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 two 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 two, then follow up with us after the call if you have any additional questions, to allow others the opportunity to participate. 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 premiere. As I've 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, the 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 forecasts 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're pleased to achieve progress on or conclusions to several of our rate cases. The Missouri Public Service Commission determined on July 15th 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 WEMA 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 two 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 projects over the next few years. 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 six 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.

Redomiciling to the US 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. Over time, we believe it would strengthen our financial profile, broaden our access to capital, and create a path to inclusion in certain US equity indices and funds.

From a structural standpoint, we expect to complete the redomicile to Delaware through a court-approved 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 seven and eight, 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 costs 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 15th order approved implementation of $97 million in annualized revenue adjustments, effective on August 3rd. 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 one.

The settlement included a black box stipulation for authorized equity ratios and ROE. Out west in 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 WEMA and similar proceeding 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 a 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 a proposed implementation date of spring of next year. EnergyNorth 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 nine, I'll add a few comments regarding our evolving regulatory and legislative landscape. On the operations front, on June 17th, 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. 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 non-recurring favorable items from the second quarter of 2025.

In the second quarter, we also reported a $17.2 million writedown of a regulatory asset related to the previously discussed proposed decision in our California WEMA proceeding. The impact of the proposed decision, which as Rod 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 non-recurring 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 0.4 cents 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 at our Apple Valley and Park Water utilities in California inclusive of an unfavorable retroactive adjustment to July 2025 of $3.1 million.

Interest expense grew by $9.3 million related to a new debt issuance at Liberty Utilities Co. 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 17 cents per share compared to 19 cents per share in the first half of 2025. Although a decline year-over-year, I'd like to highlight that 2025 experienced $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 in 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 rates 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. Lastly, interest expense was unfavorable, as previously discussed, due to a new financing at Liberty Utilities Co., 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 Co. through a private placement offering of senior unsecured notes and used the proceeds from the offering to pay down $1.15 billion aggregate principal amount of notes at Algonquin Power & Utilities Corp.

that matured on June 15th. At Algonquin, we continue to be rated BBB by S&P and Fitch, and at Liberty Utilities Co.

continued 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.

Thanks, 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 reached settlement 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 WEMA and Litchfield Park. We continue to work diligently on our rate cases at New York Water, Empire Arkansas, EnergyNorth, and in Arizona.

On the operations front, we've continued to improve our customer performance metrics and strengthened our standing with our regulators and customers, while obtaining approval for CWIP treatment for our Asbury 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 premiere. Thanks for your time this morning, and with that, I'll turn it back to the Operator for questions.

Thanks. Morning, everyone.

Thanks for the update on the US 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 redomicile to the US?

Yeah.

Rob, go ahead.

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 a 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. We pay, subject to continued board approval, $200 million of dividends about per year, so that's 5% on the $200 million.

Then the other tax that the redomicile would eliminate was the BEAT tax. That tax is a tax on the cash funds that are sent up to Algonquin to service the debt at the holding company level.

That's about a 10% tax rate on the funds that we send up to service that debt. As far as the effective tax rate, obviously, that'll be determined by a number of factors, but those are two instances of savings that we would point to that we would expect to realize through the redomicile to the US.

Rob, at a prior call, you talked about clawing 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?

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 a approval to proceed in the first half of 2027.

As you think about ramping up to that, you'd need to consider the timing there.

Understood. 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 rate

application? 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've 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 matter. 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 applications?

Always. It's not what it's what you can prove.

If you've had a rough experience, whether it was 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've put the work in to be able to do just that. We're looking forward to making the case, and it's been ongoing.

Sounds good. Thanks for your time this morning.

Thanks.

Hey, good morning, everyone. 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, court, or legal milestones we should be watching for that could influence the timing or ultimate economics of the redomicile?

As mentioned in my prior comment, we'll 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.

Great. Thanks, Rob.

I know you touched on the dividend and the debt tax implications of flowing the capital through the border to Canada. I know the verbiage in the MD&A was significant costs and taxes, could you directionally frame the magnitude of what could be expected in terms of those two factors?

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 to 2.5, maybe slightly higher, cents of impact on a run-rate basis. 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.

Great. Thank you.

I'll flip the line.

A question on tax on the redom. Can we dive a little bit deeper into slide 20?

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. Rather than the ongoing tax savings, can you speak to the potential one-time exit tax liability, both deferred and current, that you could incur?

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

Both would be helpful. Okay.

The way the FIRPTA tax is calculated, is effectively we'd go back and look at non-US shareholders that held the shares in the prior 10 years prior to the redomicile. We'd 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.

We've done that math. We're confirming methodology with the Internal Revenue Service, which is the purpose of the private letter ruling.

We continue to have discussions with them. We and our advisors have worked through those calculations, and given the expected value creation opportunity of the tax savings relative to those one-time costs, we believe this is a beneficial move.

Then do you have an estimate of the one-time 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. Again, relative to the range of outcomes, we believe that this is a value-accretive transaction, and expect, relative to those one-time transaction costs that the recurring benefit outweighs that one-time transaction cost.

All right. Thank you.

Then maybe just going back to the regulatory approvals. Can you just confirm which states you think will need commission approval for the transaction and do you have an expected timelines or past precedents you can help us with there?

Hey, 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.

Again, these are filings. There'll be more there in the coming weeks.

All right. Thank you.

As you see them get filed. The

Hi. Good morning.

Thanks for taking my questions. 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 11%. Obviously, you said 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.

I think you have to also consider rate case timing and implementation. Obviously, we'll begin to get the Missouri rates in August.

We've gotten the California rates in, and we'll continue to benefit from those. Then all the rate implementation associated with some of the updates that Rod made, and so 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. Thank you.

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 does your pipeline there and when could we potentially expect an announcement?

It's Rod, and I very much appreciate the question. The only thing I can say, 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 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 load tariff is an enabling aspect of our ability to further any conversations we might have with potential customers. 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.

I know that might be frustrating to hear, 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. I do appreciate the question, though.

Great. Thanks for taking my question.

Hey, good morning, everyone. Maybe just sticking with Missouri, I know that you guys have had a lot of activity in this state and you just talked about not being able to provide much clarity 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 timeline or quantifying uplift at this time.

I know it's an ongoing process, but just broader color would be great.

I definitely excited about a couple aspects. I think just the Asbury project in particular, that project being eligible for CWIP treatment, and helping kind of stem some of the regulatory lag that you would otherwise see in part.

Then on the transmission filing, that will really apply mainly to the kind of future of transmission development in SPP. Obviously, that's a large project for us that extends over the next several years.

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. That future test period will also help eliminate some of the lag component for us on that future development work.

Got it. 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 2 cents impact.

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 2 cents 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?

As far as the tax savings and the expected EPS impact of that kind of 2 to 3 cents, if the 2027 impact would be determined based on kind of when in the year we're able to achieve the approval. 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, but as far as the kind of separate issue of index inclusion, based on the work that we've done with our advisors, the expectations are there would be some positive fund flow associated with inclusion in at least one of the indexes in the US. I think one of your peers has also done some work around that.

I think that's all we can say at this point.

All right. Appreciate the color.

Hi, thanks. Good morning.

You mentioned some of the tax benefits from the redomicile pushing beyond the guidance. Haven't extended the guidance.

I'm just curious more specific in regard to you had that three-year through '27. How should we think about when you do extend your guidance, I'm presuming it's not going to be until you get approval of the redomicile first half, keep them separate?

Then do you think three-year CAGR through end of decade is reasonable for you given the regulatory timeline or is it maybe something lesser and more than that?

I think we've talked a little bit about this. I think that moving forward, when we do move to, and 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 year guidance and then the long-term growth rate.

Wouldn't say right now how far out we'll 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 into those projections, we'll address at that point in time.

Okay. Could you also provide just on the OpEx side of things, you had a guidance around OpEx trending lower as a percentage of the growing revenue base.

Could you perhaps update on progress on that? Where are we right now?

Have you surfaced the easy pickings? Has it been some challenges along the way on some of these areas?

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.

Okay. All right.

Thank you very much.

Thanks.

Hi. Good morning, everybody.

I'd like to go back to the large load opportunity in Missouri, not focusing on any specific customer discussions, but more just about the ability in your systems 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 room you've got.

Yeah. Go ahead.

You had a second part to your question? Go ahead.

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.

Again, and and we've been around we've been around in in conversations before, and we're not seeking, to obfuscate, I think the the question. The answer to that question it would be premature because disclosing it would then signal the the size, the scale of any potential customer.

I commit, and we commit to you, the moment we're in a position, remember that we have multiple stakeholders who are who are part of this conversation, including the state of Missouri, the Commission, as well as any potential customers, in shaping in a a integrated resource plan. It's premature for us to signal a size before we're we're in a have a position to, to actually match that integrated resource plan with with expected loads.

All of those things are to be determined. What we're framing up with the large load tariff is enabling a range of outcomes that would then allow us to get further along analytically, around just what scale of, generation and 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 load tariff filings and in furtherance of our efforts to bring economic development to our service territory.

I guess I'll I'm comfortable signaling internally that we're putting more resources to bear in anticipation of of us having greater impact in in the areas that we're we're seeking the to file a large load tariff. 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. Thank you.

All right. Then if there are no more questions, I will simply say thank you for your continued interest, support, and feedback.

With that, we will end the call.