Ladies and gentlemen thank you for standing by and welcome to the Algonquin Power & Utilities Corp. 2020 Fourth Quarter and Full-Year Earnings Webcast and Conference Call. At this time all participants are in a listen-only mode. After the speaker’s presentation there will be a question-and-answer session. I would now like to hand the conference over to our speaker today, Amelia Tsang, Vice President, Investor Relations. Thank you. Please go ahead.

Good morning, everyone. Thanks for joining us this morning for our 2020 fourth quarter and year-end earnings conference call. My name is Amelia Tsang and I'm the Vice President of Investor Relations at Algonquin Power & Utilities. Presenting on the call today are Arun Banskota, our President and Chief Executive Officer; Arthur Kacprzak, our Chief Financial Officer. Also joining us this morning for the question-and-answer part of the call will be Jeff Norman, our Chief Development Officer; and Johnny Johnston, our Chief Operating Officer. To accompany our earnings call today, we have a supplemental webcast presentation available on our website algonquinpowerandutilities.com. Our financial statements and management discussion and analysis are also available on the website, as well as on SEDAR and EDGAR. Before continuing the call, we would like to remind you that our discussion during the call will include certain forward-looking information, including but not limited to our expectations regarding future earnings and capital expenditures, and the expected impact and outcomes of the recent severe winter storms in Texas and the Central U.S. At the end of the call, I will read a notice regarding both forward-looking information and non-GAAP financial measures. 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 our call this morning, Arun will provide an overview of our Q4 and full-year 2020 performance. Arthur will follow with the financial results, and then Arun will conclude with an update on our strategic plans for the business. We will then open the lines for questions. I ask that you restrict your questions to two and then re-queue, if you have any additional questions to allow others the opportunity to participate. And with that, I’ll turn it over to Arun.

Thank you, Amelia, and a very good morning to those who have been able to join us on this call and online. Given that this is our year-end earnings call, I want to provide some highlights and speak to performance, both financial and operational for 2020. Firstly on financials, I'm pleased to report steady year-over-year growth in our key financial metrics. 2020 adjusted EBITDA of $869.5 million increased 4% year-over-year, and our 2020 adjusted net earnings per share of $0.64 compares to $0.63 reported last year. There were three particular events, COVID, weather in the central region, and delayed closing of BELCO that impacted our results. Despite these, management was able to pull a number of levers, including cost savings to continue our growth trajectory. We exited the year with $13.2 billion in assets, a 21% increase over last year. Secondly, in terms of shareholder value creation, we've continued to generate consistent outstanding returns, as proven by our record on delivering total shareholder returns.

Thank you Arun and good morning everyone. As Arun mentioned earlier, in 2020 Algonquin began to show its ability to accretively grow earnings through a stable regulated services and long-term contracted renewal power businesses. Our fourth quarter 2020 consolidated adjusted EBITDA was 253.1 million, which is approximately 10% from the 230.4 million we reported in the previous year. The Regulated Services Group delivered 161.8 million in operating profit in the current quarter, which compares to 159.4 million in the same quarter last year. The increases primarily reflect the implementation of new rates, as a contribution from ESSAL and BELCO, which both flows in the quarter. This was partially offset by consumption, primarily under central utilities due to warmer than usual weather. The Renewable Energy Group reported fourth quarter divisional operating profit of 102.9 million, which compares to 85.9 million in the same quarter last year. The increase represents generally higher production across our renewable fleet during the quarter. Our Q4 adjusted net earnings per share came in at $0.21, which compares to $0.20 reported last year. Our results were positively impacted by cost savings implemented during the quarter, a solid performance from our generation facilities, and a contribution of ESSAL and the BELCO acquisitions. So, we’re partially offset by the unfavorable weather in the central region as mentioned earlier. For the full-year, adjusted net EPS came in at $0.64 and compares to $0.63 recorded in the prior year. The 2020 results included a full-year contribution from New Brunswick Gas and the St. Lawrence Gas Systems, which were reported late last year, as well as the implementation of new rates on our and Granite State Electric Distribution Systems. The results were negatively impacted by decreased consumption resulting from the COVID-19 pandemic, as well as significantly unfavorable weather experienced by the central…

Thank you, Arthur. Before we close out our prepared comments this morning, I want to give an update on our growth initiatives and capital plan. At our December Investor Day, we updated our five-year capital investment program, which projects $9.4 billion from 2021 through the end of 2025, to be spread across our two business groups, with the emphasis on regulated services. We have identified projects that make up the entire $9.4 billion with most of them under construction, or in advanced development. This core $9.4 billion does not include any further M&A beyond previously announced transactions or any success from our 3.4 gigawatt pipeline of Greenfield opportunities. Over the last year, we have bolstered our internal resources and software tooling to focus even more on Greenfield development opportunities that are originated by us. For many of these opportunities, we already have side control and are in the interconnection queue, and we will work to bring this into construction in and beyond. Before we open the lines for the question-and-answer period, we remain very excited about Algonquin’s businesses and prospects. With society and economies working hard to minimize carbon emissions and many countries coalescing around a net zero carbon by 2050 goal, Algonquin regulated and renewables businesses are well-positioned to contribute to and benefit from this decarbonisation transition. Our three strategic pillars of operational excellence, growth, and sustainability will be a key foundation as you continue to build the business and bring long-term value to our shareholders. We remain well-positioned to continue to execute on our growth strategies, while pursuing our sustainability goals guided by maximizing operational excellence on behalf of our stakeholders, including investors, employees, and customers. With that, I will turn the call over to the operator for any questions from those on the line.

Your first question comes from the line of Rupert Merer from National Bank. Your line is open.

Good morning, everyone.

Good morning, Rupert.

So, if I could start with the Texas weather then, you discussed the incremental commodity costs of the regulated utility business in the Midwest, what's the scale of that incremental cost? And can you talk us through how this will manifest itself in the financial results? Do you book higher costs in revenues here; are we going to see an accrual on receivables? Can you just tell us how we should be looking at that please?

Sure, sure. So the total cost is expected to be in the neighborhood of around just over $200 million. And that's primarily all of those costs are expected to be passed through to our customers although the timing over the passthrough is obviously subject to discussions with our regulators. We do expect to set up regulatory assets with respect to those commodity costs.

Okay, all right, very good. Thank you and then looking at the Texas event and as well as all of the growth you have on top right now. Can you give us some thoughts on the balance sheet strength today, your liquidity position and capital needs for the remainder of the year to fund your construction?

Sure Rupert. So, we have a very strong liquidity position. As you know, we've got regular, about 1.5 billion of committed credit facilities. And we've also, call it beefed up our liquidity position with another 1.6 billion of term facility. So, right now we're sitting at about 2.8 billion of available liquidity to us, which certainly is sufficient to fund our ongoing capital plans. But obviously, we plan to also be in the capital markets this year raising some funding.

Very good. I'll leave it there. Thank you.

Thank you, Rupert.

Your next question comes from the line of Sean Stewart from TD Securities. Your line is open.

Thank you. Good morning. Couple of questions. I see that subsequent to year-end you sold a 32% stake of a sell down, pretty shortly after acquiring it. Can you give us some of the rationale, especially as it looks like you sold it at a little bit of a discount to the initial purchase price?

Sure, Sean, good morning. So look, while we are very, very comfortable with Chile, as a country risk and a business risk, this was our first major investment in Chile. And if you look at the structure of ESSAL, it had a strong local partner initially. And through the tendering process, they tendered their shares. We always believed that as a first transaction, you know strategically, it was very important for us to have a good strong local partner, who could help us with all kinds of things locally. And so, was a very natural choice. We have known them for a while and they not only know the local energy and water sector very well, they in fact, also own 50% of another water utility in Chile. So they are a very, very natural partner for us. So, it was really a strategy that we had in place long before the final acquisition of ESSAL took place. And no, it was not at a discount.

Okay. Looked just like a modest one in our math, but maybe I'll follow up on that. Second question, Page 22 of the MD&A goes through some of the variances in the quarterly results for the regulated segment. There was another bucket of 9.9 million that goes through several items, I’m wondering, Arthur or Arun, if you can go through some of those elements specifically and help us clarify that figure and the impact on the results?

Sure Sean. I'll try to take a stab at that. And it really is a bunch of items in there. One of the things as we obviously – as you're aware of contracted services at some of our utilities that revenue tends to be a little bit more chunky so just a matter of, I guess timing to the last year of that revenue and differing to facility as an example. So, we also have our ESSAL utility that we actually ended up recognizing some interest in last year, but that generally occurred this year, as it is a matter of a comparative. We also have just lower AFUDC capitalization this year compared to last year. So, it’s a bunch of things all put together.

Okay. Thanks for that, Arthur. That's all I have for now. Thank you.

Thank you, Sean.

Your next question comes from the line of Julien Dumoulin-Smith from Bank of America. Your line is open.

Hey, good morning team. Thanks for the time and the opportunity.

Good morning, Julien.

Hey, thank you so much. Listen, a couple different questions for you guys, maybe to start higher level. Can you elaborate a little bit more on ITC/PTC extension here? Just how are you thinking about the impact to your business? I mean, obviously, you guys have this accelerating opportunity, number of different counterparties Chevron for instance; just can you elaborate a little bit on how you think about the cadence of the opportunity here?

Hey Julien, it’s Jeff. And I just want to – if you can reiterate the very beginning of that question on the ITC/PTC opportunity, just to make sure that I…

This would be extensions here. I mean, does this provide a greater sort of five-year view on what you think you can do? I know this is out of cycle with a typical December updates, but I'm just curious given that we've got these extensions of late?

Yeah, well, there's a couple of things. We are very keen about the Biden administration and where they're going to take things and what extensions will go above and beyond what we've already seen. And obviously, the ability to improve some of the economics within our 9.4 billion pipeline to the extent that they're able to qualify for that incremental PTC/ITC. The most significant is the ITC extension, allowing projects to come online a little bit later on the solar side. And so, we do see upside in the 9.4 billion pipeline on the timing of some of those projects and the ability to bring more projects, which aren't yet secured. But obviously, we're always looking at the ability to bring more projects to take advantage of the full ITC.

Also, to add to that, Julien, where it should it really help us is on our 3,400 megawatt Greenfield pipeline. With the extension of the ITCs and the PTCs, obviously, the economics on those projects will be even better than what we had projected before. And again, as a reminder, that 3,400 megawatt Greenfield pipeline is above and beyond our $9.4 billion five-year capital plan.

Yeah, understood. And then if I can go back into some of the details here, I just want to understand the New York American Water piece of this, just can you talk about the confidence in getting that closed here. I mean, I know that there's lots of talk in the States, difficult to discern exactly what's going to transpire there. And on the Texas front, just force majeure, anything specific we should be watching there? And what you're assuming in that ? I just want to make sure I understand what the assumes on outcomes there? Thank you.

Sure. Julien, let me start with the New York American Water, right. So, as you know, there's a lot that that has been very in the public realm. And I'm not going to repeat that, but our conversations and discussions with the commission has continued and the hearings are set for mid-May. As you know, our Governor Cuomo has come out with this bill. And one of the elements of that bill is to look at potential municipalization. We obviously welcome that opportunity to have a public dialogue around the benefits and not of municipalization versus you know private participation. And we are still confident that that acquisition will close in 2021. Just as context, I should point out, you know, we did close St. Lawrence Gas in New York State, and that was an approximately 18 month process. So, you know, because of our presence in 16 different jurisdictions, we have a pretty good view of how long different regulatory processes take. And so, we believe that we'll be in that, kind of timeframe. Your second question was I believe around Texas and force majeure. Our announcement was between a $45 million to $55 million impact before any potential mitigation, right. And so, we have already issued force majeure notice, I believe, we obviously remain confident in the provisions under which we issued that. Obviously, there's a, because it could get into a dispute or litigation situation. I don't want to comment more on that. The other potential mitigation is, as you're well aware, Julien, there's a lot of discussion going on at the Texas Legislature, at the PUC there around the merits and not above the $9,000 a megawatt hour pricing and whether there's a possibility of part or all of that being rescinded. We see that as another potential mitigation, because by and large, from every commentary out there, there was a large scale market failure. So, those are some of those mitigations we're thinking about, but that is not included in the $45 million to $55 million number we gave in our release.

Thank you so much. I really appreciate it.

Thanks Julien.

Your next question comes from the line of David Quezada from Raymond James. Your line is open.

Thank you. Good morning, everyone. Just my first question here, just as it relates to your wind build-out in the Midwest, you know, as that customer savings plan, I guess completes over the next year or so here. I'm wondering what your thoughts are on the potential for future renewables and the rate base there in the Midwest? And I guess maybe even how storage could play a role there as well?

Hey, David, good morning. So, let me answer the first part of the question, and I may turn that over. So, in terms of the 600 megawatt wind projects, in fact, one of them is already online, North Fork, and the two others Neosho and Kings Point. They're scheduled to come online, in fact, by the end of this month. So they're clearly very, very advanced in terms of being in operations. We do believe that there's more opportunities out there, in terms of substituting wind or solar for other forms of thermal generation, but I'll turn it over for more context.

Yeah. Good morning. So, Johnny Johnston. So, as far as our ongoing review of our IRP plans as part of our central organization, we're always looking ahead at what opportunities we have to make sure that we've got the right generation to meet our load. Within our plans at the moment, we have another 50 megawatts of solar to be put into place and then 20 megawatts of most of solar and storage, more of a community type basis. And then we continue to review that analysis each year, as we go forward. So, clearly we've still got a number of other aging facilities that are part of our generation through that, and as those opportunities present themselves will be put in the middle.

And David, as you know, I mean greening the fleet is a very key lever that we have, where we believe we have unique expertise, especially with our experience around tax equity, as you know, in as well, we've added a number of, you know, solar generation into that database. We are excited about potential opportunities in Bermuda as well, because that certainly is all thermal generation. So, this is something that we are continuously evaluating. And again, you’ll obviously continue to hear more from us on our Greenfield initiative.

That's great color. Thank you very much. Maybe just one more from me, I guess in Europe, you've started to look like unearth some opportunities in Spain, and then I guess, a few renewable opportunities in Colombia as well. Just curious how you see the outlook in the development of projects progressing through Aegis? Just any comments that you could provide there on the momentum you're seeing in those markets?

Sure. So, I do want to give context first, right. So, you know, we are by and large, a North American Energy and Water company, right. And, you know, some years ago, when we acquired our position in Atlantica, we also felt the need for a development entity that would go after non-regulated international business. So, the scope of Aegis is just that, you know, non-regulated and international. And the two markets that we have been targeting are Spain and Colombia, because we believe that from a country risk, business risk, potential opportunities, and our own positioning those markets, we believe that we have advantages in those markets. As we saw, I mean, we have in fact, dropped down couple of those assets in Colombia already into Atlantica. We are progressing well on a number of those solar opportunities in Spain as well. And we'll update you as we make more progress. The other thing I do want to remind you is that none of those projects are part of our $9.4 billion capital plan. So, they will be above and beyond.

Perfect. I appreciate that. Thank you. I'll get back in the queue.

Thank you, David.

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

Good morning, everyone. Two follow-up questions for me. The first is on the 2021 capital. Look the renewable energy at 1.4, 1.75, you know, is pretty robust there and over half of – around half of the five-year total spend, you know is that just, kind of timing of all the investments or are you baking in some of your we'll call it lower probability or earlier life stage investments there or is that really just, kind of, you know, cleaning up the rest of Maverick, Sugar Creek, and , among others?

Hey Rob. Good morning. So, let me try and answer your question, right. So when we were at Investor Day, and we showed you that $9.4 billion capital plan, we also showed that really a large portion of that is what do we do report to that already locked and loaded, because, as you know, in 2020, that was our largest construction year in our history. We have around 1,600 megawatts of wind and solar projects that are coming into operation. So, basically, when you look at it that way, right, I mean, Sugar Creek, for example, that has now recently come online. Our acquisition of our Texas Coastal Wind Facility, which is a fairly – which is, in fact, the largest acquisition on our renewable side. That happened earlier this year. Our North Fork Ridge came online and we have some large projects that are also coming online, fairly shortly, including on the regulator side, you got Kings Point and Neosho. And then on the renewable side, you've got Maverick, and out of this are also coming online. So, it's just that a large portion of that 1,600 megawatt construction is really coming online in the first quarter, and in the second quarter. And so that's what accounts for the, you know, a lot a portion of that capital investment plan happening early in 2021.

All right. That's great color. Great to hear that. And then this is a follow-up, you know, at the Investor Day, you did say that 2021, you could be looking at mandatory equity instruments to fund the capital plan. Is that still the case and the Texas will weigh on your credit metrics a little bit here, but should we assume that, you know, the equity in the plan that you outlined in December is pretty front-end loaded here?

Hi Rob it’s Arthur. I think you can assume what we laid out at Investor Day folds with respect to our funding plans. And to your question about mandatory, yes, it's a product that we still are looking at. And I mean, as we think about, you know we're probably in a the predominance of over financing would be, probably through mandatory, but again, we are still evaluating.

Excellent. Thank you.

Thank you, Rob.

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

Thanks. Good morning, everyone. last question, Arthur, for you. And just in terms of some of that pressure from the higher commodity costs, and the Texas losses, potentially, have you guys spoken to the in terms of how they would look through this or deal with this in terms of any and does that push you to maybe re-engage on the ATM earlier now?

Yeah, good morning, Mark. Yeah, no, we obviously have spoken to the rating agencies, and it's still early days, as you know, we're not the only company that's obviously going through this. I think the rating agencies are still evaluating, obviously, this is transitionary, but it does weigh down on the credit metrics from the top line. So, I mean we view our capital plan more on a long-term basis anyway. So, I wouldn't look at this as necessarily impacting our significantly.

Okay. And then, in the fourth quarter the O&M costs on utilities, you've had a real material step-up year-over-year and also from the prior quarter, I appreciate ESSAL and BELCO come into the . Can you maybe break it down in terms of how much of the higher O&M comes from the new assets that have been added in this quarter and then other factors that might have played into the higher OpEx for the utility segment?

Yeah, I don't have the exact breakdown for you. But I would say majority of it is due to the new acquisition. I mean, I can just give maybe, anecdotally, when you think about seasonality, or utility like BELCO will earn about 70% of the earnings will come in the late spring to call it early fall months, right. So, it is really seasonally shaped here. And, you know from that perspective you may for margins.

So, you’re saying that maybe top line revenues for BELCO are a little lower, but the fixed operating costs are fairly flat across the quarters?

Correct.

Yeah. Okay. I'll leave it there. Thank you.

Thank you, Mark.

Your next question comes from the line of Nelson Ng from RBC. Your line is open.

Great, thanks. Good morning, everyone. So, the first question relates to all the development projects you have on the go. So, like big picture, how much do you spend or expense on development costs? I know some of your Canadian peers spend anywhere from like, 20 million to 100 million. I'm just wondering where you guys, kind of fall within the range? And then secondly, how does that cost get embedded? Is it within your – is it at the corporate level or is it in the renewable energy level? Or, I know some of it's in Aegis? But can you just give a bit more color on that?

Sure, maybe I'll say that – Jeff, Nelson, and I'll take the first question, and maybe Arthur can take the second question. But generally speaking, at Investor Day we did indicate that we would be ramping up our spend on new renewables and unveiled the 3,400 megawatt early stage Greenfield pipeline. I believe at that time, we indicated that there'd be about a $0.02 drag on EPS as a result of those activities. And so that accounts for the majority of that spend.

Okay. So, $0.02 per year in general is what we should expect?

That’s the incremental cost with respect to the Greenfield development that we're looking at . With respect to your question around how development costs get booked through, I mean, obviously, we would want the project to reach a certain feasibility with starts becoming capitalized on our books, but the early stage projects are undertaken through Aegis development platform, again, once they reach a specific threshold .

So Aegis does the U.S. developments, as well as international, like it's all done within Aegis?

It's all it's all done within one combined development shop . We call them call Aegis, maybe Aegis is not the right word for it, but it's really our one combined development shop and those costs get reimbursed through our results once they actually do achieve a certain .

Okay, got it. And then my second question relates to weather. So, Q4 weather was warmer than usual, and that was a negative impact. Q1, I guess, if you exclude the extreme weather was probably colder than usual, like, so would that help your utility earnings in Q1? I guess, aside from the fact that you had to pay a lot for commodities, but can you just give some color as to, like Q4 was warmer and those negative? So Q1 was colder, but obviously, commodity prices are also a lot higher. So, what would be the net impact excluding the, obviously excluding the Senate Wind Facility?

Yeah, good morning, Nelson. It’s Johnny again. So far 2021 has been a bit of a funny old year on the weather front, and actually, you looked at the facility in January, it was actually a much warmer winter than we were expecting. I think it's fair to say that the February has been a bit colder. We're interested to see where March plays out. So, in some ways, I would say probably all things considered, it's almost a watch at the moment. And so, not a huge, I think movement either up or down, as you look at the various moves that we've seen in the first couple of months of the quarter.

Okay, thanks. I'll leave it there.

Thanks Nelson.

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

Hi, thanks. Good morning. I wanted to call on some of the questions on impacting your credit ratings from the Midwest weather events and I understand you’re normalizing for earnings per share, like you shared, but clearly this isn't a some sort of a cultural impact. So, I'm wondering, really was there conversation to the credit rating agencies that that 50 million, did you get the sense that they're going to capitalize that in your balance sheet? Or is it going to flow through your FFO? Or they're just going to completely ignore it and normalize it out of their credit metrics methodology?

Hey Ben, it’s Arthur. It’s early days, like I said, we're probably only – there is a few players that are working through this, but I'll just leave it at that to say, I mean, we target without pushing in our metrics for especially things like this. So, we're not concerned about being able to absorb it.

Okay. So it sounds like it has decided what they are going to do there?

They have not decided. We are in early discussions with them. I mean they went back and just say, well, how's it going to impact your credit metrics? Full transparency, in terms of honesty, this will have a FFO impact, but full impact is absolutely transitionary. So, I guess I'll leave it at that. I'm sure we'll be watching it closely over the next few weeks. I’m sure they will take a position.

Okay, I'm excited. I mean, there can be somewhat more prospective looking than anything. Maybe I can slightly turn to your guidance, and I just want to make sure impact or when you guys impacted some of the driver you mentioned, the COVID-19 impact $0.02, there's a little average resource conditions, and then some acquisitions or delay, but then on the other side, you were able to surface cost savings and tax benefits, which I think you said it was $0.05 or so. So, it sounds like it's a wash on both sides. So, when you look at your versus beginning of year $0.05 like what else am I missing there in the conversation?

I think you've got – I just don't think it was a full on watch. The big impact here was COVID, was weather, but also obviously the delay in the acquisition. And as I mentioned earlier, there's a pretty significant seasonality that transpires with our BELCO utilities. So, we've closed it, call it a probably the worst time you can close it during the year, but that's certainly weighing on our results.

Okay. All right. Thank you very much.

Thanks Ben.

Your next question comes from the line of Richard Sunderland from JP Morgan. Your line is open.

Hi, thanks for taking my questions here. Just wanted to circle back to the incremental commodity costs you outlined at the start of the Q&A. The 200 million, are you able to break it down by jurisdiction and utility?

Yes, pretty much the majority of that through our in central, most of our other utilities are on the coastal regions get hit so hard, it’s our biggest utility by some way. So, it's a mixture of increased natural gas costs for running our gas generation fleet. And then some incremental costs on the electricity side .

Okay, got it. And then thinking around recovery at a higher level, could you run through maybe some offsets to the cost here? And are you simply thinking about amortization period? Or, you know, are there other considerations in terms of, you know, the recovery dynamics, I'm thinking in two parts, kind of the Asbury plant recovery could potentially impact as well in this sort of that dynamics at large. So, I mean, some kind of different levers there, but just curious how you see the path forward to recovering?

Yes, certainly in terms of the gas and electricity prices, we have an approved and well established process through our fuel and purchase power, adjustment fuel or . We saw that slightly in on a six monthly basis and in the normal course of business, as you follow that you then have a six month recovery period that follows that and because of the material nature of these incremental costs we filed with the commission, an AAO, an accounting order will allow us to put those costs onto the balance sheet and then have a conversation with the commission around. Actually what's the right period of time for us to recover those costs in a way that makes sense for us the business, but importantly, makes sense for our customers? You could imagine this would have a , really not the best time for them. And so, we still have those conversations with the commission, but in terms of sort of the process of prudent recovery those is well established and approved and documented already.

Got it, and just one last one, if I could? Just any dates or timing to watch in terms of those conversations with the commission?

So, it should be between now and April. So, our fuel adjustment filing is due on the 1st of April. So, we'll be having those conversations really in the next month to agree on the best way to handle the .

Got it. Thank you for the color.

Thanks Richard.

Your final question today comes from the line of Naji Baydoun from iA Capital Markets. Your line is open.

Hi, good morning. Just wanted to go back to M&A for a second. I guess in a worst case scenario where the New York Water acquisition, you know, doesn't go through, just wondering if you can talk about your pipeline of acquisitions today, and how quickly you can take that capital and reinvest it somewhere else?

Sure. So, as you know, historically, we've been a fairly, you know, transaction oriented company. So, we have done what something in the range of 20 transactions over the last 20 years or so. We, because of that experience, and because of our track record of being able to close our transactions, you know we're already in the mix in terms of discussions around these transactions, whether, you know, whether it can in the public realm or not. So, that's something that we cannot actually pinpoint as to exactly when those transactions or might happen, or if, and that's why, as a matter, of course, we only include on our five-year capital plan. The M&A transactions that we've already announced that may not have closed. So, that's why New York American Water is the only one on a five-year trajectory. To your point, worst case, New York American Water doesn’t close, we will be able to do another transaction. I mean, over, we just started our five-year plan, and obviously, we've got four years 10 months more to go. So, I will be highly confident in our ability to do more M&A transactions.

I appreciate the timing difficulty. It sounds like you're confident that that you can find other opportunities fairly quickly. I guess another question is, are there any updates to the Empire rate case, either the appeal process, or just any updates we should be aware of on the new rate case that you expect to file?

I don’t see any material updates, the appeal process is ongoing, it could take up to a year for that to come through. And we're preparing to file our next case in Missouri later on this year.

Okay. And just one last question on the Chevron framework agreement, just any updates, or I guess next steps that you're looking to achieve this year with Chevron?

Sure. So, Naji as a reminder, I mean, we announced that there was some time in the middle of 2020. And so what we have done since that time is, we have in fact done some joint procurement work to make sure, you know we have the Safe Harbor event with us, we have also filed four Interconnection Queue applications. So, those are well underway. And we are working through in terms of contractual structures and starting detailed engineering and design on those projects. So, we are making good progress. We're happy with the pace of progress we're making. And so, you know, the question is, you know when will we actually be able to announce something that starts construction, you know we are hopeful sometime this year.

Okay. That’s great to hear. Thank you.

Thank you.

That concludes our Q&A today. I now turn back to management for closing remarks.

Thank you very much. And thank you for taking the time on our call today. With that, please stay on the line for our disclaimer.

Our discussion during this call contains certain forward-looking information, including but not limited to our expectations regarding future earnings and capital expenditures, future commercial dates and the impact and outcomes of the recent severe winter storms in Texas and the Central U.S. This forward-looking information is based on certain assumptions, including those described in our most recent MD&A filed on SEDAR and EDGAR and Edgar are available on our website, and is subject to risks and uncertainties that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Forward-looking information provided during this call speaks only as of the date of this call and is based on the plan, belief, estimates, projections, expectations, opinions, and assumptions of management as of today's date. There can be no assurance that forward-looking information will prove to be accurate and you should not place undue reliance on forward-looking information. We disclaim any obligation to update any forward-looking information or to explain any material difference between subsequent actual events and such forward-looking information except as required by applicable law. In addition, during the course of this call, we may have referred to certain non-GAAP financial measures, including but not limited to adjusted net earnings, adjusted earnings per share or adjusted net EPS, adjusted EBITDA, adjusted funds from operations, and divisional operating profit. There is no standardized measure of such non-GAAP financial metrics. And consequently, AQN’s method of calculating these measures may differ from methods used by other companies and therefore, they may not be comparable to similar measures presented by other companies. For more information about both forward-looking information and non-GAAP financial measures, including a reconciliation of non-GAAP measures to the corresponding GAAP measures, please refer to our most recent MD&A filed on SEDAR in Canada or EDGAR in the United States, and available on our website. And that includes the conference call.

Thank you everybody for joining today. That concludes your conference call. You may now disconnect.