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Thank you for standing by. This is the conference operator. Welcome to the Algonquin Power & Utilities Second Quarter 2018 Conference Call. [Operator Instructions] The conference is being recorded. [Operator Instructions] I would now like to turn the conference over to Christopher Jarratt, Vice Chair of Algonquin Power & Utilities. Please go ahead, Mr. Jarratt.
Thank you. Good morning, everyone, and thanks for joining us on our 2018 second quarter earnings conference call. As mentioned, my name is Chris Jarratt, and I'm the Vice Chair of Algonquin Power & Utilities Corp. Joining me on the call today are Ian Robertson, Chief Executive Officer; and David Bronicheski, our Chief Financial Officer.To accompany this earnings call, we also have a supplemental webcast presentation that you can access from our website, algonquinpowerandutilities.com. This presentation and additional information on our Q2 2018 results are available for download from the website.Over the course of this call, we will be providing information that relates to future events and expected financial positions, which should be considered forward looking. You can review our full disclosure on forward-looking information and non-GAAP financial measures on our website, and we will also read the full disclaimer at the end of the call.On our call this morning, Ian is going to start with a review of the Q2 2018 strategic achievements and David is going to follow up with our Q2 financial highlights, and then Ian will conclude with our outlook for 2018 and beyond. We will then open the lines for questions. [Operator Instructions] And with that, I will turn things over to Ian to discuss our progress in Q2.
Good morning, everyone, and thanks, Chris. We appreciate you taking time on this sunny summer Friday morning as we outline our performance and accomplishments in Q2 2018. Just a quick reminder to everyone on the call, we are now reporting our results in U.S. dollars. And so I remind you all that references made during the call to U.S. dollars -- are to U.S. dollars, unless we state otherwise.I'd like to start today with a few highlights of our activities and the progress made across our business in the quarter. Firstly, I think it's fair to credit our diversity in operations for the delivery of steady and growing financial results in the quarter. Challenging resource conditions faced by our wind power operations were more than offset by stronger commodity demand in our utilities and earnings contributed from new facilities.Specifically, you can see adjusted EBITDA increased by 9% as compared to the comparable quarter in 2017, and adjusted net earnings per share and adjusted funds from operations increased by 22% and 26%, respectively. We're pleased that the strong financial performance and sustained growth demonstrated in the quarter continues to justify the 10% dividend increase we announced last quarter.Secondly, we're pleased to report continued execution against our growth plan with some significant milestone passed during the quarter. Consistent with our commitment to playing the leadership role in the sustainability of the energy and water future, we received a favorable ruling from the Missouri Public Service Commission related to our efforts to transform the generating fleet within our Midwest electric utility to the addition of 600 megawatts of new wind capacity.Secondly, after a protracted development process, we're pleased that our 75-megawatt Amherst Island Wind Project here in Ontario has now gone into commercial operation. Out west, construction is now underway for the next 10 megawatts of solar-generating capacity to be owned by our California electric utility. This project complements the 50 megawatts of solar power generation commission last year [ and marks ] Progress against our commitment to making CalPeco one of the first 100% renewable energy powered electric utilities in North America.And lastly, we continue to make progress against our articulated growth plan. Early in the quarter, we announced a deeper commitment to our international expansion strategy with an agreement to acquire a further 16.5% equity interest in a company called Atlantica Yield. With the progress made on the necessary approvals, we continue to anticipate closing in Q3 or early Q4 this year.Additionally, we're confident that with support of APUC and our international [ developmental ] organization AAGES, Atlantica Yield will be able to realize on a number of identified accretive investment opportunities in the coming months.Within Liberty Utilities, our commitment to sustainability has led to our first investment in the development of renewable natural gas. EnergyNorth is committed to the development of a rate-based landfill-to-pipeline natural gas project, which is expected to deliver approximately 500 million cubic feet of renewable natural gas annually to our New Hampshire Gas utility customers.And lastly, our previous investment in safe harbor wind turbines continues to bear fruit with the commencement of development activities of more than 300 megawatts of new wind-generating projects in the U.S.With that summary, I'll pass it over to David for a review of our Q2 2018 financial results. David?
Thanks, Ian, and good morning, everybody. I'd like to start by just highlighting that we are, for the second time in a row, reporting our results in U.S. dollars with over 90% of our assets, revenues and cash flows coming from the U.S. Reporting in U.S. dollars allows our investors to see the stable operating performance of our company without the volatility associated with foreign exchange impacting our results quite as much. To further assist investors, we've also prepared and filed a full set of financial statements for our 2017 and 2016 with comparatives to further assist investors and analysts.With that said, let's take a closer look at our Q2 operating results. As Ian mentioned earlier, on a consolidated basis, we delivered strong Q2 results, posting impressive year-over-year growth in earnings and cash flow. Our strategy to build a diversified portfolio of renewable power generation in multiple jurisdictions and regulated utilities in 13 different states has again proven its worth.The best way to characterize our results for this quarter is that on an overall basis, our regulated utility business experienced above-average results due to favorable weather conditions, which more than offset the below-average resource condition in our renewable power business.Year-over-year, our adjusted EBITDA was $160.3 million for Q2, which was an increase of 9% over the comparable period last year. Within our Liberty Power business, our current year results for the quarter compared to last year were largely driven by a full quarter of results from our Great Bay Solar facility, representing about $2.8 million and $7.7 million of dividends from our investment in Atlantica, but partially offset by below long-term average wind resources primarily from our U.S. wind facilities.On the regulated utilities side of the business, EBITDA was up due to favorable weather conditions, which resulted in higher cooling degree days for part of the quarter within our electric utilities, primarily Empire. Overall, these conditions brought an additional $9.9 million of EBITDA in the quarter.Our ongoing management of making sure we earn our authorized regulatory returns saw the implementation of new rates within our CalPeco electric and Midstates Gas utilities, which also contributed to the year-over-year improvement in operating results. Again, we were very pleased with the performance of our utility business in the second quarter.Looking at adjusted EPS, we achieved growth of 22% in adjusted earnings per share to $0.11 per share in Q2 2018. As we explained last quarter, one of the adjustments to our adjusted earnings and adjusted EPS is for the unrealized noncash mark-to-market changes in the fair value of Atlantica investment, whether positive or negative, to be eliminated, and we did that this quarter as well.Now just a few comments on U.S. tax reform. At this point, we continue to reiterate our guidance from Q1 that we expect U.S. tax reform to negatively affect our EBITDA in 2018 by approximately 3% to 4%, which is within the normal variability with which we typically plan for our business in any event. But we've also note that tax reform is also expected to be neutral to slightly positive to EPS, particularly given that the nonrate side of our business is about 30% and overall tax reform is lowering our effective tax rate into the 16% range.Beyond 2018, the effects of U.S. tax reform are more likely to be addressed in the context of rate cases where all factors affecting rates, including growth and rate base operating cost, ROE, et cetera, are factored into an assessment of rates. That does remain our preferred approach, which we believe brings a balance between ensuring customer rates both reflect the lower taxes but also continue to provide a fair return to utility shareholders.Utility regulators, however, in different jurisdictions are taking different approaches and in timing to ensure the customer rates begin to reflect the lower tax rates. So we would note that until we get through all regulatory processes in our utilities, our guidance remains our best estimate at this point in time of the most likely outcome for 2018. But we will keep shareholders and analysts up-to-date as we move through the various regulatory processes for this.Lastly, before I turn things back to Ian, I'd like to mention that we were pleased to receive a BBB flat stable long-term issuer rating from Fitch Ratings for APUC and its subsidiaries, Liberty Power and Liberty Utilities. In addition, we received a BBB+ rating for our Liberty Utilities senior unsecured debt. We believe this rating again confirms the strength of APUC's overall corporate balance sheet and our focus on maintaining a strong investment-grade credit rating.And with that, I'll now turn things back over to Ian.
Thanks, David. We'll open the lines for questions in a couple of minutes. But as usual, before that, I want to spend a few moments speaking about the near-term growth initiatives being pursued within APUC as we look forward within our 5-year strategic planning horizon.Firstly, progress on our Greening the Fleet. As I referenced at the beginning of the call, we continue to make positive steps in transitioning our electric utilities toward a more sustainable mix of generation sources. Early in July, the Missouri Public Service Commission issued an order, which provides critical support for our customer savings plan, an initiative that involves the addition of 600 megawatts of cost-effective new wind power to serve the needs of our Midwest electric utility customers.In our regulatory filings with the MPSC, we outlined a plan to create up to $300 million in savings for our customers over the investment horizon for these new wind power generators. We continue to make headway in terms of regulatory support and other jurisdictions and in our on-the-ground project development efforts. We'd expect final investment decision on these development projects early next year.With respect to Granite Bridge, our Granite Bridge pipeline infrastructure project, which we announced last year, continues to progress. This $0.3333 billion pipeline and LNG initiative is expected to serve as a key component in lowering the energy cost for our New Hampshire customers by addressing chronic New England natural gas supply constraints. During the quarter, Liberty Utilities received preliminary acceptance of the proposed pipeline route from the New Hampshire Department of Transport, and environmental and geotechnical work are now underway.Active communications are continuing with our host communities and with other key stakeholders. To date, we've secured strong support for the project, including a statement of endorsement from 22 of the 24 New Hampshire senators and most recently from the New Hampshire Governor. A final investment decision is expected in early 2019 following approval from the New Hampshire Public Utilities Commission and site evaluation committee.And lastly, a couple of comments on our International Expansion Initiative. The development team within AAGES continues to assess the pipeline of projects sourced from our partner Abengoa as well as actively bidding on new international concession opportunities. Discussions took place in Q2 to familiarize potential infrastructure financing partners with the AAGES opportunity set and its mission.As we outlined in our MD&A, the highest priority opportunity is ATN3, a high-voltage transmission line project in Peru. As we've mentioned before, this project is emblematic of our desire to international investments. ATN3 will receive U.S. dollar indexed revenues under our 30-year concession agreement, which is supported by approving government guarantee. A final investment decision on AAGES' participation in this project is likely to be made this quarter.And finally, I want to leave you with some thoughts on our more than $6 billion near to midterm growth pipeline. From an organic utility growth perspective, in addition to key initiatives such as Greening the Fleet and Granite Bridge, we continue to prudently invest capital to improve the reliability and service we're providing to our customers. Our transformation team remains focused on our customer first initiative, a rate-based commitment of over $350 million to evolve our business to meet the changing needs of our customers.Within our nonregulated renewable energy subsidiary Liberty Power, we have a deep development pipeline, including our 177 megawatts Saskatchewan and 25-megawatt Quebec wind projects in Canada together with 4 projects representing over 400 megawatts of production tax credit supported wind projects in the U.S. I think it's notable to observe that the horizon for APUC to begin paying cash income taxes in the United States is approaching. And this creates the opportunity for APUC to act as its own tax equity in a number of these projects. Internationally, we remain committed investment opportunities outside Canada and United States. To this end, we expect to close our additional investment in Atlantica during the second half of this year.In summary, all of these initiatives lend confidence to APUC's ability to execute on its strategic objective of delivering growth in earnings and cash flows to support industry-leading dividend increases over the coming 5 years.With that, operator, I'd like to open the line for questions.
[Operator Instructions] Our first question comes from Sean Steuart with TD Securities.
A few questions. Let's start with AAGES. It looks like the A3T Mexican cogen project has dropped off your list of prospective projects. Maybe just an update on what's happening there and expansion on broader opportunities under AAGES going forward.
Yes, sure. As you know, the A3T project was a project that was commenced by Abengoa a number of years ago. And I would say strangely, but it was a project that was commenced without the support of a long-term offtake agreement in terms of the steam and electricity that was going to be produced by it. And while Abengoa has made good progress in ultimately contracting the offtake of that project, I will say that the character of those contracts were shorter than we were sort of, a, comfortable with and probably would represent a diminution in the average contract life within Atlantica. And so I think at this 10 seconds, our attention is probably focused to things like ATN3, that 30-year index transmission concession rather than something like A3T. And while I'm sure there are investors to whom A3T represents strategically aligned investment opportunity, it's difficult to see that it fits our bill. So I think right now, we -- our interest in that is probably lower, and I think that's represented in the fact that you don't see it in our MD&A anymore. But it's not like there's a dearth of other opportunities to consider. But there's a little bit of background, Sean.
Okay. And how would you characterize the backfilling of the AAGES pipeline in general? Is this progressing slower than you might have expected? How would you characterize it?
No, I think I'll say AAGES is a group of around 20 or 23 individuals, and I think they're out there digging up opportunities. And we bid on one in Chile, haven't heard back yet. Well, they're actively progressing on ATN3. They've got a number of opportunities that they're providing some due diligence assistance with respect to Atlantica Yield. And if you listen to the Atlantica Yield call, I guess, it was earlier this week, their CEO commented on a number of opportunities that they expect to realize in the coming months. And so I think it's very prudent as expected. I think one observation that I will point out is that the -- while the world is a big place, the value proposition associated with the renewable energy and other things is equally appreciated around the world. And so it's not as if they're much easier to come by in Chile or Peru than they are in North Dakota, and one -- there's a lot of work that needs to go into finding and sourcing and identifying good projects. And so I don't think it's taking any longer than it's taking in North America. But as I said, the world is a big place and there's 25 guys covering it. But the good news is we don't need to get all of the market in order to be successful. So I think it's working out okay, Sean.
Okay. Next question. The new U.S. wind development opportunities, you referenced COD targets in 2020 and 2021. How much of the capacity you're envisioning there might miss the PTC window? And if any, how does that affect your views on potential returns for those developments?
Well, you used the word missing the PTC window. Let's just be clear, it's missing the 100% PTC window. 80% of the PTC is still available for projects that are commissioned in 2021. And so as we think about a project that might slip to 2021, it would have to continue to meet our investment criteria in -- being -- in 2021, capitalizing only on 80% of the PTCs. And so it's not a cliff. I'll say it's a step-down. You might say it's a big one and -- because the value of that 20% of the PTC is probably $5 a megawatt hour, so it's not inconsequential. So to the extent that you move the project from '20 to 2021, you have to be confident that the economics can sustain that $5 a megawatt hour drop. I think the reality is that projects will continue to get developed, capitalizing on the PTCs right through until they drop off in 2023. I think it's the last year in which you can get the 20% PTCs. So any project that we would reference for a 2021 COD would be one that we are confident and comfortable that it still meets our investment criteria in 2021 with the 80% PTCs. I don't know if that's the kind of color you're looking for. Obviously, 2020 is better than 2021. But I think it's a -- there's a practical consideration in terms of how many hundreds of megawatts can you actually get developed and completed in that year. And I think the last thing you want to do is strive for something and miss the date and be -- end up with sort of unintended consequences of a lower PTC.
[Operator Instructions] Our next question is from Nelson Ng with RBC Capital Markets.
Just a quick follow-up to Sean's question. You mentioned the 80% PTC qualification. Did you -- like I know in the past, you bought, I think it was like $60 million of 100% PTC-qualified turbines. Have you also went ahead and bought some additional turbines at the end of last year?
No, Nelson. What we have done though is as we looked at a number of projects, we have struck arrangements or at least have the opportunity with a number of the manufacturers to exchange -- to the extent that we are pursuing an 80% project to exchange some of our 100% PTC components for projects -- for components that qualify for 80%. So in some respects, you might think of them as being usable for both, but it actually does involve an exchange. And so to follow up or to add a little bit more color to the answer I gave to Sean, to the extent that we have a project that we are targeting for 2021, that would have to be targeted because you can't just miss the 2020 deadline and flip to 2021. The income tax act is more specific and prescribed in that. And so if we have a project that were to due in 2021, that's a decision we will make now, and we will exchange our 100% PTC component with the manufacturers for ones that would be 80% qualified. I don't know if that's the color you're looking for, Nelson.
Yes. No, that helps. And then I guess, the next question relates to in terms of Empire Greening the Fleet. Can you just walk through, I guess, the next steps in terms of like what other kind of big milestones are required before you can essentially move forward with the project? And I think in the past, you talked about how, I think, you're progressing your own projects and also getting wind RFPs. Like could you talk about like whether any specific locations has been determined? And like what the process is there in terms of what or where the facilities would be?
Sure. So to sort of take those bits and pieces in order, there are 3 projects that will comprise the 600 megawatts. 2 of them are located in Western Missouri, just -- they're called North Fork and Kings Point. And those are 2 projects that Empire has developed and gone and signed land leases and started the environmental studies on. And so the RFP portion for those projects really was Empire looking for a third party to come in and undertake the construction of those projects on behalf of Empire and end up with the lowest price for the construction of its projects on its land located close to its load center. And I mean, that's material because obviously, you -- while the wind might be better in Nebraska, it's a long way down to Missouri and there are complications. The third project is going to be lower -- located in Eastern Oklahoma. And it's -- right now, there are 2 sites under kind of final consideration, and we'll be making that decision imminently. And so I can tell you where the -- at least 2 out of the 3 projects are, and I can tell you that there are 2 -- which are the 2 that were under consideration. But the primary objective of that RFP was to find all the best wind projects in the area to get the lowest levelized cost of energy. And I think we're really pleased that when you -- we were able to confirm, at least during the discussions with the -- on the order that was issued by the MPSC. There's a levelized cost of energy that the customers are going to enjoy all in. It's like in the $0.02 per kilowatt hour range. So it really is quite phenomenal that these projects are able to deliver that. So in terms of next steps, the -- from a regulatory perspective, the next steps are really to file what's called a certificate of convenience and necessity application, so CC&N application, for each of those 3 projects in front of the Missouri commission. I'd expect those to be filed sometime in September, early October. And there'll be a normal regulatory docket where the specifics of that project are looked at and that levelized cost of energy that I mentioned is consistent with the initial customer savings plan that got -- that was referenced in the order that the commission just issued. I would think that those orders will be late 2019 incoming, something like that, if the normal procedural document is filed. In advance of that, we are moving ahead on all the development activities specific in those projects in terms of interconnection, finalizing interconnection, finalizing environmental studies, entering into contracts, at least in the case of -- for the construction of those projects with the third parties. And so the intent is, as I've mentioned in my prepared remarks, to make a final investment decision for those projects late this year, early next year, but primarily file after the CC&N dockets are completed. So I don't know if that's kind of the color you're looking for. Happy to keep talking if I haven't answered the question.
So construction would start next year, right, like early next year or...
Yes, yes, yes. So just maybe to follow on to Sean's question, these are 2020 project commissions for sure.
Our next question is from Rupert Merer with National Bank.
Just a quick follow-up on Greening the Fleet. So is it 100% certain then that the projects will be in rate base? And if so, it will be at the same ROE as the rest of the rate base at Empire?
Yes. Certainly, the implicit and maybe even explicit conclusion on the order issued by the commission is that every dollar spent on these projects would be fungible with every other dollar in rate base. And so to the extent that we earn a 9.5%, 9.8% ROE on rate base, that would apply to these projects. Obviously, I would say -- maybe I shouldn't say obviously, the investment that's being made by tax equity is not our investment and therefore, isn't included in the rate base of the projects. And in fact, the tax equity, the return on -- return of that tax equity is generated by the PTCs that the projects are expected to generate. And so it's kind of outside of rate base. I don't know if that's helpful, Rupert.
Yes. And on that note, so you are considering being your own tax equity investor on these projects. Are you or are you [indiscernible]?
No. Yes. No, that comment really would apply to our nonregulated projects. I think the complications that would be created by attempting to be our own tax equity would create unintended affiliate considerations that we would have to deal with, with the commission. It's just much easier to deal with Wells Fargo or JPMorgan as the provider of that tax equity. I think it is important that customers of Missouri know that they, through a competitive process, they got the cheapest capital out there. So that comment would apply to us being our own tax equity would apply to the pipeline of nonregulated projects. Good news is there's probably more projects in the pipeline that our tax appetite could satisfy, and so I think there's lots of opportunity.
Our next question is from Robert Hope with Scotiabank.
Wanted your take on the Greening the Fleet initiative. So just want to get a sense of what you think the key hurdles are before that FID because it seems that the CC&N filing should be a rather normal course. And then I guess, secondly, if you are -- if one of the 3 wind projects faces difficulties, could you go forward in a piecemeal manner?
Sure, okay. So short answer is I would never presume to say that a regulatory docket is normal course, I think. But having said that, I think one looks to the order that was issued by the commission to give good support that's philosophically the commission is on side to this idea of reducing cost for customers through the construction of low-cost wind. The CC&N application is very specific, as you say. It's about the specifics of the project, where it's located. In some respects, would grant you condemnation rights should you need them for land, et cetera. But it's a process that we need to go through. And as I've mentioned, I think, to Nelson, end of this year, it's probably early next, is probably a reasonable time for the conclusion of those dockets, which would precede the FID. So -- but you are correct that each one of these projects, in some respects, is taken individually. And I don't think there's a requirement that we do 600 rather than, I'll make it up, 3 -- 2 projects of 200. So if there was an individual problem, then that would not [ scupper ] the entire program. And so I think that provides, I would hope, some benefits from your perspective as you think about the diversification of the regulatory approval process that it's not all or nothing.
All right, that's helpful. And then sticking in with Missouri. So Senate Bill 564, just wanted to get your sense on how you think the regulatory framework in Missouri is moving. It looks largely positive versus -- once you -- or since you have bought Empire.
Yes. No, there's no doubt about it. I think it's been -- I'll argue -- acknowledge, a long time coming. As you know, we've been in the state of Missouri since 2005, so we've been there a long time. And we have watched the legislature struggle a number of times with getting a legislation to, I'll say, modernize the regulatory environment. And we're pleased that -- you're correct, SB 564 represents a significant step forward. For us, the most notable element of SB 564 is the idea of normalization, weather normalization -- against weather in Missouri. I mean, whether we attribute the volatility in weather to global warming or not, the fact of the matter is I don't think we're asking our customers to ride the -- to either -- to ride the wave of volatility in weather. And so we're pleased that looking forward, we won't expose our customers, frankly, nor our shareholders to that volatility. And that's a -- as you're probably aware, that is a phenomenon, that weather normalization, that most modern regulatory environments provide. And most -- from our perspective, we're pleased that New Hampshire has also got on that bandwagon with the decoupling in our most recent rate case, EnergyNorth rate case as well. So it's -- yes, I'll just concur that Missouri seems to be moving ahead and we're pleased that we put our chips on the right state.
Our next question is from David Quezada with Raymond James.
A quick follow-up question on the potential for you guys to act as your own tax equity provider. I'm wondering if you have any other context you could provide on how you might structure that internally and whether or not would have any impact on the project returns in -- among your renewable development pipeline.
Well, I'll start by saying -- is we would not confuse the opportunity to invest in tax equity with the opportunity to invest in the cash equity of a particular wind project. And so the economics of that wind project would have to stand on its own. The economics associated with making a tax equity investment are -- I'll say, there's a fairly deep and robust market. So the returns that are available for making tax equity investments are largely understood in the marketplace. It would be an investment that would likely be made at the top of our house, so to speak. And so we would invest the capital that would -- might otherwise have come from a third party. And so -- but you can imagine in those sort of -- that sort of opportunity, so you can earn a return on and a return of your investment in that over the 10-year horizon. It's largely established for tax equity, so it's a healthy return over the near term. And then unfortunately or fortunately, it's only available to companies who have a tax equity, a cash tax horizon. And I would note that -- and maybe this is aspirational from our point of view that Warren Buffett's MidAmerican has pursued this strategy pretty extensively across the U.S. to capitalize on the cash taxability of their utility portfolio, which would be something that we would be, I'll say, replicating should we elect to go ahead with it. I don't know, David, if that's kind of what you're looking for. Or if you're looking for some more color, happy to get specific.
No, no, no. That's very helpful. My second question here, just on the remainder of the projects you outlined in the renewable pipeline, I'm just wondering, would the PPA in most cases be the biggest obstacle there? Is there any other hurdles that we should be aware of? Just trying to handicap the potential for those projects to go ahead.
Well, revenue certainty, as we sort of refer to it, has always -- I wouldn't say a hurdle for these projects. But I'll say the market is evolving and revenue certainty for projects today consist of a combination of utility PPAs, which has been the most historically conventional approach. But industrial and commercial PPAs, floating to fixed swaps, also known as hedges, agreements with community choice aggregators in the U.S., I think what is -- the character of the renewable marketplace in the U.S. is really changing to the fact that if you're going to own a renewable power-generating station today, you better acknowledge the fact that you're actually in the business of producing power, and there are markets in which you are -- your generating station is going to be located. And so going forward, and maybe this is the character of the projects that we're looking at, is you certainly got to pick the market that you're going to be in there, first, and then find the revenue certainty, second, because I think this idea of finding utility purchaser will give you a 25-year PPA that will largely insulate the returns of this project and transfer them to the utilities, getting a much tougher proposition to replicate. And so consequently, as we look at something like Walker Ridge as an opportunity, it is cited not based on the availability of the PPA per se, but based on the value of the product it's going to produce in the market in which it is located. And so yes, we intend to either find those contracts in the form of offtakers, of CCAs or hedges. But actually, that wasn't the driver for these projects. With respect to the hurdles that they face, I'll say, kind of the normal environmental and land tenure hurdles though, you -- I'm sure you acknowledge and noted from the projects that we articulated, it wouldn't be on that list. We didn't think it was more probable than not that we would get over all of those hurdles. That's kind of the test that we apply to put it on the list. And I think, obviously, that Shady Oaks #2 and Sandy Ridge #2 are expansions of our existing projects. I think it would probably increase or decrease in the handicap, depending on the way you'd look at it for the inclusion of those projects in your perspectives going forward for the company. So I don't know if that's kind of helpful in terms of the -- what you're looking for, but...
Our next question is from Ben Pham with BMO.
I wanted to continue on the tax question. And I'm curious, just given you guys -- you guys always announce new projects every year, and that backlog always gets bigger that you should reasonably assume that you don't pay taxes. And maybe not perpetuity, but you're always extending that shield. So I'm just trying to maybe figure out just that thought process. And then is your cash taxes really going to go up regardless of that dynamic that's occurring? Is that what I'm interpreting?
Yes. Ben, I think it's important to understand, I guess, the tax structure within our company. We've got, for all intents and purposes, I would say 4 tax returns, I'm obviously grossly simplifying it. But we've got a consolidated tax return at the top of the house and APUC tax return. We've got a consolidated tax return on the utility side of the business that exists. We have a consolidated tax return on the nonrate side of the business and we've -- in the U.S. And then we've got a series of tax returns we don't do to consolidate to tax returns in Canada, but we've got tax returns in the Canadian side. And they each have different taxability horizons. And obviously, now we're referring specifically to the U.S. And so the timing of the taxability horizons can be different depending on which, I'll say, tax return that you're referring to. And so we're trying to make sure that we're mindful of the different tax horizons that exist there.
And maybe just to add one more little piece of color to David's comments, Ben, is recent U.S. tax reform in that Tax Cuts and Jobs Act in the U.S. eliminated something called bonus depreciation for regulated utilities in the U.S. And so historically, most regulated utilities, every time they invested a dollar at the time, it's translated to $1 in that year of pretty much of tax deferral. That is now gone, meaning that most regulated utilities will find themselves in a cash taxable position in the relatively near term, and Liberty Utilities is no different than that. But what a great opportunity to be able to make an accretive investment to reduce that taxability horizon. And so David, our taxability horizon, for -- that would be applicable to acting as our own tax equity is very specifically, our Liberty Utilities regulated utility group in the U.S. So I don't know if that kind of helps distinguish between the CCA that we would get here in Canada or the makers' depreciation that would be available in the U.S. from these projects.
That's very helpful. Forgot about the -- or didn't appreciate [indiscernible] bonds depreciation angle. Can I ask then -- secondly, I know 5 years is quite some ways away, but have you made an update on the 2022 dividend, whether you had looked at extending that? I know last Investor Day, you've decided not to at least talk about it at that time. You've announced AAGES, you've got the Greening the Fleet. I know you don't want to go above 10%, but maybe just a quick update on 2022.
Yes. I'm not sure thinking has firmed up to the point where we would say, "Oh yes, you can count on the 10% in 2022." I think the statement we have made, and I think all of the initiatives that you referenced are supportive of a trajectory of earnings and cash flows that would allow the company to make a 10% dividend increase in 2022. If we felt that, that was -- that optimized the value proposition for our shareholders. I think we note that a lot of our -- the brethren within the power and university space in Canada are kind of backing off on some of their dividend growth objectives going forward. And at this 10 seconds, we're not doing that at all. In fact, quite the opposite, we're presenting an earnings and cash flow per share growth story that would be supportive of that if we wanted to continue to deliver it. And so while I can't give you any more confidence that our thinking has long been locked and loaded in terms of an additional 10%, I can say that we are pleased with all of the growth implications of all the initiatives that you've sort of heard about historically and maybe even some of the new ones that we articulated today.
Our next question is from Mark Jarvi with CIBC Capital Markets.
I want to go back to the Greening the Fleet. And you said some of your own land, but I get the impression that you used third-party developers. So maybe help me understand and with the other site as well, the sort of the build by developer and then transfer, and so then your capital commitments from Algonquin are from the utilities over the next couple of years, if this goes forward.
Yes. So you can imagine that in front of the commission, it's absolutely critical that we establish that we got the best possible price through a competitive dynamic for the construction of those wind projects. And the best way to do that, as you can imagine, is through issuance of a public request for proposal from third-party developers. And what we did within Empire, we went out and secured 50,000 acres of land and said, "Well, in addition to sites you might have, please give us a proposal to build out our large sites." And so from a broad range of third-party developers, we got proposals, sought the most economic for Empire. And it turns out that the use of our 2 sites was the most economic, the 2 most economic. And we chose the third most economic and they're all pretty closely grouped from -- that was a project that had been initiated by a third-party developer. And as I mentioned, it's kind of down to 2 for that third project, 2 opportunities that we're just evaluating. And so you described the process accurately that the developer will, in some respects, I guess, take our lands, go off and design the project, construct it and then turn it over to us, to Empire, for a payment, which has been negotiated and as part of the proposal they gave to us. And in that way, we can confirm to the commission that we got the best possible price, that there was a competitive tension that drove the price down to the bottom for our customers. And so you can imagine, if we -- within Algonquin Power & Utilities Corp., we said, "Well, we'll just build it ourselves." It leads to the rebuttable presumption that, that was the cheapest cost. And so -- and the good news is, man, we've got lots of work to do ourselves in our nonregulated side within our Liberty Power Group. So I think it works out well for us, Mark.
So just to close that out then, so your actual investment dollars wouldn't happen until those assets are up and running, so 2020 time frame? So maybe you can reconcile that with sort of expectations for funding plans and any external capital you need until the next kind of [indiscernible]?
Yes, so it's that great outcome that the -- those third-party developers will carry those projects during the construction period, which has always been, as you know, a challenge as we think about our credit metrics and having debt on our books that isn't actually generating earnings. And so yes, the -- our investment, Empire's investment to purchase the project, would come upon COD, essentially at the time that project now starts producing, if you will, value or revenues. And so therefore, we would start to earn a return on it. And so I think it solves a huge problem from our perspective in that it aligns the investment with the cash flows, which is exactly what we want to accomplish.
Our next question is from Jeremy Rosenfield with Industrial Alliance Securities.
Just a couple of cleanup questions. First, on the U.S. wind projects that you're contemplating, nonregulated investments, can you sort of elaborate on sort of the blended return profile if you are both the cash and tax equity investor in those projects?
Sure. Well, I'll start by saying -- is we actually don't blend them for exactly the reasons I said before. The last thing you'd want to do is have the returns on the tax equity somehow [ mask ] a project that, from a cash equity perspective, that you wouldn't do. Our return expectations for the cash equity are usually measured on an unlevered after-tax IRR basis. And we kind of, as I mentioned in the past, strive for something that's in the 8% to 9% range. If we can find that, that feels like it's consistent with the risks. Tax equity generally has a return and is again on an unlevered after-tax basis. When you add up all the bits and pieces and cost of tax equity, it's probably in the high 7%, low 8s range. And so it's not too far -- it's not too dissimilar from the returns that you could -- you would get on the cash equity. If you add them together that -- not surprisingly, the returns, when you kind of dollar average of them, are in the -- on a combined basis, in the 8% range. I will say that interestingly, the profile looks a little bit different. The tax equity has generally a more front end loaded return because it -- you get the return on and return of over the first 10 years, i.e. the PTC horizon. And in general, many times, the tax -- or the cash equity might have a more back end loaded return as energy prices rise and inflation drives up the top line. And so consequently, I think marrying the 2 together has a great opportunity to, if you will, provide a more level 25-year earnings profile, if we want to talk about them in time as well as in quantum. And so I think it is a nice opportunity. I will say it is reserved for those individuals who have a cash tax appetite which is predictable for the next 10 years. And the nice thing about the utility business is it's going to continue to have those earnings over that 10-year horizon. So it's a good opportunity for us.
It sounds like a match made in heaven. Let's -- let me just move. If you were to compare that investment profile with some of the other opportunities in front of you, it sounds obviously that there are increasing number of opportunities across the business, both the regulated side of the utilities business, nonregulated side of the power business. How do you sort of think about the amount of financing that you will require if you were to pursue all of these various opportunities? And how do you think about access to capital right now?
Well, it's -- I mean, you know that historically, we have been blessed with not having to make the Sophie's Choice, if you will, for particular investments in that we've been able to realize our objectives in both the reg and the non-reg side. I think if you're asking the question, is does our growth pipeline present a challenge to accomplish in its entirety over the next while because of constraints and access to capital, not sure we see that. I mean, keep in mind that we're talking about 5 years out. We're a $10 billion U.S. company right now and that represents $6 billion of investments. So while meaningful, it feels achievable within the context of the availability of capital to us right now.
And Jeremy, I would also add that we are always positioning ourselves to expand our sources of capital. And I think we've communicated this year that we will be adding hybrid securities to our capital structure as yet another source of capital. We're very focused on positioning ourselves to be able to access the equity capital markets and the debt capital markets in the United States. And I know that was in addition to -- just making sense because most of our business is in U.S. dollars. Converting our reporting currency to U.S. dollars was a strategic thought down that path of being able to position ourselves to better access the U.S. capital markets as well. So it's a continuing focus to us to make sure that we are diversifying that.
This concludes the question-and-answer session. I would like to turn the conference back over to the presenters for any closing remarks.
Well, I appreciate everyone taking the time for our call today. And we look forward to speaking you with next -- for our next quarterly call. And with that, I'll turn things over to our investor relations group to give you our riveting disclaimer.
Thank you, Ian. During the course of this conference call, we may have made statements relating to the future performance of Algonquin that contains forward-looking information, including statements with respect to the expected performance of the company, its future plans and its dividends to shareholders. While these forward-looking statements represent our current judgment based on certain material factors or assumptions, actual results could differ materially from such forward-looking statements made today.Additional information about the material factors that could cause actual results to differ materially from such forward-looking information and the material factors or assumptions that were applied in making any forward-looking statement as well as risk factors that may affect the future performance and results of Algonquin are contained in the results press release and Algonquin's public disclosure statements filed by the company SEDAR and on EDGAR. We undertake no obligation to update these forward-looking statements, unless required by law.Furthermore, during the course of this conference call, we have referred to certain non-GAAP financial measures, including but not limited to, adjusted net earnings, adjusted EBITDA, adjusted funds from operations, per share cash provided by adjusted funds from operations and per share cash provided by operating activities. These non-GAAP measures do not have any standardized meaning under GAAP and may not be comparable with other non-GAAP or non-IFRS financial measures presented by other companies.We refer you to our MD&A for more information about these non-GAAP measures, including a reconciliation of the non-GAAP measures to the corresponding GAAP measures where a comparable GAAP measure exists.Finally, our confidence level remains high in APUC's ability to execute on its financial and strategic objectives through the numerous avenues for growth we have available to us. And we maintain that our projected growth in earnings and cash flow support our commitment to grow our dividend by 10% annually through 2021.With that, I will turn the call over to the operator. Thank you.
Thank you. And this concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.