In addition, copies of the annual report containing the audited financial statements of the corporation for the year ended December 31, 2025, have been sent to the shareholders of the corporation who requested them. Accordingly, with the consent of the meeting, I will dispense with reading the notice of meeting.

The first item of business is the presentation of the corporation's audited financial statements for the year ended December 31, 2025, and the auditor's report thereon. I direct that the financial statement and the auditor's report be annexed to the minutes of the meeting. Unless there is an objection, I will dispense with the reading of the auditor's report.

The next item of business is the reappointment of the auditor of the corporation. May I have a motion that Ernst & Young LLP be reappointed as the auditor of the corporation until the end of the next Annual Meeting of the Shareholders or until a successor is duly appointed.

My name is Jane Tran, and I so move.

Would anyone care to second the motion?

My name is Jennifer Tindale, and I second the motion.

Thank you. In order to be carried, the motion must be passed by a majority of votes cast. At this time, we would ask the moderator to please advise of any questions that have been received in this matter.

I confirm that there are no questions relevant to the immediate matter at hand.

And we will now proceed to vote by online ballot. As previously noted, if you have already voted by proxy and you vote again by online ballot during the meeting, your online vote during the meeting will revoke your previously submitted proxy. If you have already voted by proxy and do not wish to revoke your previously submitted proxy, please do not vote again during the online ballot. Registered shareholders and duly appointed proxy holders can choose to vote by online ballot now by selecting the applicable voting option. I will announce the results of the vote at the conclusion of the meeting.

[Voting]

We'll now proceed with the election of directors. The corporation's articles provide that the Board of Directors determine from time to time the number of directors within the minimum and maximum numbers provided for in the articles. The Board has determined the number of directors to be elected at this meeting is 9.

As described in the management information circular, the Canada Business Corporations Act specifies a majority voting standard for the election of directors. This means that in order to be elected, each nominee must receive more votes for his or her election than votes against.

I would like to call on Jennifer Tindale to nominate the directors.

I nominate the individuals named in the management information circular to stand for election as directors of the corporation, namely: Brett Carter, Amee Chande, D. Randall Laney, David Levenson, Christopher Lopez, Gavin Molinelli, Dilek Samil, DeAnn Walker and Roderick West.

Thank you, Jennifer. Particulars of these 9 nominees are set out in the management information circular. In the absence of instructions to the contrary, management proxies will be voted in favor of these nominees, each of whom has accepted his or her nomination. If elected, these nominees will hold office until the end of the next Annual Meeting of the Shareholders or until their successors are duly elected or appointed.

Pursuant to our advanced notice bylaw, since there have been no director nominations put forward other than the directors nominated on behalf of the management and set out in the management information circular, I declare the nominations closed. May I have a motion for the election of the 9 persons nominated as directors?

My name is Jane Tran, and I so move.

Would anyone care to second the motion?

My name is Ryan Elger, and I second the motion.

Thank you. At this time, we would ask the moderator to please advise of any questions that have been received on this matter.

I confirm that there are no questions relevant to the immediate matter at hand.

Thank you. We will now proceed to vote by online ballot. Voting is for each individual nominee. Registered shareholders and duly appointed proxy holders can choose to vote by online ballot now by selecting the applicable voting options. I will announce the results of the vote at the conclusion of the meeting.

[Voting]

The next item of business is the amendment of the corporation's share unit plan. The full text of the share unit plan as is intended to be amended is set out in Schedule C to the management information circular and the resolution set out on Page 18. May I have a motion that the resolution set out on Page 18 of the management information circular approving the amendment of the shareholder unit plan be approved.

My name is Jane Tran, and I so move.

Would anyone care to second the motion?

My name is Jennifer Tindale, and I second the motion.

Thank you. In order to be carried, the motion must be passed by a majority of the votes cast. At this time, we'd like to ask the moderator to please advise of any questions that have been received on this matter.

I confirm that there are no questions related to the matter at hand.

Thank you. We'll now proceed to vote by online ballot. Registered shareholders and duly appointed proxy holders can choose to vote by online ballot now by selecting the applicable voting options. I will announce the results at the conclusion of the meeting.

[Voting]

The final item of formal business on the agenda is the advisory vote on the approach to executive compensation. The text of the advisory resolution is set out on Page 18 of the management information circular and a simple majority of the votes is required for its approval. Although the results of an advisory resolution are not binding on the Board of Directors, the Board will take the results into account together with other feedback from shareholders in considering the approach to executive compensation in the future.

May I have a motion that the advisory resolution on the approach to executive compensation contained on Page 18 of the management information circular be approved.

My name is Jane Tran, and I so move.

Thank you. Would anyone like to second the motion?

My name is Jennifer Tindale, and I second the motion.

Thank you. At this time, we'd ask the moderator to please advise of any questions that have been received on this matter.

I confirm that there are no questions relevant to the immediate matter at hand.

Okay. We will now proceed to vote by online ballot. Registered shareholders and duly appointed proxy holders can choose to vote by online ballot now by selecting the applicable voting options. I will announce the results of the vote at the conclusion of the meeting.

[Voting]

It is now 10:14 -- or no, excuse me, 11:14 Eastern Time zone. The online ballots on all items will close in 1 minute to the current time. For those of you who have not voted yet -- yet voted on all the items of business, please do so now. As previously noted, if you have already voted by proxy and do not wish to vote or revoke your previously submitted proxy, please do not vote again during the online ballot. We'll now take a short break while the polls close and the results are tabulated by the scrutineers.

[Voting]

I can now confirm the online ballots are now closed, and the scrutineers have tabulated the results. I'm pleased to announce that the scrutineers have reported that all matters put to ballot have been passed with the requisite shareholder approval. Accordingly, I declare that Ernst & Young LLP have been reappointed auditors of the corporation. Each of the 9 nominees to the Board of Directors has been elected. The amendment of the share unit plan has been approved and the advisory resolution to the approach to executive compensation was passed. The corporation will file a report disclosing the voting results on each item of business on SEDAR and EDGAR following the meeting.

As there is no formal business that may properly be brought before the meeting, this concludes the formal part of the meeting. Thank you for attending, and I now declare the meeting terminated. There will now be a general question-and-answer period conducted by Rod West and management.

Thank you, Randy. We would now like to invite questions from meeting attendees. Rest assured, we will not be attempting to limit or filter legitimate questions, and we'll do our best to address all relevant issues raised. As previously noted, to the extent we are unable to respond to a submitted question, we will endeavor to follow up with you after this meeting. If you wish to ask a question, please click on the question icon on the left-hand menu, if you're on a web browser or on the bottom menu if you're on a mobile browser and then type in and submit your question. There are no questions before us.

Okay. Thank you, Rod. On behalf of the Board and the management of the corporation, I'd like to thank all of our shareholders as well as others who have joined us today for the attendance at the meeting and the ongoing support. Thank you, and have a good day.

Hello, and welcome to the Algonquin Power & Utilities Corporation First Quarter 2026 Earnings Conference Call. [Operator Instructions] I will now turn the conference over to Mr. Brian Chin, Vice President of Investor Relations. Please go ahead.

Thank you, operator, and good morning, everyone. We appreciate you attending our first quarter 2026 earnings conference call. Joining me on the call today will be Rod West, Chief Executive Officer; and Rob Stefani, Chief Financial Officer, who will share prepared remarks. Other members of the management team are also available to answer your questions during the Q&A portion of the call today. 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. Additionally, all net earnings information to be discussed today is for continuing operations and is attributable to the common shareholders of Algonquin. 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 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 important additional information on these items.

On the call this morning, Rod will provide a business update, and Rob will follow with the details of our financial results. We'll then open the line for questions. We ask that you kindly restrict your questions to 2, then follow up with us after the call if you have any additional questions to allow others the opportunity to participate. And with that, I'll turn things over to Rod.

Thanks, Brian, and good morning, everyone. Thanks for joining us. First quarter 2026 has been a solid start for Algonquin, and I'm pleased to say that we are indeed pushing ahead on our path to premier. As I stated in my early days at Algonquin, a premium pure-play regulated utility earns its standing through consistent execution, constructive regulatory outcomes supported by disciplined financial and operational management. These attributes position the company to deliver sustainable value to shareholders, customers, employees and the communities we serve.

As we'll discuss in a moment, this quarter's results touch on all of those and build on the measurable progress we've made from 2025. In short, we're advancing toward our goal of becoming a premier pure-play regulated utility. Taking measure of our strategic priorities for the year, I'm pleased with the progress we've made in the first quarter. For example, on the operations front, we've begun to roll out updated procedures and training materials for damage prevention and leak response at our gas operations. We've also implemented quality assurance and quality control reviews of line locating activities by independent inspectors.

On the customer side, in Missouri, we've improved our billing accuracy versus prior periods and improved our communications to customers in the moments that matter to them. On the regulatory side, we are pleased to achieve conclusions to our rate cases at New England Gas and CalPeco Electric, an order approving our settlement agreement at Empire Electric and the tariff agreement at Suralis, our Chilean water utility.

We continue to work towards resolution of our Arizona Litchfield Park Water & Sewer and Empire Kansas rate cases. On the corporate front, we expect to refinance our senior unsecured notes due in June, which Rob will discuss in more detail shortly. And we continue to explore tax optimization strategies, including a potential redomicile. In summary, we've laid out our list of strategic priorities for the year. And for the first quarter, we've made solid progress on this priority list.

On Slide 6, we've outlined several factual considerations that require evaluation as part of a possible redomicile, which I know is a common area of inquiry. As a reminder, we have not made any definitive decisions on this and such a move would require the approval of our Board, shareholders and other stakeholders. One timing point. We have engaged with the Internal Revenue Service to request a private letter ruling to confirm tax treatment, and these types of requests typically take 6 to 9 months to rule on. We will update you when we have more to share.

Turning to Slide 7. Focusing in a bit more on our regulatory strategy, we've been prioritizing earlier dialogue to identify areas of common ground as well as advancing more pragmatic filings. We expect this to deliver fair regulatory outcomes that allow us the opportunity to capture both recovery of reasonable costs and returns on our investments for the benefit of our customers. I'm pleased to note that we are starting to see this play out. In Massachusetts, the Department of Public Utilities on March 27 approved our New England natural gas settlement agreement, which calls for a $45.3 million revenue adjustment.

In California, the Public Utilities Commission on March 19 approved a proposed decision that adopts our CalPeco Electric settlement agreement with the exception of changes to the proposed adjustment to our fixed charge for residential customers, which will remain the same. The approved decision provides for additional $48.6 million in annualized revenues and includes a retroactive adjustment to January 2025. Rob will provide more details on the CalPeco settlement in just a moment.

For Empire Electric Missouri, we continue to await commission review of our customer performance data. As a reminder, the approved settlement requires 3 consecutive months of customer metric performance before we can implement the $97 million in annualized revenues. We've submitted the 3 monthly filings in which we identified limited deviations in each month, consistent with the provision of the settlement. We are now awaiting commission approval. Separately, the next step to the settlement is an additional potential $13 million of annual revenues based on meeting further performance requirements stated in the -- starting rather in the second half of 2026.

We remain in close discussions with stakeholders to arrive at an appropriate set of customer performance metric definitions and review the processes for this second tranche of revenues. With regard to active cases in Arizona, our settlement agreement and a decision regarding formula rate plans remains pending at Litchfield Park Water & Sewer. We've asked the commission for a decision by August. In California, separate from our CalPeco general rate case, we have our WEMA proceeding, which we filed in June of 2025. This application seeks recovery of approximately $77 million in wildfire costs, consisting primarily of claim settlements in excess of insurance coverage, legal costs and finance costs related to the 2020 Mountain View Fire.

We have also received proposed decisions and ultimate proposed decisions in our Park Water and Apple Valley rate cases. In Kansas, our rate case at Empire Electric requesting a $15.8 million base rate change is pending. And finally, at our Chilean water utility, Suralis, we just this week reached an agreement with our regulators in our most recent tariff proceedings, which includes a $4 million rate adjustment expected in the latter half of the year. The common thread through these updates is this. We continue to make steady progress on rate cases across multiple jurisdictions in a more deliberate and intentional manner, doing a better job of involving all stakeholders.

Slide 8 helps to put all of this in context. Simply put, our regulatory strategy means we're engaging in key dialogue earlier, identifying broader areas of common ground, filing in a more timely and accurate fashion and as a result, achieving more constructive resolutions. In other words, we're getting back to regulatory basics to earn our right to grow -- earn the right to grow on our path to premier.

Turning to Slide 9. I'll add a few comments regarding our evolving regulatory and legislative landscape. On April 7, the California Earthquake Authority released its natural catastrophe resilience study report as required by Senate Bill 254's passage last year. We found a number of points in the report worthy of further discussion. For example, we support the report's concept of expanding the catastrophe fund to protect smaller utilities like CalPeco and the communities we serve so that we have the same financial protections during natural disasters as those served by our larger brother and sister utilities in the region.

We also support the reports suggesting to transition the catastrophe fund away from a customer-only funding model. Wildfire safety is a shared state responsibility that should be supported by broader state resources, not just through utility bills. We're looking forward to presenting more of our perspectives on this and other points raised in the report in the near future. More broadly, in states, including Arizona, Missouri and New Hampshire, we're working to build coalitions with our peers to educate stakeholders on the benefits of forward test years and formula rate plans that facilitate constructive customer-centric investment in our communities.

These mechanisms are examples of the predictable, transparent regulatory framework that support full and timely cost recovery and are key to operating as a premier pure-play regulated utility. This allows the opportunity to capture returns closer to authorized return -- ROEs with the objective of supporting earnings and credit metrics stability, all to benefit our customers. And I'm pleased to say that in this first quarter, we've taken several steps further along on our journey to Premier.

With that, I'll turn it over to Rob to walk through our financial update for the quarter.

Thanks, Rod, and good morning, everyone. On Slide 11, we reported first quarter GAAP net earnings of $83.1 million compared to $92.8 million for the same period in 2025. First quarter 2026 adjusted net earnings were $99.6 million versus $109 million for the first quarter of 2025. Overall, the slight decline from 2025 to 2026 reflects the nonrecurrence of favorable depreciation and tax adjustments recognized in the first quarter of 2025 and slightly unfavorable weather year-over-year, almost entirely offset by a favorable retroactive adjustment in the resolution of our CalPeco general rate case. I'll discuss the drivers behind this in more detail as I walk through our results.

On Slide 12, we provide our first quarter 2026 adjusted net earnings per share walk to common shareholders. First quarter adjusted net EPS to common was $0.13 per share, which was $0.01 lower year-over-year. Our CalPeco rate case is the largest driver for our year-over-year results. As noted earlier, our rate case concluded with the increase to approved annualized rates of $48.6 million. This resolution includes retroactive revenues to January 1, 2025, of $60.7 million. This revenue uplift was partially offset by higher wildfire insurance expenses recovered in rates of $28.5 million, which includes retroactive insurance expenses to the first quarter of 2025 of $22.7 million.

I'll provide a little more context on this point. Wildfire insurance costs incurred and paid in 2025 above the amount permitted in rates at that time were deferred onto our balance sheet as part of the regulatory process. In the first quarter of 2026, the commission approved and finalized authorized revenues and costs for 2025. The commission's approval prompted retroactive recognition of those on our income statement, along with the higher revenues and costs as required by U.S. GAAP. The net effect of the increase in revenues and the increase in wildfire insurance expenses, inclusive of the retroactive adjustment amounts to an increase in year-over-year EPS of $0.03 per share.

Elsewhere, our net revenues year-over-year were down by $11.9 million, driven primarily by slightly unfavorable weather in the quarter compared to slightly favorable weather in the comparable period in 2025. Operating expenses increased by $41 million compared to the first quarter of 2025, driven primarily by the aforementioned $28.5 million in wildfire insurance expenses as a result of the retroactive adjustment from the CalPeco rate case.

Aside from the retroactive adjustment, the increase in operating expenses was primarily driven by our $3.8 million in gas safety excellence costs and higher labor, benefits and property taxes across our gas systems. Depreciation increased by $12.9 million, primarily due to the nonrecurrence of 2 favorable depreciation deferrals in the first quarter of 2025 that totaled $8.2 million at Granite State Electric and Litchfield Park Water & Sewer. Tax expenses were higher by $9 million due primarily to the nonrecurrence of a favorable first quarter 2025 tax adjustment for our Hydro Group following the January 2025 sale of our renewable energy business.

Briefly touching on Slide 13, our balance sheet continues to be in a position of strength with a reaffirmation of our credit ratings in the BBB range by Fitch for Algonquin in the last few weeks, and we remain at BBB at S&P and Baa2 at Moody's. On the near-term financing front, we expect to refinance the Algonquin unsecured notes due in June of this year by raising approximately $1.15 billion at LUCo through a 144A bond issuance as discussed on our prior earnings call. Additionally, we recently put in place a $1.15 billion delayed draw credit facility to support the execution of this refinancing if it's required.

With that, I'll turn the call back over to Rod for his closing remarks.

Thanks, Rob. Before we open the line for questions, I just wanted to step back for a second and leave you with a few thoughts on where we are and where I think we're headed. It's only been a couple of months since we last provided you an update. But in that short time, we've made some meaningful progress. We received the approvals in our Empire Missouri, CalPeco and New England Gas rate cases and reached an agreement in Chile for Suralis, the water company there. We're working diligently towards the resolution of our California WEMA, Arizona Litchfield Park and Empire Electric Kansas proceedings. We're providing an influential voice in advancing our point of view towards more constructive regulatory and legislative compacts in states like California, New Hampshire and Missouri.

And operationally, we've implemented improvements in our gas excellence efforts and improved our customer billing accuracy. In short, we've extended our tremendous 2025 momentum into the first quarter of this year, and we remain confident in our plan ahead. I couldn't be more excited for what's next, and I hope you'll join us on our path to Premier.

Thanks for your time this morning. And with that, I'll turn it back to the operator for questions.

[Operator Instructions] The first question comes from Elias Jossen from JPMorgan.

Just wanted to start on the Empire Missouri billing. Can you just walk us through procedurally what the key milestones are for execution, the phase-in time line once you kind of have clarity on those metrics? And any other expectations from staff that you can provide color on today?

I think I'll just give you an overview. Our objective and certainly responsibility is to show 3 consecutive months of designated performance metrics. We made the filings for those first 3 months. And the commission on advice will get essentially an assessment from the staff on their point of view and observations regarding our performance. And then the commission would then essentially confirm their point of view on us having met the requirements and allow us to implement the rates consistent with the settlement. And it's our expectation, given the fact that we believe we've met our expectations that the commission will rule on it by midyear. Amy, our Chief Customer Officer, is here with me. And if there's anything I've missed or anything that you think we ought to communicate, you're welcome to add anything, Amy.

I think you've covered it, Rod. I do believe that -- we want to thank the staff for their thorough review of the data that we've provided, and we look forward to the commission's response to their feedback.

Great. And then maybe just further on the IRS private letter ruling. I know that this is an ongoing process, and you provided some clarity in your opening remarks. But maybe can you just give us a little bit of color on what this ultimately means for Algonquin going forward and what a potential outcome could look like here?

Yes, go ahead.

Elias, it's Rob. Yes, so we've engaged with the IRS. As you probably know from other situations, those rulings typically take 6 to 9 months. And so that will affect the timing of kind of further updates around this. What we're asking them to assess is obviously the tax implications of a legal redomiciling into the United States. There would be tax consequences associated with that, and we're trying to get the best estimate of what those would be.

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

I just had a question relating to CalPeco. I saw an article about NV Energy indicating that they'll no longer supply electricity to CalPeco starting in May of next year. And I think that coincides with the completion of the Greenlink transmission line. But can you just provide a bit more comment on the power supply plans for CalPeco and whether there's any opportunities to add some generation to the utility?

Nelson, this is Rob. So we're launching a competitive search for new energy partners. We filed a request with the CPUC to begin the search, expect formal bidding to commence later this summer and then preferred selection should be announced in the winter of '26, '27. So if that's been approved by the CPUC, we'd expect to enter into new power supply agreements by the spring of 2027.

Okay. Got it. And there are no plans to potentially add generation to the utility in terms of building some of your own generation. I know previously, CalPeco added some solar facilities.

Yes. So as part of the fourth quarter, those solar facilities, we stood down on. But at this point in time, we're just launching a competitive search for new energy supply partners in the region.

Got it. And then my next question just relates to CapEx. I know the guidance for the year is about $800 million. I think CapEx in Q1 was about $88 million. So I presume it's just seasonal or timing, but -- or is there a large project that might kick off?

It's a safe -- yes, your assumption is correct. Seasonal and timing. We still have an expectation of meeting our capital plan, but your instincts are spot on.

There are no further questions at this time. I'll turn the call to Mr. Rod West for closing remarks.

Well, I'll just say thank you for your time and attention, and we look forward to our next update. And before I close, just thanks to the employees who have contributed so much to our progress thus far. All the best.

That concludes today's meeting. You may now disconnect.

Hello, and welcome to the Algonquin Power & Utilities Corp. Fourth Quarter 2025 Earnings Conference Call. [Operator Instructions] I will now turn the conference over to Mr. Brian Chin, Vice President of Investor Relations. Please go ahead.

Thank you, operator, and good morning, everyone. Thank you for joining us for our fourth quarter and full year 2025 earnings conference call. Joining me on the call today will be Rod West, Chief Executive Officer; and Rob Stefani, Chief Financial Officer, who will share prepared remarks. Other members of the management team are also available to answer your questions during the Q&A portion of the call today.

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.

Additionally, all net earnings information to be discussed today is for continuing operations and is attributable to the common shareholders of Algonquin. Certain material factors and assumptions were applied in making the forecasts and projections reflected in 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 on SEDAR+ and EDGAR and available on our website for important additional information on these items.

On the call this morning, Rod will provide a business update, and Rob will follow through with details of our financial results. We'll then open the line for questions. [Operator Instructions]. And with that, I'll turn things over to Rod.

Thanks, Brian, and good morning, everyone. Thanks for joining us. 2025 was a turning point for Algonquin. We delivered strong results, improved earned returns, made substantial operational and regulatory progress and meaningfully strengthened our balance sheet. And those results reflect something broader.

Algonquin is a different company today than it was a year ago. We are more focused, more disciplined and to each other and to our stakeholders more accountable. We have sharpened our strategy, assembled an experienced leadership team and laid the foundation for a sustained performance culture. In short, we're advancing toward our goal of becoming a premium pure-play regulated utility.

Turning to Slide 5. I'll begin my remarks today by walking through our accomplishments in 2025. We delivered full year net earnings per share of $0.27 and adjusted net EPS of $0.34, which exceeded the top end of our guidance range by $0.02. These results demonstrate that our Back-to-Basics strategy is driving measurable improvements in our underlying fundamentals. And as we've discussed before, becoming a premium utility starts with getting the fundamentals right.

Since I joined Algonquin, we focused on, first, improving operational discipline to improve customer outcomes and driving efficiencies by bending our cost curve; and second, strengthening regulatory strategy execution through more proactive stakeholder engagement, all to drive more constructive and timely outcomes. Our 2025 results provide recent evidence of that focus. We reduced operating expense as a percentage of gross revenue by -- from approximately 38% in 2024 to roughly 36% in 2025. We achieved constructive regulatory outcomes across a range of proceedings, and we improved our earned ROE from 5.5% in 2024 to approximately 6.8% in 2025.

We also made progress this year in strengthening our balance sheet. We used net proceeds from the sale of our renewable business, excluding our hydro assets to retire approximately $1.6 billion of debt, materially improving our cap structure and financial flexibility. And finally, we continue to simplify the company and the story, both through portfolio actions and by reducing complexity inside the regulated platform. While we clearly have much more work to do, this was a good start, and we carry that momentum into 2026.

Looking ahead to 2026 on Slide 6, our priorities build directly on what we have achieved over the last 12 months. Operationally, cost discipline remains a core priority. As we transition to a more commodity aligned structure and centralizing shared services around cost and value, we expect to capture additional efficiencies and drive consistency across our gas, water and electric portfolio. As we undertake these efforts, we're also implementing a centralized capital projects team to improve our execution performance and reducing risk.

At the same time, we're focused on improving the safety and reliability of our system, supporting positive customer outcomes and maintaining affordability across all of our jurisdictions. To drive better customer experiences, we've been making improvements across our end-to-end process design, focusing on the moments that matter most to our customers. This includes more accurate billing and better delivery of information during any kind of disruption.

From a regulatory standpoint, we're pleased to receive approval of our settlement in Empire Electric Missouri's rate case in January this year. We're working there to see the rates implemented, which remains subject to evaluation of specific customer metrics. We were also glad to reach settlement agreements at New England Gas, CalPeco Electric and Arizona Litchfield Park Water & Sewer and look forward to advancing them towards approval and implementation. I'll speak to each rate case in a bit more detail shortly.

Finally, at the corporate level, we've recently onboarded key leaders, including Rob as our new CFO; Pete Norgeot as our new Chief Operating Officer; and Kristin von Fischer as our new Chief Human Resources Officer. Our execution against these priorities underpins our financial outlook.

For 2026, we're pleased to reaffirm our earnings guidance. The drivers supporting this year's guidance range are well defined, and we're confident in our ability to execute. Relative to where we were last June, we now expect our effective tax rate in 2027 to be in the mid- to high 20s percent range as compared to the previously anticipated low to mid-20s percentage range. We're continuing to evaluate tax strategies to optimize the tax rate, but expect the majority of the benefits from those strategies to be realized after 2027. This largely results in an updated expected adjusted net EPS range for 2027 of $0.38 to $0.42.

With an executive team that brings deep utility experience now in place, in addition to the aforementioned tax optimization work, we're focused on disciplined execution and constructive regulatory engagement to position the business to deliver sustainable earnings growth over the long term while also looking for additional opportunities to bridge the gap caused by the tax rate relative to last June.

Turning to Slide 7. While there is more to be done to bring resolution to a number of key rate cases, we're seeing the benefits of our regulatory and stakeholder engagement approach. By prioritizing earlier dialogue to identify areas of common ground as well as advancing more pragmatic filings, we've been able to achieve settlement agreements. We expect these agreements will deliver reasonable regulatory outcomes that benefit our customers and allow us to recover investment in our systems efficiently. Let me walk through our key recent proceedings.

In January this year, the Missouri Public Service Commission approved our settlement agreement for Empire Electric, which is our largest operating utility. This authorizes a $97 million revenue increase after we meet customer metric performance requirements for 3 consecutive months, with an additional potential $13 million of annual revenue increase based on meeting further performance requirements starting in the second half of 2026.

In California, we received a proposed decision at CalPeco Electric, adopting the proposed settlement agreement, which provides for a $48.6 million revenue increase retroactive to January 2025, an ROE -- allowed ROE of 9.75% and an equity ratio of 52.5%. We are awaiting a final decision. In Massachusetts, we reached a settlement for New England Natural Gas, which calls for a $45.3 million revenue adjustment, of which approximately $17.9 million is non-gas system enhancement plan revenue, with 2 additional step-ups in rate base in subsequent years. The settlement includes an allowed ROE of 9.3% and an equity ratio of approximately 52.9% and a rate stay out -- the rate case stay out through October 31, 2029. We've requested a commission order by the end of this month.

In Arizona, just this week, we filed a proposed settlement for Litchfield Park Water & Sewer. The settlement, which was reached with the Arizona Corporation Commission staff calls for a $15.3 million revenue adjustment and an ROE -- allowed ROE of 9.75% with a 54% equity ratio. Hearings are scheduled for late March of this year.

And finally, in Kansas, we filed a rate case at Empire Electric in December, requesting a $15.8 million base rate adjustment, which represents a net requested increase of $12.5 million with a 3-year phase-in for a gradual adjustment.

Slide 8 helps put all of this in context. Over the past year, we have steadily resolved rate cases across multiple jurisdictions, advancing from filing to constructive resolution to implementation of rates. As we look ahead, we now have line of sight to resolving a significant portion of the remaining requested revenue adjustments this year, which will inform our forward earnings trajectory.

Turning to Slide 9. We are fortunate to operate in high-quality jurisdictions that have attractive regulatory mechanisms. This includes tracker mechanisms, multiyear rate plans, forecasted test years and formula rate structure. These regulatory mechanisms underpin the majority of the expected rate base growth between now and 2028. Building on this foundation, recent legislative and regulatory developments across our states are supporting enhanced investment recovery. Recent advances in Missouri, Arizona, New Hampshire and Oklahoma are further strengthening our regulatory frameworks with the adoption of future test years, CWIP for new gas generation, plant and service accounting and consideration of formula rates. Overall, these developments reinforce the constructive regulatory environments in which we operate.

With that, I'll turn it over to Rob to walk through our financial update for the quarter and year-end. Rob joined the company just this past January on January 5. Many of our analysts and investors may already know Rob from his time as CFO of Southwest Gas Holdings. He also previously served as CFO and Treasurer of PECO Energy, a Philadelphia-based electric and gas utility subsidiary of Exelon. Rob joins a strong team of experienced utility executives in the C-suite. And as we continue to build our utility platform, Rob's utility leadership experience, strategic skill set and financial expertise will be leveraged to build a strong foundation for the company as we solidify our strategy and execute on our path to becoming a premium utility.

So again, Rob, and for my last time formally welcoming you, I'll hand the call over to you.

Thanks, Rod, and good morning, everyone. I've been immersed in my first 2 months at Algonquin, and I'm excited to partner with Rod and the leadership team here to build a premium utility through disciplined execution across the organization. With that, I'll turn to our results on Slide 11.

We reported full year GAAP net earnings of $208 million compared to $54.8 million in 2024. Full year adjusted net earnings were $258.8 million, up approximately 17% from $221.6 million in 2024. For the fourth quarter, GAAP net earnings were $29.4 million compared to a net loss of $110.2 million in the fourth quarter of 2024. These strong results reflect the progress we are making to deliver steady, predictable earnings. I'll now discuss the drivers behind this improvement as I walk through our adjusted net EPS results.

On Slide 12, we provide our fourth quarter 2025 adjusted net EPS walk to common shareholders. Fourth quarter adjusted net EPS to common was $0.06 per share, which was flat year-over-year. On the top line, the increase in adjusted net earnings was primarily driven by $10.3 million from the implementation of new utility rates at BELCO Electric, Midstates Gas, Peach State Gas, Missouri Water, New York Water and several of our Arizona water and sewer systems.

Moving to interest expense. We realized a $17.9 million reduction, reflecting the paydown of debt using proceeds from both the sale of the renewable energy business and the sale of our ownership stake in Atlantica. This has been a consistent positive driver throughout the year and a direct result of our balance sheet strengthening efforts. Operating expenses and depreciation were modestly higher by $6.1 million, driven by fourth quarter costs associated with the targeted relief initiative for customers agreed to as part of our Empire Electric Missouri settlement.

Full year basis, operating expenses were essentially flat. These benefits were offset by the removal of $10.9 million in Atlantica dividend income, which impacts the corporate group as well as a $7.3 million write-off related to the CalPeco solar project that was discontinued. Taxes were flat year-over-year.

Moving on to Slide 13. Full year adjusted net EPS attributed to common was $0.34 per share, up from $0.30 per share in 2024, representing approximately 13% growth. This exceeded the top end of our previously stated guidance range by $0.02 per share, driven by accelerated realization of our operating expense savings, lower depreciation expense resulting from authorized deferrals and tax adjustments.

Let me walk through the key drivers in more detail. New utility rates contributed $41.6 million of benefit from approved rate implementations across several gas, water and electric systems throughout the year. We saw $13.9 million of favorable weather, predominantly at our Empire Electric system. In addition, we benefited from $11.9 million in depreciation deferrals. These factors were partly offset by the costs associated with the targeted relief initiative at Empire and CalPeco write-off mentioned previously.

We also recognized a $15.9 million Hydro Group tax adjustment that was largely recognized in the first half of the year from the Hydro reorganization completed in connection with the sale of the renewable energy business. Interest expense declined by $81.1 million, reflecting the paydown of debt using proceeds from the sale of the renewable energy business completed in January 2025 and the prior sale of our Atlantica ownership stake. The removal of $76.3 million in dividend income from the sale of an ownership stake in Atlantica was the single largest headwind for the year. As a reminder, the repayment of debt using the Atlantica sale proceeds contributes to the interest expense savings across both the Regulated Services Group and the corporate group, which partially offsets the lost dividend income.

We also absorbed a higher effective tax rate and common share dilution from the mandatory underlying shares as approximately 77 million common shares were issued upon the settlement of the purchase contracts in 2024. The Regulated Services Group growth was driven by the combination of new rate implementations, favorable weather, lower interest expense and the depreciation deferral benefits, partially offset by higher operating expenses and the solar project discontinuations.

Turning to Slide 14. We are updating our 3-year regulated utility capital expenditure outlook now totaling approximately $3.2 billion from 2026 through 2028. This includes approximately $800 million in 2026, ramping to $1.1 billion in 2027 and approximately $1.3 billion in 2028. Cash flow from the business and existing cash balances are expected to internally fund approximately 65% to 70% of the capital investment requirements. This capital plan is focused on reliably serving our customers with investments in safety, reliability and service across our electric gas and water systems. As you can see on the slide, the capital spend is expected to be diversified across our commodity types. Our large capital expenditure plan supports our strong organic regulated utility growth proposition. As Rod highlighted, across our jurisdictions, mechanisms exist to pursue recovery via capital trackers, formula rates and other interest rate case mechanisms.

I'd note that the 2025 capital expenditures totaled approximately $604 million, down from approximately $757 million in 2024, with the decrease primarily due to investment in our integrated customer solution platform, which was largely completed in 2024. In terms of rate base, year-end 2025 rate base was approximately $8.2 billion, up from $7.9 billion at year-end 2024. We expect our rate base to grow to approximately $8.5 billion by the year-end 2026, $9 billion by the year-end 2027 and approximately $9.7 billion by year-end 2028, representing a compound annual growth rate of nearly 6% from 2025 year-end through 2028.

On Slide 15, our balance sheet was meaningfully strengthened following the completion of the sale of the renewables business in January of 2025. We used approximately $1.6 billion of net proceeds to pay down debt. Combined with proceeds from the sale of our Atlantica ownership stake, we have significantly improved our credit profile. Total debt stands at approximately $6.5 billion. After adjusting for equity credit on our hybrid debt, Empire securitization bonds and preferred equity, our adjusted net debt profile supports our current credit ratings. We have a solid investment-grade credit rating with stable outlooks from S&P and Fitch. Moody's rates our operating subsidiary, Liberty Utilities at Baa2 with a stable outlook. We continue to expect no equity issuance through 2027.

On the near-term financing front, we plan to refinance the Algonquin unsecured notes that are due in June 2026, and we continue to manage our maturity profile in a disciplined manner. Lastly, we expect to pay an annualized dividend of $0.26 per share, subject to Board approval.

On Slide 16, you'll see a sources and uses table depicting the cash flows between the holding company of our U.S. operating businesses, Liberty Utilities Company, or LUCO, and the publicly traded holding company, Algonquin Power & Utilities Corporation or APUC. Our 2026 financing plan at APUC of approximately $1.6 billion includes nearly $1.45 billion upstream from LUCO. We expect this upstream to fund repayment of the June 2026 APUC of $1.15 billion debt maturity and the approximately $100 million Suralis term loan as well as the Algonquin common equity dividend. We expect to raise approximately $1.15 billion at LUCO through bond issuances to retire the June maturity at APUC.

Cash flow from ops of approximately $500 million and a draw of about $500 million on the credit facility together are expected to fund domestic regulated CapEx and the upstreaming of cash to APUC. Through these actions, we aim to proactively refinance upcoming maturities, fund the business, maintain liquidity and manage leverage without incurring additional incremental debt.

Let me walk through our financial outlook on Slide 17. First, we are reaffirming our 2026 adjusted net EPS estimate in the range of $0.35 to $0.37, consistent with the outlook we originally provided in June of 2025. The drivers supporting 2026 performance are underway, and we are confident in their achievability. As Rod discussed earlier, we are revising our 2027 adjusted net EPS estimate to a range of $0.38 to $0.42. We updated our assumptions regarding the company's effective tax rate in 2027, which is now expected to be in the mid- to high 20s percent range as compared to the previously anticipated low to mid-20s percent range.

We are continuing to evaluate tax strategies to optimize the tax rate, but expect the majority of the benefits from such strategies to be realized after 2027. The guidance revision also reflects expected timing of gas operational excellence activities to extend into 2027 before normalizing. With that, I'll turn the call back over to Rod for his closing remarks.

Before we open the line for questions, I want to step back and leave you with a few thoughts on where we are and where we're headed now that literally, this is my 1 year in the job. It was March 7 last year when I began my tenure. When I joined Algonquin just over a year ago, I said that this company had the very real potential to become a premium pure-play utility.

In 2025, we began turning that potential into results. Our leadership team is now in place, and we're delivering results through our Back-to-Basics strategy. We're focused on driving operational execution and constructive regulatory engagement to drive an attractive near-term financial profile as we close the gap to our authorized return. We have a strengthened balance sheet with a credit rating profile that provides low-cost access to capital and no expected equity needs through 2027.

We're executing a customer-focused capital plan of approximately $3.2 billion, focused on organic investment to enhance safety, reliability and improve customer service. As we continue to reearn our right to grow, we're keeping our eye on additional opportunities in our service territories. We believe this adds up to a clear and compelling investment thesis as we position Algonquin as a singularly focused pure-play regulated utility operating across high-quality, increasingly constructive jurisdictions. As you've heard me say, every component of our vision, mission and strategy is being developed with achieving sustainable premium attributes at the forefront. We're staying focused on capturing the opportunity ahead and executing the mission we've laid out. I couldn't be more excited about what's in store for 2026 and beyond.

Thanks for your time this morning. And with that, I'll turn it back to the operator for questions.

[Operator Instructions]

Our first question comes from the line of Baltej Sidhu with National Bank of Canada.

Just on the revised 2027 guidance, can you share details or the largest drivers that underpin the new assumptions towards the mid- to high 20s effective tax rate versus the prior assumptions?

Yes. Thanks, Baltej. It's Rob Stefani. Look, throughout my onboarding, we reviewed the financial projections. And during that assessment, the forward view of the effective tax rate moved from the low to mid-20s to the mid- to high 20s that we currently expect. That resulted in just over about $0.03 per share of EPS deduction. We're actively looking at tax optimization strategies, but those appear to really move past 2027, if pursued. As a result and in the interest of transparency, we revised that 2027 range down. Anything else I can add there for you?

No, I think I got it there. And then just a follow-up there for you, Rob, just more from a strategic overview. You've been in the seat now for 60 days. Could you share your thoughts on the largest levers that the business can pull in the near term and also potential procedures or processes that Algonquin doesn't have yet that you've seen elsewhere in your prior experience?

Yes. I mean, look, I think the strategy that Rod and the team have put together is strong, and that's really hinges around the rate case cadence and rate case strategy and engaging across our jurisdictions, bringing leaders in from very well-recognized utilities to enhance the operating platform like Amy and Pete and Kristin.

And so as I think about kind of levers we can pull as a management team with a lot of experience at premium utilities, I think that's really at the forefront. And then the balance sheet, we've got over $1.4 billion of liquidity. We've got a strong investment-grade balance sheet, and that provides us the flexibility to pursue organic growth as well as assess other opportunities. So as you think about levers, the leadership team, that refocus on regulatory engagement and then the sound financial balance sheet provides us a lot of flexibility.

Our next question comes from the line of Elias Jossen with JPMorgan.

I wanted to start on the additional opportunities you mentioned at the end of your remarks. Can you just frame what types of opportunities you see in the market and maybe touch on whether those would include some portfolio optimization opportunities as well?

I'll start and certainly let Rob weigh in with his early observations. The opportunities from my vantage point aren't new. Our growth story starts with organic growth within our existing jurisdictions where we have both the opportunity, and I would dare say the mandate to create different customer outcomes in the areas we serve. And the underpinning of our rate base growth is predominantly organic.

What we've said in prior -- the last prior couple of quarters, particularly since last May, is that the portfolio, we've done the work on our existing portfolio with all the potential scenarios around puts and takes. And what you've heard from us is that we remain opportunistic. There was nothing so compelling given the screening criteria for M&A that keeps us disciplined on our core business. There was nothing immediately so compelling that it required us to move now. But to the extent that there are opportunities for us to take a look at potential moves within the portfolio, we're poised to do that. There was a capital recycling opportunity.

Again, we have a point of view around things that might be in the dashboard. But our focus still -- and remember, it's only -- from my vantage point, at least, it's only 12 months in. We're under the hood right now improving the existing portfolio with an eye towards creating sustainable returns from that base. And we'll continue to be eyes wide open on additional moves, but they got to be accretive. They got to be transactional to be able to be executed, and they can't so unduly distract us from the commitments we've made. So opportunistic is the word.

Great. And then we've seen some initial rate case and broader operational execution across the business. But maybe thinking a bit further out, how should we think about this transitioning from an ROE improvement vision to one that is more growth driven by solid rate base trends and growth across the business?

Yes. That's the right question and the one that's occupying us. It starts first on our end by improving the outcomes for customers and our own operational discipline, earning the right to make requests for the -- and I use the term gently, the tweaks and the regulatory mechanisms in our respective states. I'll give you a prime example.

I'll use the state of Missouri because I remember off the top of my head, I think it's Senate Bill 4 that created forward test year formula rate plans for water and gas, I believe, and it did not include electric. But given what we know to be our capital focus to create customer outcomes and support economic development in that Empire region, it would be a helpful component if we didn't have -- if we had the access to forward test years and formula rates in the electric business, right? But those require legislative adjustments. And I could see where we would align -- we can align with our stakeholders there to help support more timely and constructive recovery mechanisms consistent with our customer-centric capital plan.

That's just one example of the types of tweaks where we have an opportunity to close the gap and allow returns by coming to the regulator with an all-out effort to lower cost to be focused on affordability, while at the same time, meeting our aligned objectives around improving customer outcomes, supporting economic development and certainly for us, meeting our financial obligations to our owners.

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

Rod, congrats on your first anniversary on the job. My first question just relates to CalPeco, the solar project that was canceled or written down. Can you just give a bit of background on that project and like how big it was? Because I think there are several solar assets at CalPeco already, but I just want to kind of understand -- provide a bit of color. And then also, I guess it was also included in adjusted earnings and why it wasn't adjusted out?

Yes. So just regarding the question on the CalPeco solar write-off, that project was in Nevada, was meant to bring power in CalPeco. Just given where the economics of the project were and our assessment of the ability to earn a fair return on it, we decided not to move forward. As far as why it wasn't included in adjustments, I think as a utility with the rate base, the size of ours, obviously, you'll have projects that could potentially be abandoned along the way. And so view that more as something that wouldn't necessarily be classified as one-off. Obviously, you strive to limit those. But in that case, we wanted to reflect it within operating expenses year.

Okay. Great. And then my next question is, I know, Rod, you previously talked about potentially redomiciling. Do you have any updates or early indications on that process? And I was just wondering whether that could potentially impact your effective tax rate.

The short answer is it could. And the other answer is it's ongoing. I won't be in a position to announce anything on the redomicile question other than to say we are advancing our analytics around answering those types of questions to the extent that a redomicile conversation could influence our point of view on our respective tax strategy and the options available to us. And we're taking those types of -- that type of analysis to our Board to answer those very questions. So -- but we don't have announcements to make. I think those are premature, but the work is without question underway.

Next question comes from the line of Robert Hope with Scotiabank.

So I appreciate the incremental color on 2028 CapEx and rate base on the presentation. Can you provide some incremental color on what you think the natural growth rate of your utilities are in a more steady-state environment? The presentation shows 5% to 6% rate base -- 5% to 6% rate base CAGR to '28. But if we actually take a look at '28 with $1.3 billion of CapEx, you're closer to 8% growth on the rate base. Is this what you view to be a more indicative number for the natural growth of the business?

Yes. Thanks, Robert. I think towards the end of that forecast, I think you have to remember, we've got the ARIS generation project as well as our investment in the transmission and SPP, which we're very excited about. So it's back-end weighted due to that SPP transmission project and really more of the spend on ARIS. So that's what really drives the outsized growth towards the end of that forecast period.

All right. That's helpful. And then as a follow-up there, maybe just in terms of the SPP transmission, can you provide us an update on where you are with the number of those projects? And would it be fair to assume that, that does hit '28, but that will be a multiyear project towards the end of the decade?

One, it's a multiyear project for sure, where the lion's share of the capital really shows up in the back end of the decade. We're going through various regulatory processes associated with SPP and our counterparties in both the transmission and the generation projects internally. We're tracking along with our regulator expectations around how that capital deployment is actually going to flow through rates, and we're shaping our regulatory strategy around aligning recovery with our capital deployment expectations.

And so it's -- as you know already from your history, you know how this works. Given the size of the capital programs, particularly as it relates to the history of Algonquin and the Empire District, it's one of the largest projects we've ever had in the company's history. It's critical for us that we align our CapEx programs with constructive regulatory recovery. And to their credit, the respective states are aware of the significance of us getting that piece right, and we're bringing them along with us on the journey.

Next question comes from the line of Ben Pham with BMO.

You mentioned the progress on operational efficiencies for '25. You mentioned the uptick in ROE. Can you comment then maybe specific for Rod, as you think about the last 12 months, you kind of tracking to what you're expecting coming in? Was there anything you learned along the way in the last 12 months, surprises, areas you can tweak a bit more. So a progress update on 2025 versus when you first started?

Yes. It's a great question, and I've been in constant both assessment and reflection mode. I think the extent to which I had a point of view around bidding the cost curve and the need for us to rightsize the service company in support of our utility objectives, that's really been reinforced the deeper I've gotten into the organization. The need for consistent operational both cadence and standards for customer outcomes for safety and operational performance, the need is great.

To the extent that you have operating entities from, let's say, Bermuda out from an eastward perspective to CalPeco to the West, you have different operating cultures and experiences. The 13 U.S. states in 4 different countries each have different regulatory cultures. But from our vantage point, the need to have a singular focus on safety, customer outcomes and operational excellence required more engagement from leadership, which is why I knew that I needed to be surrounded by folks who understood what excellence looks like so that we could role model the very behavior we're seeking to now reinforce 2, 3, 4 levels down in the company.

And the other piece of the puzzle is the stakeholder engagement where I'm bringing and we are intentionally bringing our stakeholders along with us on the journey. It's really important for us as leaders to show up with our regulators who we're asking to support us on the journey to create different customer outcomes. And that means putting capital to work. More importantly, all of this stuff is happening in an environment where affordability is an absolute headwind regardless of what the actual price to value might actually be. The narrative around affordability is influencing our regulators' receptivity to additional rate recovery.

But they recognize being intellectually honest, that customers can't receive the benefits of economic development and lower cost without efficient investment and timely recovery. And so I'm not surprised by what I've seen because I've been in the industry long enough to where I'm recognizing pattern recognition, but in every different jurisdiction, context matters and it influences how our employees, our regulators, the communities and the customers that we serve, how they receive our value proposition.

My objective then is to provide you as much transparency as our investors in the path ahead and create a predictable pathway of meeting your expectations so that you take the journey with us. But I've been pleasantly surprised by the receptivity of our employees to this pure-play strategy and the standard. And I'm really pleased that I've been able to convince my colleagues around the table to join me on this journey of realizing what I still very much believe is a fantastic future for Algon.

Okay. That's great. And then maybe to turn to some of the other questions highlighted, the 2028 CapEx, the rate base you have there. You now have CFO, Rob in the seat, he's looked at the numbers in more detail. Are you in a position near term or next couple of months to think about your guidance beyond '27 with these additional details? Or is even through 2030 guidance, that may be unrealistic just given that you're still walking and running?

Yes. I think you better believe we're looking at that. But to the extent that I would give guidance beyond, say, a growth CAGR for earnings, I'm grappling with what level of certainty do I have given the multitude of states, regulatory constructs, investment opportunities, portfolio scenarios on top of the earlier questions that were being asked and continue to be asked around domicile.

I don't know that in the next couple of months, I'm going to give you -- be in a position where I'm comfortable giving you a longer view. But from the moment we came on board and now that we've settled and Rob has settled in -- settling in as CFO, we're putting the meat on the bones around the longer view and zeroing in on reducing that cone of uncertainty as we and the Board begin making some decisions around the answer to some of those broader questions, whether it's portfolio, domicile, all of those things influence the tax assumptions for '27. But it's a work in progress, and I don't -- I won't create an expectation of some big reveal, but I need you to know that we're under the hood constantly assessing how far out can we have clarity so that we can project transparently that clarity to you. But we are definitely working on that.

Next question comes from the line of Mark Jarvi with CIBC Capital Markets.

Just in terms of the CapEx ramping through '27 and again through '28, Rob, you've articulated that you don't want the company really spending capital unless you can earn a fair return on it. So just as you stand here today, the confidence that the regulatory improvement there, confidence in recovering that invested capital to get across '27, '28. And just is that sort of the signal then the higher CapEx through '28, just that increasing confidence that the earned ROE continues to track higher beyond 2027?

The short answer is yes. And again, for me, looking at -- and certainly, Rob, as we're shaping out the capital plan and matching the earnings, we're also doing the dance around timing. And what I am trying to get my comfort around, and this kind of goes to my relative visibility into a 5-year plus kind of look is how does the timing play out? I know that I got some big chunky investments in transmission and generation in the next couple or 3 years.

Missouri, I got a 2-year stay-out period, right, where I'll be working to feather in the implementation of the rates that we settled on, while at the same time, knowing I got to put capital to work to advance the larger chunkier projects in transmission and generation, all of which are accretive to the value of the firm. But the work is ongoing for me, how do I bend the cost curve in the near term to create and maintain the margins while still feathering in investment and getting support of our regulators to, in some instances, perhaps accelerate existing mechanisms to keep us whole.

All of those things are part of managing the business. And as we've alluded to, there are some areas where we just have to put more resources to work to provide the outcomes to customers to earn the right for those more efficient recovery mechanisms. But Rob and I are -- along with the executive team, know that our responsibility to you is to map out how we close the gap between our allowed returns and earned. And we are dead set on remaining focused on achieving those outcomes as quickly and as efficiently as we can. I need you to know that that's not -- that's never lost on us.

That makes sense. And then just if I hear you right, would we maybe sort of higher sort of variance potentially on CapEx in '27, '28 just because you're still working through this process? And then I guess, Rob, in terms of the comments around 2027, no equity, just the view in terms of how you fund through 2028?

Yes. So we haven't put out guidance on 2028. And I think to Rod's earlier point, I think as you look across the business and anything we could do there, I think it's just premature. But as we look out, as you look at our balance sheet, as you look at bringing in decisions on the regulatory front, we feel confident in that ability to get through 2027 without an equity issuance.

I think the capital plan is exciting. It is back-end weighted, but not an insignificant part of that is FERC transmission that would earn a return along the way that's compelling. So as we think about those kind of opportunities and closing the gap on ROE, I mean, that's exactly that and getting in on the state side to close the gap on the distribution end. That's what we got to be doing. So I think it's exciting. Those projects, unfortunately, they're towards the back end. But as Rod highlighted, they do continue past 2028. So something to kind of look forward to in the forecast, but also beyond that.

Next question comes from the line of John Mould with TD Cowen.

I'd just like to start with the Missouri rate case and the customer metrics that you need to have in place there for 3 consecutive months. Could you maybe just -- and I appreciate those are metrics that were included in the settlement that you're comfortable with. I'm just wondering if you could give us some color on your progress on those customer metrics and how you're thinking about kind of time to hitting that 3 consecutive month window?

Yes. And I have Amy, our Chief Customer Officer, here. I'll start the question, and I'll look for some body language from Amy to tell me if I'm off on it. And I've shared before that these -- the customer metrics were all around items like accuracy, timeliness of billing, which sounds simple, but for us, represented the outcomes of a series of end-to-end processes that presented opportunities for improvement.

We did not believe those metrics, all of which would be the types of things that any utility would view as reasonable. We believe we have satisfied those metrics, but we are in the process of validating with the commission the sustainability of -- the achievement and sustainability of those metrics so that we could then satisfy for the commission that we met the conditions precedent for rate implementation.

And Amy and her team have literally been working 24/7 to ensure not only the achievement, but the durability of the fixes that created the friction in Missouri. And our expectation is that we're going to answer the bell for the regulator, but also for our customers to meet that -- to meet those time lines and outcomes. So we're on track, but we're in the process of validating that with the commission, and that is a condition precedent of rate implementation per for this element. But think about timeliness, think about accuracy of bills and the durability of the system upgrades that we -- and tweaks that we have made along the way.

Okay. And then just maybe a quick one on the hydro. How should we think about where that sits in the pecking order of potential recycling opportunities? It doesn't impede your pure-play positioning and wouldn't displace an equity need over the next couple of years because you don't need to come to market, but it does represent your only non-reg assets. So how should we think of that relative to the rest of the portfolio and in terms of what you -- the kind of interest or conversations you've had in the market since you identified that?

Yes. And I'm -- it's not going to be exciting to hear because there isn't one thing different than what you've heard before. And I don't -- well, actually, I do want to sound like a broken record because I want us to be consistent, is no longer what we consider to be material, right, just given where the asset sits within the existing portfolio. We are focused on the pure play. And certainly, our openness and willingness to transact with the hydro asset hasn't changed.

We've made the point that it's not a fire sale circumstance where we're looking to jettison it at any cost. And to the extent that we have been -- have received or are in any stage of conversation with counterparties, we wouldn't be commenting on it unless we thought we were at a point where we'd have something to transact on. That being said, it is still very much an asset that we believe is -- would better serve us outside the portfolio, assuming we had reasonable terms. And that's all we're doing is pursuing reasonable terms, and we're sure not going to be distracted by any process that isn't from our vantage point, isn't creating some level of value on our end.

So if Rob has anything to add there by all means, but it's on the dashboard, and we go through the normal processes around considering inbound from interested parties. But again, this will not be a fire sale.

[Operator Instructions]

We'll take our last question from Elias Jossen with JPMorgan.

One more quick one. Can you just discuss your overall view on the California regulatory backdrop, maybe thinking about wildfire risk at CalPeco and whether the team would consider contributing to a wildfire fund there?

How much time you got?

I got all morning.

No, it's -- listen, it's an ongoing effort for us as we're not at the same scale as some of my larger colleagues that operate in the state. And that dynamic influences how I think about the backdrop around wildfire. We're going through a process right now to get our wildfire mitigation plans approved. And it is a complex landscape that we are navigating. We expect to navigate it as is our charge and reduce the risk, both financially, operationally and otherwise to wildfires while managing certainly the cost, but from my vantage point, the recovery mechanisms that -- and access to insurance that reduces risk on our end.

And I am spending a fair amount of time as is my team, both contributing to and tracking that process. But -- and it is a full-time endeavor. I will tell you. We are spending a fair amount of time and resources keeping up, but I am duty bound to reduce the risk of operating in California, and we're engaged with our stakeholders in Washington, D.C., and the state of California from the governor's office to our regulators and other counterparties. We're fully engaged just given the complexity of managing risk there.

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

All right. Just a general thanks for your continued interest and our commitment to be transparent with you has been the undergirding of our disclosures today. And again, thanks for supporting our path to premium. Have a great day.

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

Hello, and welcome to the Algonquin Power & Utilities Corp. Third Quarter 2025 Earnings Conference Call. [Operator Instructions] I'll 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 third quarter 2025 earnings conference call. Joining me on the call today is Rod West, Chief Executive Officer. To accompany today's earnings call, we have a supplemental webcast presentation available on our website at algonquinpower.com. Our financial statements and management discussion and analysis are also available on the website as well on SEDAR+ and EDGAR.

We'd 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 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. On the call this morning, Rod will touch on our leadership and then provide a review of the key highlights and operational updates for the quarter. He'll also provide some commentary regarding the company's portfolio strategy. I will follow with details of our financial results. We will then open the lines for questions. We ask that you kindly restrict your questions to 2, and then requeue if you have any additional questions to allow others the opportunity to participate.

And with that, I'll turn things over to Rod.

Thanks, Brian, and good morning, everyone. Thanks for joining us on the call. Before we move into the quarter results, I'd like to briefly touch on the important leadership update we announced by press release earlier this morning. We're very pleased that Robert Stefani will be joining Algonquin as Chief Financial Officer, effective January 5, 2026. Robert brings to the role an exceptional blend of financial discipline, capital markets expertise and strategic acumen, having served the last 3 years as CFO at Southwest Gas Holdings and 4 years as in the same role and Treasurer of PECO Energy.

We're excited to welcome Rob to the executive leadership team. I expect his capabilities and contribution will help us accelerate our path to becoming a premium pure-play regulated utility. I'd also like to take a moment to thank Brian Chin for stepping into the interim CFO role. I personally appreciate his partnership and steady hand during my early months as CEO, and we look forward to having Brian continue with us as a key member of the finance and leadership team and to assist in the leadership transition.

On would we go. From a financial and operational standpoint, I'm pleased to report that it was a constructive and solid quarter. Our Q3 financial results were strong with double-digit year-over-year percentage increases in adjusted net earnings and adjusted net earnings per share, and our outlooks remain unchanged. On the operational front, we received approval of our EnergyNorth rate case settlement and our CalPeco rate case settlement is pending.

At Empire Electric, we filed a settlement and recognize from commission feedback that we have more work to do to align on specific metrics and milestones to demonstrate improved and predictable customer service. Let me state, we always appreciate hearing from the commission. We are listening and we are committed to reciprocating the transparency. We will be working with the parties to consider how to factor the commission's feedback into our settlement. We have hearings in December on our New England Natural Gas rate case. And in our Litchfield Park case, intervenor testimony is due on January 2026 with hearings scheduled for March of next year.

These 2 cases represent a combined total rate request of $73.6 million of the $326.4 million in total pending rate request. A few additional comments, while we're on the topic of our regulatory proceedings. We understand that any adjustments in rates can be challenging for some customers, and affordability is a concern we take very seriously. Rate requests go through a rigorous regulatory review process designed to support our continued delivery of safe, reliable and cost-effective utility services for our customers. with rates reflecting the very real cost of modernizing infrastructure, meeting safety and reliability standards and improving customer experiences and outcomes.

These are investments made by the company to create sustainable value for all of our stakeholders. We recognize that while necessary, our investments must be balanced with affordability in mind, which is why we are committed to doing our part to continuously find ways to lower our costs and be more efficient in the way in which we work. And finally, before I turn things over to Brian on the results, a few comments on the company's portfolio optimization strategy.

When I became CEO in March, I initiated a series of quantitative and qualitative screens of our portfolio including value accretion, dilution, credit strength and overall strategic fit. I heard the questions that many of you were asking me in my first days, hours and weeks in the role. With the benefit of that initial work now behind me, I am confident that our back to basics pure-play regulated strategy we laid out in June is fundamentally sound.

Continuing our focus on lowering our cost curve, improving operational performance and stakeholder engagement is our best path to creating sustainable value, reducing risk and growing our business. That being said, with a stable balance sheet and robust organic growth prospects within our existing portfolio, we are poised to be opportunistic, should the situation arise. And regarding those opportunistic situations, you should first expect that any potential opportunity will -- must be first value-enhancing to our regulated pure-play strategy, whether it's through EPS accretion and/or risk reduction.

And secondly, you should expect that we would have and articulate clear lines of sight on transactability. And thirdly, it should not be a surprise to you, given the fact that we're turning this company's performance around or aim to. It should not unduly distract management's attention from our central strategy of turning around our financial performance and keeping our promise to you to be steady and predictable. That being said, Brian, I'll turn it over to you for the quarter results.

Thank you, Rod. As Rod stated earlier, it was another positive quarter for our key financial metrics, and our 2025 financial outlook remains unchanged. Third quarter adjusted net earnings from continuing operations were $71.7 million, up approximately 10% from $64.9 million in 2024. Net earnings for the Regulated Services Group were up year-over-year, fueled by growth from the implementation of approved rates across several of the company's gas and water utilities as well as slightly favorable weather compared to the prior year at the Empire Electric system.

Lower operating and interest expenses also contributed positively to the quarter with gains partially offset by higher income tax expense due to higher earnings before tax. Our expectation of an effective tax rate for the year in the mid-to-low 20% range has not changed. Net earnings for the Hydro Group were essentially flat for the quarter. And for the Corporate Group, a decrease of $14.7 million was primarily related to the removal of dividends related to the company's investment in Atlantica, which was sold in the fourth quarter of 2024, partially offset by lower interest expense of $8.9 million.

Moving to our EPS walk. Q3 adjusted net earnings per share were $0.09, up 13% from last year's Q3 2024 adjusted net earnings per share of $0.08. Positive drivers for the quarter included $0.02 driven by stronger operational performance from approved rate adjustments and favorable weather compared to last year, another $0.01 related to lower operating expenses and a $0.01 onetime gain from the EnergyNorth depreciation deferral. We were down $0.01 due to the inclusion of a benefit in third quarter 2024 of a New York Water retroactive payment that did not repeat in 2025. Additionally, we benefited by $0.02 from lower interest expense from deleveraging, which was more than offset by the elimination of Atlantica dividends of $0.03 and then finally, a negative $0.01 of unfavorable taxes.

And now back to Rod for his closing remarks.

Thanks, Brian. And to close, this was another quarter of quiet but steady, thoughtful execution. As we continue our way forward, our focus remains on creating sustainable long-term value for our stakeholders and continuing to effectively serve our customers and communities. We're looking forward to seeing many of you at EEI in the coming days. Thanks again for your time and continued support, and we are happy to take your questions. Back to you, operator.

[Operator Instructions] Your first question comes from the line of Baltej Sidhu from National Bank of Canada.

Congratulations on the strong quarter. Just looking at the OpEx improvement, could you share any color as to what were the main drivers of this and if it's sustainable? Looking in the MD&A, you had highlighted favorable timing as a factor.

Yes. Thanks, Baltej. So as you know, we have been continuing to work on improving our cost discipline. You'll notice that we have taken cost-cutting measures as part of our ongoing strategy of improving value to our customers and stakeholders. We do say in the MD&A, and I'm glad you pointed it out, that we do expect a little bit of reversal on OpEx timing to happen in Q4, and that's part of the reason why our [indiscernible] remains unchanged.

In terms of specific drivers, it's across the board. I wouldn't point to any one particular thing, Baltej. It's a myriad of improvements in efficiency and discipline across the board. So do be prepared for a little bit of reversal of that in Q4. But broadly speaking, we're pleased with the trajectory that we've been making.

Great. And just another one for me. If you can provide some color on, if there's been any incremental conversations with data center players and/or if you expect any large-sized projects that would -- or could meaningfully contribute to your system or rate base?

Yes. We wouldn't be talking about any conversations with customers unless they were aligned with us disclosing those conversations. I will say that our focus is on creating the conditions precedent to serving a multitude of customers, especially increasing transmission capacity in Southern Missouri, which we've already disclosed that we intend to do and certainly looking at stabilizing our generation portfolio in the region as well. And that's about all we'll say.

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

Just a quick follow-up on the operating costs. So I think out of the $9 million of -- sorry, out of the $11 million of cost reductions we saw in Q3, $9 million was due to timing. So are -- so Brian, should we expect to see the $9 million all get pushed into Q4?

Nelson, I think that the timing aspect for Q4 is going to be an item that does crop up. Is it going to come out exactly at $9 million? We'll see what happens as we continue to progress through Q4, but the order of magnitude, I think, is correct.

Okay. And then also in the quarter, I think restructuring costs were about $9.6 million for the quarter and I think $22 million year-to-date. Can you just talk about when you expect to see restructuring costs gradually roll off?

What I'd say is we're in the early innings of our restructuring efforts still. Obviously, given the history of the company, we believe we have a lot of opportunities to provide value across our cost curve. And so stay tuned for more, but early innings is how we would describe it here.

Okay. So this could be a multiyear process?

Early innings, Nelson, is how I would phrase it.

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

As part of the portfolio optimization review, do you take a look at the domicile of the company just given the fact that the majority is now in the U.S.

No, no question about it. I got those questions, as you know, and you guys were part of the queue from March on about the domicile question. It is an active conversation and consideration, as we think about providing sustainable value. The question for us, recognizing that we would need to get the support of our existing shareholder base is how does that play out.

And while we have not made any determinations, I owe it to you and to my Board to do the due diligence to answer those questions. That work and that analysis is in flight. And that's all I can say. I do expect that at some point, we'll be in a position to opine as to whether it's something we pursue or not.

All right. Appreciate that. And then maybe just moving over to the regulatory front. Are the settlements at the various utilities kind of better or worse than you were expecting in your financial update in June? And more broadly, on the next go around for these regulatory filings, how would you as the new management team do things differently?

Well, I'll simply say in our outlook that we laid out for you in June, we made certain assumptions around the reasonableness of our regulatory outcomes in the litany of rate cases. And I'll simply say that, as I alluded to in my opening remarks, everything is very much in flight. So I won't comment on whether or not where we are in our various settlement postures, is above or below expectations, but our expectation around reasonable outcomes remains as reflected in our outlook.

In terms of what we are doing differently and what our existing, and certainly with Rob's arrival, our future management team would be doing differently, we'd be spending more time as we've sought to accelerate here, engage with our stakeholders long before we put pin the paper on a regulatory filing. And you've heard me say this before, but it bears repeating that our objective is that by the time we actually make a filing for any rate adjustment mechanism tweak or legislative change that we have reduced the number of contested issues to as few as humanly possible before we make the filing to give our regulators a lot better air cover in both assessing and deciding on regulatory outcomes.

And that's just more work beforehand that really efficient and candidly, premium utilities, that's what they do, and we expect to mirror the attributes of those highly valued pure-play utilities.

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

Just on the activities at Empire, you had a nonunanimous settlement, OPC hasn't signed off yet. Are you in ability to negotiate with them and do a revised sort of more fulsome settlement in parallel to the public hearings that were ongoing?

We're going to always be open to resolving disputes between every -- any and every stakeholder. I'm not singling out OPC, as I don't want to get ahead of any of the processes in Missouri. But the short answer is our objective is to get the support of the commission by bringing as many of the stakeholders along and resolving disputes. So OPC is an important stakeholder, but it's the commission at the end of the day who will call balls and strikes, and we're going to do our best to bring as many folks along as we can.

I'm also curious how you guys think about updating the market in terms of the journey on the cost cutting and navigating these rate cases. If you had sort of final decisions on CalPeco and Empire at some point in earlier 2026 and you've seen some progress on the cost reductions, would there be a view to update potentially '26 and '27 guidance at some point early or sort of midyear 2026?

Yes, it's a great question. And I think it also aligns as I look out at the calendar with the arrival of our new CFO in January. I certainly would want -- if all things remain equal, not just with the timing of the various rate case developments, I'd want my new CFO to come in and weigh in because he, along with me, would own the path forward. So an update if it was -- if we thought that there was any need for -- to disclose a material change in our outlooks.

I'd give him a little bit of grace in the early part of next year, but our foundation is sound. And my short answer is I'd always update if I thought there was a material change, but the arrival of the CFO gives us a chance to reflect and have fresh eyes on it as well. So the -- your assumptions on timing, I think, are pretty sound.

Okay. Makes sense. And then just, Brian, I know you mentioned the reversal in Q4 of some operating costs. But just as it stands today now, would you be tracking above the 2025 guidance on EPS?

No, our guidance is our guidance. So we're not going to make any comment about how we're thinking about things relative to that guidance.

Your final question comes from the line of John Mould from TD Cowen.

Maybe just going back to the portfolio optimization aspect. I'm just wondering if you can elaborate a little bit on the risk reduction commentary. Is that chiefly a comment around utility or state-specific regulatory risk? Or are there other aspects of the portfolio optimization process where you see risk reduction opportunities as enhanced potential...

Great question. The short answer is all of the above. It's risk period. So anything that would reflect a risk to our ability to achieve steady, predictable outcomes for the long term would be a consideration. So I don't mean to point to any specific one. But in the same way that I -- that we not doing the math on whether a specific transaction would be EPS accretive, the remainder of the considerations that would drive portfolio assessment, value assessment would be just how we articulate, identify and mitigate risk. So I appreciate the opportunity to be explicit on that. It's the generic enterprise risk to value.

Okay. And then maybe just one more on your customer and billing and data systems. I appreciate the challenges that we've talked about on previous calls, are pretty backward looking at this point. But can you just give us a sense of how that system is operating broadly across your utility footprint at this point?

Yes. I am -- in the midst of all the noise from the customer disruptions with the billing issues we've had, I'm encouraged with the progress that we have made. When we brought Amy Walt on as Chief Customer Officer, it was her experience around SAP deployment and end-to-end customer systems that gave us confidence that there was a path forward for us to create different outcomes for customers.

We're well on our way to doing that, which is why I was explicit and intentional in recognizing the guidance and feedback we got from Missouri, who themselves want to see better customer outcomes and are really focusing us on the metrics and milestones that not to be tried, the show-me state wants us to show them how we are improving the customer outcomes, which we know we are, but how do we know that we're doing it in a way that is sustainable.

And I am really encouraged with the progress we're making internally and the fact that we have an opportunity in Missouri to show how the improvements we made are going to be sustainable. So we're making progress. We got a lot of work to do, but we are making progress.

There are no further questions at this time. I'd like to turn the call over to Mr. Rod West. Please go ahead.

Well, everyone, we are days away from EEI. So I thank you for your time and attention to our story, and we look forward to double-clicking face-to-face. Safe travels to everyone. Have a great weekend.

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