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Thank you for standing by. This is the conference operator. Welcome to the Algonquin Power & Utilities First Quarter 2018 Conference Call. [Operator Instructions] And 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. Thanks for joining us on our 2018 first quarter earnings conference call. As mentioned, my name is Chris Jarratt, and I'm Vice Chair of Algonquin Power & Utilities Corp. Joining me on the call today are Ian Robertson, our Chief Executive Officer; and David Bronicheski, our Chief Financial Officer. Ian and I are participating in this call from the U.K. today, where we just attended the Atlantica AGM and a board meeting; while David is back at our Algonquin office, holding the fort. I only mention this because I'm hoping we don't have any technical glitches, but if we do, that will be the explanation. To accompany this earnings call, we have a supplemental webcast presentation that you can access from our website, algonquinpowerutilities.com (sic) [algonquinpower.com]. This presentation as well as additional information on our Q1 2018 results is available for download from our 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, and I direct you to review our full disclosure on forward-looking information and non-GAAP financial measures available on our website. We will read the full disclaimer at the end of this call. On our call this morning, Ian is going to start with a review of the Q1 2018 strategic achievements. David is going to follow up with the Q1 financial highlights. And then Ian will conclude with our outlook for 2018 and beyond. We will then open the lines up for questions [Operator Instructions] And with that, I'm going to turn it over to Ian.
Thanks, Chris, and good morning to all of those on the line from North America. As Chris mentioned, we are in London today attending the Annual General Meeting of the Atlantica Yield, and obviously, it's an organization which we've made a significant investment. I'm pleased to speak today after what's been a pretty active quarter of the strategic initiatives, supported by strong performance across our portfolio. I think it bears noting that commencing this quarter, APUC is reporting its results in U.S. dollars, and therefore, all the references we'll be making during this call will to U.S. dollars unless we state otherwise. I'll start off today by outlining the main highlights in the quarter. Looking first to our financial results, Q1 marked a strong start to 2018. For those of us who do live in North America, we'll all know that we contended with the effects of a long and cold winter season. These conditions, along with strong renewable resource condition for much of our generating fleet, resulted in good operational performance across our businesses during the quarter. The impacts of new business investments, together with the impacts of recent U.S. tax reform, also influenced the Q1 results, upon which David will expand later in the call. Second, we saw a significant year-over-year increase in adjusted EBITDA and adjusted per share net earnings. For those of you who are more cash focused, adjusted funds from operation also increased by 15% on a year-over-year basis. A key component of our total shareholder return is a stable and growing dividend, supported by strong financial performance. We're pleased that our financial performance and growth prospects gave our Board of Directors the confidence to authorize an increase in our dividend of 10%, which we'll apply to the Q2 dividend declared as of yesterday's date. Next, we're pleased to report material progress in the expansion of our asset base and advancement of a number of our key growth initiatives. Following commissioning, we're pleased that our 75-megawatt Great Bay Solar facility in Maryland is now fully contributing to our financial results. I'd like to thank our project team for their persistence and hard work in reaching this milestone. Aligned with our commitment to being part of a sustainable energy future, we're excited to have reached a settlement with the Missouri regulators regarding the transformation of our Empire District generating fleet with the addition of 600 megawatts of new wind capacity under our Greening the Fleet initiative. For those of you who recall, this is an important strategic rationale in our investment in Empire Electric. Consistent with our objective of reducing the volatility of our customer bills, we were pleased that the tariff issued under our recent rate case at the EnergyNorth natural gas distribution utility in New Hampshire includes, for the first time, weather decoupling. And lastly, we continue to execute on our international investment strategy. In early March, we completed the formation of AAGES, our joint venture developer with Abengoa, and this fully staffed organization is now aggressively pursuing opportunities for investment in global clean energy and water infrastructure projects. And I'll provide a little bit more color on this later in the call. Contemporaneous with the formation of AAGES, we completed the acquisition of an initial 25% interest in Atlantica Yield. Subsequent to Q1, we announced a further investment in Atlantica through the acquisition of an additional 16.5% equity interest. And lastly, concurrent with our announcement of the additional Atlantica investment, we successfully closed CAD 445 million common share equity offering. Through this financing, we are fortunate to have secured a commitment from an important new global utility investor and further commitment from a selection of our existing shareholders. We're pleased that our recent equity issuances are targeting at meeting our currently anticipated 2018 common equity needs. And with that, David, I'll turn it back to North America to review our 2018 Q1 financial results.
All right. Thanks, Ian, and good morning, everybody. I think it's fair to say that our financial statements are looking a little different this quarter, and I'm sure it might be a little disorienting for some at first. This is the first quarter that we are reporting our results in U.S. dollars. But given that over 90% of our assets, revenues, cash flows and income is in the U.S., reporting in U.S. dollars just makes sense, and it allows people to see the stable operating performance of our company without the haze and volatility of foreign exchange clouding our results. To assist investors and analysts a little bit more with this change, we have also prepared an information package that is available on our website that converts our as-reported 2017 historical financial information and our non-GAAP financial measures, both annually and by quarter, into U.S. dollars. Before diving into our strong operating results in the first quarter, there were 2 items reflected in our results that warrant a bit of discussion. One is the accounting policy election we have been made for accounting for our investment in Atlantica, and the second is the acceleration of HLBV income that has resulted from U.S. tax reform. First, with respect to our accounting for our 25% investment in Atlantica, we have elected the fair value method of accounting under U.S. GAAP. Under this policy method, the dividends received from Atlantica are recognized in our income statement as dividend income and the income remains in our adjusted EBITDA and our adjusted EPS figures that we report. In the first quarter, we received dividend income in the amount of approximately $7.6 million. However, the fair value method also requires us to mark to market each quarter the fair value price of Atlantica shares that we hold on our balance sheet. We paid a premium to market for the shares we acquired, and in the first quarter, an unrealized noncash accounting loss of $117 million was recorded on our GAAP income statement. This amount is included in our GAAP income statement but is backed out in our adjusted EBITDA and adjusted EPS as this amount is an unrealized loss and is not reflective of the economics of our underlying investment in Atlantica, which is premised on the steady stream of dividends that come from Atlantica's high-quality portfolio of operating facilities. The second item that deserves a call-out is the acceleration in our HLBV income that is a follow-on effect from U.S. tax reform. As people on the call know, tax equity investors make an upfront cash investment into a U.S. renewable energy facility, and this amount shows up as noncontrolling interest on our balance sheet. Over the ensuing 10 years, the tax equity investors received their return on and of their invested capital through the operation of the facility in the form of production tax credits, tax depreciation expense and some amount of operating cash returned from the project. As the tax equity investor realizes those operating tax benefits on our behalf from the project, the amount they have invested gradually moves from noncontrolling interest through our income statement to form part of our retained earnings. Once they have fully earned their return on and of their invested capital, we are essentially left as the full owner of the facility thereafter. But the key here is that the tax equity investors are receiving an after-tax return. Following U.S. tax reform, with the lowering of corporate taxes, delivering that after-tax return just got easier on a pretax basis. Therefore, HLBV income has accelerated to reflect that real value transfer to Algonquin. In the first quarter, we recognized approximately $55 million of accelerated HLBV income. So with that additional background, let's dive into our first quarter operating results. As Ian mentioned earlier, APUC's consolidated operations, both regulated and unregulated, performed very well during the quarter. Year-over-year, our adjusted EBITDA was up 45%. One of the main contributors was the accelerated HLBV income that I just discussed, which accounted for approximately $55 million of year-over-year performance. But even net of HLBV, Liberty Power's EBITDA increased by 16% on a year-over-year basis. The increase was driven by a full quarter of results from our Deerfield wind farm, representing approximately $13 million of additional EBITDA; and our Q1 dividend from Atlantica of $7.6 million, a solid outing all around. On the utility side of our business, EBITDA was up almost 6% due to a colder winter or really, I should say, a more typical winter than what we saw in 2017. This brought in an additional $6.7 million of EBITDA and completed rate cases which increased revenues by nearly $4 million. Again, a solid outing for our utility business. Looking at adjusted EPS. We achieved growth of 68% in adjusted EPS to $0.32 for Q1 2018. As I explained earlier, our net earnings were adjusted for the unrealized noncash mark-to-market changes in the fair value of our Atlantica investment, but the adjusted earnings does include the accelerated HLBV. However, even without the accelerated HLBV, our adjusted EPS would have been $0.23 per share, which is still a 21% increase over 2017. Again, no matter how you look at it, solid results. Our adjusted funds from operations grew by 15% to $179.9 million in Q1 2018. And finally, as -- the last row of the table shows, our Q1 dividend. As Ian mentioned, we have announced the 10% increase in our dividends starting in Q2. The increase in our dividend of 10% is consistent with the growth in our earnings and cash flows, which has been well in excess of 10% for the last couple of years. This has allowed our dividend payout ratio to fall to approximately 80% or even a little bit lower of our annual EPS. Now given all the moving pieces this quarter, including the change to U.S. dollar reporting, the effective tax reform on our utility business, the acceleration in our HLBV income and our announced additional 16.5% investment in Atlantica, we thought that it would be useful to provide an update to material we presented at our Investor Day in December 2017. Based on the factors I have just described and as you can see on the slide in our webcast, Algonquin is expecting to end 2018 with a U.S. dollar EBITDA of between $750 million and $780 million. And we are now expecting to end the year with a U.S. dollar EPS of between $0.64 and $0.68. Before I think -- turn things back over to Ian, I would also like to say that shortly after the quarter, we were pleased to have completed a non-brokered offering of Algonquin Power common shares, raising $445 million of equity, which largely satisfies our common equity needs for the capital investments being made in 2018 related to our current capital plan. This non-brokered common share offering came from an opportunity created by a unique set of circumstances and should not necessarily be seen as a precedent for all future equity offerings. As our investors know, we are committed to growth, and with growth will come the need for more equity. So we will, in future years, continue to look for opportunities to broaden our shareholder base, including retail shareholders in Canada, the United States and now, with the creation of AAGES and the investment in Atlantica, around the world as well. So with that, I'll turn things back over to Ian for our future outlook.
Thanks, David. Consistent with past practice, before we open up the lines for questions and answers, I did want to provide a quick update to those on the call about some of our significant growth initiatives. As I'd mentioned at the beginning of the call, we're thrilled to have reached an important milestone in our efforts to transform the power generating fleet within our Midwest utilities region. Having reached a settlement agreement in Missouri for our plan to reduce customer energy bills through the addition of 600 megawatts of new wind capacity, we will be actively engaged across all of the regulatory jurisdictions involved and hope to conclude these discussions in Q3 of this year. We believe our Greening the Fleet plan in our Midwest region has the ability to generate cost savings for our customers over $300 million over the coming 20 years. Next up, Granite Bridge. Positive progress continues to be made on the development of the Granite Bridge pipeline and LNG infrastructure project we announced last year. Liberty Utilities has now received preliminary acceptance from the New Hampshire Department of Transport on the proposed pipeline route, and communications with key stakeholders for the project are actively underway. We continue to see the Granite Bridge pipeline and LNG initiative as an important opportunity to lower the energy cost for our New Hampshire gas customers by addressing the continuing New England natural gas supply constraints. And the final decision on this project is expected by early next year. Amherst Island. And hopefully, the last time it will be on this list is -- because construction is well advanced with the erection of the remaining few turbines expected in the coming weeks, and commissioning of the currently finished turbines well under way. The project is expected to be substantially complete next month. And then lastly, quick -- a couple of quick comments on the international side. We are pleased to have a new series of opportunities to outline to investors related to our International Expansion Initiative. As we outlined in our Q1 MD&A, we've described a couple of projects which we are actively evaluating, including a high-voltage transmission line in Peru. And I'd just point out that this project has many of the attributes we're seeking for international investment: revenue certainty provided by a 30-year concession agreement, paid in U.S. dollars, supported by a Peruvian government guarantee and a commercially secured opportunity for Algonquin and AAGES. A decision on our participation in this project will be made in the latter half of 2018. So before we go to questions, we do remain confident in our ability to execute on our financial and strategic objectives through the various avenues of growth which are open to us. We remain confident that our projected growth in earnings and cash flows will support our commitment to deliver industry-leading dividend growth. And with that, we'll open it up to questions. And I promise not to use the Elon Musk qualification for any questions that anyone would choose to ask in terms of no matter how boring and boneheaded they might be. I'm just kidding, kidding, kidding. So let's open it up for questions, operator.
[Operator Instructions] Our first question is from David Galison with Canaccord Genuity.
I'll try not to ask a boneheaded question. But maybe...
I'm just kidding, David, just kidding.
Well, the first one, I'm not entirely sure I fully understand the HLBV income, but -- so maybe it will be. But just how should I think about the accelerated income going forward?
Okay. Well, now that we've -- a certain amount of that HLBV income in the quarter has been accelerated. Going forward, we're going to be a more normal pace now for our HLBV income in the future. I mean, I guess, the best way to think of it is that $55 million is HLBV income that we would have recognized over the next 8 years, which is about the average length -- remaining length of our PTC projects that we have. So that amount has been accelerated, recognized in Q1. Now going forward, we're back to a more normal pace. As an example, there's probably $36 million of additional HLBV income that we're going to be recognizing in the balance of the year, but we'll now start to be at that sort of more normal pace.
Okay, that's helpful. And that is included in your guidance that you provided in U.S. dollars, correct?
Yes, it is.
Okay. And my second question is just on the Atlantica investment. So we've made 2 separate investments so far. Just wondering what your thoughts are going forward. Are we happy with where we are? Or could we see some additional ones in the future?
Well, David, just to be clear, as we look at Atlantica as a repository, kind of a final holding place for international projects. I think it is important that we actually not consolidate Atlantica onto our books. And right now, kind of current accounting guidance would say you've kind of maxed out at under 50%. So while we're pleased to be able to provided clarity to the capital markets by completing the investment of 100% of the interest in Atlantica owned by Abengoa, I don't -- I think, at these 10 seconds, it's hard to imagine us going above 50% in the organization.
Our next question is from Rupert Merer with National Bank Financial.
So I'd like to turn to rate cases. You had a positive outcome with the New Hampshire PUC, $11 million increase in rates there, including tax cuts. Looking at your total sort of rate base now, what percentage of rate base has seen rate adjustments for tax cuts? And can you provide us an update on when you anticipate we'll see the remaining rate cases to consider tax cuts?
Sure, and just to be clear, Rupert, as you can imagine, across the 13 jurisdictions in we're operating, not everyone actually requires a rate case. Some of the jurisdictions have kind of open dockets and imposed the impact of tax reform already without the benefit of rate case. It just turns out that New Hampshire, we happen to have an instant rate case going on, and so therefore, it was reflected. But -- and so our 2 largest utilities, New Hampshire and Missouri, we actually expect 2018 to have the tax impacts resolved. And so -- I'm just trying to mentally do the math, but that's got to be close to half at least of all of our utilities having sort of resolved how taxes are going to be -- the rate case of taxes are going to be taken into account. For 2019 and beyond, and I think this kind of echoes David's sentiment during the last earnings call -- or the last earnings call where we kind of gave some guidance of tax reform, you start to get out to 2019 and 2020 and the impact of lower taxes starts to get mixed with further capital investment, maybe higher operating costs, a whole bunch of other factors, and so it starts to get muted. And so I think there's nothing that would cause us to kind of materially deviate from the guidance we gave last year -- or last quarter. And it's reflected in David's slide, showing that the impact of tax reform on our utility operations was in the 2% to 3% of EBITDA range, and I think that's kind of what David's slide was showing. So I don't know, Rupert, if that kind of gives the clarity in terms of how you might be thinking about tax reform.
Yes. No, that's perfect. And looking at New Hampshire ROE, 9.3%. Can you remind us where was it before? And how are ROEs progressing? And how do you expect them to progress with the rising bond yields? Are you expecting rising ROEs? Or do you think they'll be flat? Can you give us some color on your outcome?
Well, interesting question. And I guess, as -- kind of we all acknowledge that ROEs kind of feel like a sticky long-term proxy for equity returns in the capital markets. And so arguably, if you think that interest rates are on the rise, and clearly, that's kind of what the empirical evidence would show, you think that ROEs should turn the corner and start to rise at some point in time, though I think we probably don't expect them to rise, I'd say, arguably, as fast as interest rates rise, in the same way as they didn't fall as quickly as interest rates fell. To be specifically responsive to your question about New Hampshire, our last rate case, while it being a blackbox settlement, was premised on 9.25% ROE. So I think we're actually pleased that -- 5 basis points obviously isn't statistically significant as an increase, but we're definitely not seeing continued downward pressure, though I'd say it's probably too early to declare victory and start saying that ROEs are notably headed up. I don't know, again, if that's kind of what you were looking for.
Yes. It seems like quite a healthy equity risk premium with 10-year bonds at 3%.
Yes, no kidding. So when you look at that spread between ROEs and the underlying from a bond perspective, you're absolutely right, it is at, I'll say, historically wide numbers. But arguably, rather than ROEs coming down, I think the thought is that interest rates could rise. And the good news, at least in the utility business, as you are aware, those interest rate costs are passed through to customers, at least a good news from a shareholder's perspective. And so if that gap gets narrowed by rising interest rates, that actually feels like, from a shareholder's perspective, probably a better outcome than continuing to squeeze on the top line, i.e. the ROEs.
Our next question is from Nelson Ng with RBC Capital.
A quick one on -- in terms of greening the Empire fleet, the 600 megawatts of wind. So I think the original proposal was for up to 800. How did you guys settle to 600? What were some of the factors? So that's -- and the second part of that question is, what's your -- I think, previously, you talked about $900 million of rate base improvements, net of tax equity. With 600, I guess, is it strictly just a proportionate reduction in the rate base? But also, given what you've seen from the bids you've asked for, is that -- $900 million on 800 megawatts, is that proportion or ratio still a fair estimate?
Okay. You kind of snuck 3 questions in there, Nelson, but I'll give you that one. So let's start on the total quantum of megawatts. If you kind of cast your mind back to our very first Investor Day when we announced the Atlantica -- or the Empire investment, we actually were at 600 megawatts, kind of what the initial number showed. And then as we worked our way through the financial model in terms of what might have been -- I want to say the optimal, but might have been a number that felt like it maximized savings for customers, we felt that 800 megawatts could definitely result in significant savings for customers. As we got into resolving the -- kind of the negotiations that go into these things with all the various stakeholders -- and if you looked at stipulation agreement, it was kind of signed by everybody other than the office of the public counsel, that, I think, everybody just felt more comfortable perhaps with a more modest investment. So that's kind of -- I don't want to say it just came through negotiations. We remain comfortable and confident that -- left to our own devices, we actually think 800 megawatts might have generated more customer savings, but we acknowledge that there's lots of various stakeholders' perspectives to be addressed here. In terms of your follow-on questions with respect to rate base, yes, I think you can adjust it proportionally. So that 600 megawatts, there's not a massive diseconomy of scale that would come into it. Having said that, I will note, and it's just kind of an interesting observation as we work our way through the process with the regulators, there's probably another $25 million to $30 million of incremental investment that we had not contemplated in our original investment plan, our customer savings plan, as we called it. So when I say it's proportional from 800 down to 600, yes, but there's actually kind of a bit of adder back of another $25 million or $30 million, so it's probably not as impactful as just doing the math on a pro rata basis. And then lastly, the bonus question that you snuck in was, after coming up with our RFP, did anybody come up with proposals that materially, if you want to think of it that way, lower the investment opportunity? And the short answer is no. I think there's enough transparency. And Lord knows, as developers of these assets, we've got enough experience to be able to say when we made our initial estimates of the cost of these facilities, I think we had a fairly disciplined idea of what they were going to cost. And frankly, Nelson, while we were obviously pleased with the competitive nature of those responses, it wasn't like any of them came in at numbers that were materially lower than what we had originally thought that these assets would cost to build.
Okay. And then now for my second 3-part question. So in terms of the 2 projects, the ATN3 and A3T, like the transmission line in Peru and the Mexican gas facility, could you just talk about first -- I guess, firstly, clarify whether that was something that Algonquin would directly get involved in through AAGES? Or would it potentially be dropped down to Atlantica Yield? So just talk about whether it's a project that Algonquin might want. And then, I guess, the second part of it is could you just talk about how far along construction those 2 projects are? I believe the transmission line is a bit earlier stage, but the Mexican gas facility is, I think, due to be completed this year. So yes, just touch on those items.
Come on [ Ng ], what's the third part of your question?
Well, actually, the third part is on that Mexican gas project. In terms of the PPAs, like how far along -- how fully contracted is the facility today? And where does it need to be for it to be suitable for it -- to get dropped down to either Algonquin or Atlantica Yield?
Okay. Chris can speak to those specific projects. But the only comment I'll -- and I'll start this kind of as a preamble to Chris' comments, Nelson, is both of those projects, in fact, actually with an additional project, if you kind of dig out of your files, you'll recall at the time -- back in November when we made the announcement of the creation of AAGES, there were 3 projects that were already, in effect, under construction by Abengoa. These are 2 of the 3 projects. And so they're kind of not new, if you want to think of it this way. This is just execution on opportunities that we had clearly identified back in November when -- at the time of the creation of AAGES. So with -- Chris, do you want to talk a bit about ATN3 and A3T, give Nelson some color?
Sure, yes. Yes, Nelson. So those first 2 projects are an AAGES project first. Both are not completed projects, and as we all know, Atlantica typically buys completed projects. So in the first instance, those things will be dropped down into AAGES, just to complete. But as you point out, they're kind of advanced in their current state. But just to answer your question, they do get dropped down to AAGES. As far as how far along are they, I would say that the ATN3 one, the transmission line project, that was a project that was started and then fully stopped. And so there's a bit of development work required to get that process restarted, and we're well into that now. So that project is probably a couple years away from being completed. The other project -- and this is kind of tied into your third question on A3T. A3T is probably way more advanced. It's well through construction. They are going through this process of getting the facility fully contracted. And they aren't there yet, but they're making progress on that on a weekly basis.
And then so -- and then maybe to kind of wrap up on that, Nelson, when Chris says they, he speaks to Abengoa, who obviously were the initial developers of those assets. As we think of this from an AAGES perspective, I think, to the extent that there was an interest in us stepping in to finish off the development of A3T, I think we need to get some greater line of sight to what are the tenors of those PPAs for those assets. And so I think just in -- if I had to handicap the projects -- those 2 projects in terms of where our interests lie, clearly, the 30-year U.S. dollar-denominated, sovereign-guaranteed concession for the ATN3 transmission line feels right on the fairway from either Atlantica or, frankly, Algonquin type projects. And so that's probably the one that really feels like it fits from our perspective. So I don't know if that's kind of the color you are looking for.
Yes, that helps. But in terms of -- you said still a few years away. So the contract was awarded -- so for ATN3, it was awarded back in 2013. Is there a like drop-dead date or completion requirement date before -- like given that it's been fully stopped and restarted, is there any risk that, that contract could be void?
Oh, I would say voided is -- maybe that's not the right way to look at it. One of the first things that needs to get done from a development perspective, and it's definitely on our list of things to do, is kind of complete the negotiations with the Peruvian government to amend that schedule. Clearly, that original schedule makes no sense anymore. And frankly, there's been a couple of transmission route change -- line changes -- route changes, and those need to be reflected in as well. So it's kind of real boots-on-the-ground development stuff. I think the AAGES guys, who -- many of whom, individually, were actually involved with ATN3 at its initial conception, they're working on our team now, and we're happy for them to giddy up and get to work. I think we're going -- again, before AAGES/Algonquin makes a financial commitment of significance to this project, we're going to need line of sight to resolution of those concession amendments. But we're cautiously optimistic, after conversations with the Peruvian government, that those amendments will be forthcoming. So it's kind of just the same sort of stuff that we would do in any development project that we would undertake so...
The next question is from Sean Steuart with TD Securities.
A couple questions. With respect to the change, Greening of the Fleet, [ plan at ] Empire, I mean, it sounds like the overall economics aren't going to change too much for you guys with a lower wind capacity number and the coal plant staying open. Just wondering if you can walk through the process from here. You hope to have everything in place approval-wise by Q3. What needs to happen between now and then for that to happen?
Sure. It's an active file literally. The hearings are wrapping up today in Jeff City -- Jefferson City. They've been going for the past 2 days. And so our witnesses have completed their testimony. So assuming testimony wraps up today, we'd expect Missouri commission to issue an order, I'll call it. I will say 45 days, 60 days feels like a pretty normal time for the issuance of an order. You know we had reached agreement in Oklahoma already, and so we're in the process of socializing the stipulation in Oklahoma. And Arkansas actually is waiting for us to file the agreements we have with the developers for the assets, which are targeted later this month. And so there's a confluence of events, Sean, that's kind of all aiming -- and that's why we were -- normally, we don't handicap kind of regulatory outcomes, but we were confident saying that, next quarter, we should have a pretty clear idea from the regulators in the material states as to how we're moving ahead. So that's kind of why we stepped out and gave guidance where we normally don't.
Got it. And follow-up questions on AAGES as well. You referenced the 2 projects you guys have underway. I think the third one was the San Antonio water transportation initiative. Any update there? And then follow-on with respect to all of the -- I guess, the midterm development opportunities. I think the initial envisaged equity investment was about USD 300 million. Is that still in the ballpark for the total investment?
Yes. So the San Antonio water project or affectionately known as the SAW project, it's still underway. But to be candid, that I'm not -- it's kind of on current course and speed to get completed. And while Atlantica still has a drop-down opportunity to drop it into Atlantica, I'm not sure that there's a real value-add opportunity for AAGES as we've gotten into it. As I said, the project is -- autopilot is never a word you want to use from a concession project, but that project is well underway, and I'm not sure that we see a real value-add opportunity, and that's why it's not on the list. So as you accurately point out, it was on that first list. In terms of future stuff, we were -- we unveiled the AAGES concept with the understanding that Abengoa was dumping an entire portfolio of green and perhaps later-stage projects into the hopper, and the guys are actively working on it. And so we remain absolutely convinced that there are some pretty fertile ground for making that investment, and that kind of quantum doesn't feel very hard for us to get. And so while we've always painted the international thing as kind of a nice to have, it's a diversification initiative, there's definitely opportunity there. And the good news, as we said back in November, man, we're not -- we got a running start at this. We're not trying to pick a map and hire guys and get going. We've got guys who are hungry and ready to -- and they're back at it now so...
[Operator Instructions] The next question is from David Quezada with Raymond James.
My first question, just on the -- moving over to the renewable power side. I'm wondering what your latest thoughts are just on the outlook there and if you're having any conversations with kind of junior developers with respect to the safe harbor turbines you still have.
Well, as -- the short answer is yes, we have continuing conversations. You know we've spoken in previous calls about our California project. I don't think anything has advanced to the stage that we would want to be specific about it, except I will point out 2 things that are opportunities that are commercially secure for us. You know we have a project called Sandy Ridge in Pennsylvania and Shady Oaks in Illinois. And both those projects are actually candidates for material expansion, if you want to think of it that way. And so while we haven't kind of talked about those, those would be great opportunities for us to deploy our safe harbor turbines, if some of the other opportunities that we see don't work out. So we remain cautiously comfortable that before 2020, we're going to have homes for all those safe harbor turbines and that the investment potential represented by them is going to be realized.
Okay, great. That's helpful. And then my only other question is -- wondering if you have any thoughts on the recent decision in California regarding mandated rooftops as part of new home builds starting in 2020. And do you see any impact to your business there at some point?
Well, I think -- well, it's an interesting initiative. And you know our -- I mean, there's 2 opportunities that come from that. One could -- you might be asking, "Is that cannibalistic to your utility business?" Well, if you've been to Lake Tahoe, a lot of trees there, you wouldn't do so well putting solar panels on those houses. So I think it's probably much, much more relevant down in the L.A. basin than in those other areas. But I think what it really does, from our perspective, if you follow kind of the impact of solar in the California electric market, it really is accentuating this, they call it, kind of the duck curve, where energy prices in the middle of the day, which historically were always the peak, are actually becoming some of the cheapest energy. And so what that screams at me is opportunity for storage because you want to be able to now start to time shift that. And so I think, while we're not in the resi solar business, as you well know, I think that's -- I don't want to say it's a mug's game, but I'm not sure there are -- the margins that we'd be looking for there, it certainly will continue to influence the electricity markets in California, and I think that will create opportunities going forward.
Our next question is from Rob Hope with Scotiabank.
Just turning the attention to the utilities. Most of the call has been focused on power so far. But given U.S. tax reform and the valuation compression that we've seen in some utilities, are you seeing any opportunities on the utility side for M&A, whether it be kind of smaller to midsize to larger [ price ]?
Well, it's an insightful question. I mean, I think what you're seeing, the impact of tax reform, as you -- I presume your question is pointed toward, is it's caused kind of cash compression, and we had kind of talked about our impact, which is relatively muted. But there's other utilities that it's been pretty significant. And I think the thesis that we are pursuing right now is, maybe rather than trying to raise equity in a marketplace which is suffering from multiple compression, is to sell off some assets. And so we're kind of reinvigorating our outbound calls to see if there are utilities for which the sale of something which is noncore, nonstrategic makes sense. So we're definitely trying to see if your thesis holds water.
All right. And that's what I was getting at. And then moving back over to the Midwest. Just can you provide some additional color on how the wind investment could be made, whether it be third parties or on your own books, and when you think there could be a capital commitment there and your return on capital?
Well, the investment of capital is always on -- directly on the books of our utilities, Rob. Just so it's clear, when I say an RFP, it's not an RFP for PPA, it's an RFP to build and then transfer, to the regulated utility, those assets. And so we will always be investing the capital. That is the value-maximizing thesis for reducing cost to our customers. In terms of making the investment, well, gosh, December 2020, those facilities will all be up and operational. And so if one is thinking about it from a modeling perspective, 2019 and 2020 seem pretty reasonable dates to start to feather in that capital.
Our next question is from Mark Jarvi with CIBC.
The first question, maybe it was said but I missed it. With the $56 million on the remeasurement, what was the impact on EPS this quarter? And what -- in that sort of waterfall chart, when you think about the 2018 projections?
Yes. Mark, it was about $0.09 on EPS because you have to take -- the $55 million, that's pretax -- you have to tax effect it, and then you'll work through the average number of shares outstanding. And so it works out to $0.09.
Okay, great. And then going back to Empire. I mean, the one sort of -- may be the wrong word, but dissenter right now is the Office of the People's Counsel. They've got a few different objections, whether it's the timing of when the savings come, exposure to merchant pricing. I guess they're concerned around guaranteed returns. Which one do you think is the biggest obstacle for them and views whether or not there's concession you guys have to make to what you filed on the current stipulation, to get them onboard and get this plan moving?
Well, the observation I'd make, Mark, in this is that one of the interveners who obviously testified in favor of this project was the major customer group. And so I think we presented a pretty cogent argument that there are net customer savings for consumers kind of right from the get-go. If you want to start kind of parsing what I think are economically suboptimal assumptions into that and you want to start creating opportunities to say, "Well, maybe it could cost more," I think you can do that. But if you look at our initial filing and look at all the assumptions that we made behind that, I'm not sure I share the perspective that the higher costs are practically -- or a practical outcome from this. I think it is a reasonable thing -- and I'll just make the observation that this is a difficult emotional transition for a lot of people in the Midwest, to transition away from coal to wind. And that's a challenge politically. It's a challenge emotionally. And so I think we're trying to ease that transition for people. So -- but I'm not sure that we're actually concerned about the approach that OPC is advocating as something that's going to necessitate further, I'll use the word, negotiation. I mean, I think it's an economically rational thesis. And we're hoping that, at the end of the day, the commission looks at the arguments that have been advanced by a very large number of the interveners, staff and this consumer group and the Sierra Club, like, man, there's a lot of momentum, to say this is just the right thing and this is what the future is. And so -- we'll have to see how this plays out. I totally get it. This is a regulatory docket, and OPC are entitled to take their perspective. But I don't think we're frightened, Mark, if that was kind of the essence of the question.
No, I just wondered whether or not you guys were sort of digging your heels in and you kind of drew a line in the sand or whether or not you think there are certain things you can amend to bring them onboard.
I think -- look, they were part of the negotiation. They made the decision. They were actively -- active in the negotiation. I just think, at the end of the day, as they thought about their mandate, signing on for something that perhaps was the -- started the path away from coal, that was just a hard thing for them to do. And so I don't think our arguments are lost on them. And anyway, we're just all in litigation mode now. That's just the way the process is unfolding.
Our next question is from Ben Pham with Bank of America Merrill Lynch (sic) [ BMO ].
It's actually Bank of Montréal. Your comment on the 80% payout, congratulations. I know you guys are at 120% for a long time. What are you guys thinking about that right now on the 80%? Is that a good level on a sustained basis or maybe a little bit room from 80%, from here with the power business, the cash yield on that? But what's your thought on 80%?
Well, you touch on a really interesting point, which I think reflects what needs to be considered in the continued maturation of this organization as we have kind of crested 70% regulated utility. The question we're asking ourselves as we think about setting our dividend going forward is that -- historically, we didn't really focus on a payout ratio as a function of EPS, but I think it's an active discussion going forward that maybe that's what we should be focusing our dividend and our dividend growth rate, so to the extent we can drive earnings up and maintain a constant payout ratio. I think if you look at our peers -- and maybe getting back specifically responsive to your question of how does 80% feel versus maybe in the 70s, which some of our U.S. peers might be at. I think we kind of have to decide what feels right to us. Clearly, more than 100% doesn't feel right. And I think below 50%, we're probably not attracting the group of shareholders who are interested in our total shareholder return proposition. So while there could be some bid-ask around is it 75%, is it 80%, is it 85%, I think that kind of feels like a zone that we're not apologetic for.
Okay, great. Second question on Atlantica Yield and how you guys think about international versus North American mix. Do you think of Atlantica as a dividend income, as that business percentage? Or do you think proportion of EBITDA because you can get some pretty material changes in how you calculate that?
Well, let me start by saying -- and while we have a lot of fun talking about the international stuff because it's the kind of new shiny thing within our story, international, this is not a strikes-to-spots story that we're trying to convey here in terms of shifting from North America to international. So let me just start by saying it's kind of, I want to say, 5% to 7% now. Hard to imagine it more than 10%. In terms of the strategy for how do we account for it, I mentioned earlier on one of the first calls that, in terms of our growth and ownership of Atlantica, we really do see this as a tool in our financial toolbox to be able to hold projects that have a financing paradigm different than our own, i.e. project finance, because they might have currency issues that aren't appropriately consolidated in our [ book ]. And so we actually see Atlantica as being a great tool in the Algonquin toolbox as part of this growth outside of Canada and the U.S. But I want everybody to keep it in context and measured here in terms of how we're thinking about it. I don't know if that's sort of -- that's responsive to your question, Ben.
Yes. So I guess you -- the way you view your exposure to international is a dividend income rather than the proportion of EBITDA of Atlantica because that's almost a triple [indiscernible]...
Yes. And I think the reason for that is, as you know, a project which is denominated in euros and maybe has some project financing debt on there, that just doesn't feel like the same sort of animal we have with the regulated [ view ], on-balance-sheet levered utility, and so we just don't want things to get confused, to be candid.
Our last question comes from Jeremy Rosenfield with Industrial Alliance Securities.
So first, on the HLBV, just coming back on that. I think several of the earlier projects they're approaching the tax flip dates, if I'm not mistaken. And I'm just wondering if you have any thoughts on changes in the cash flows from those projects coming forward in -- I think it's going to be 2019, '20 or so. Can you just update us on that?
Go ahead, David.
The base of projects are approaching the cash reversion date. But I think it's important to realize that, that doesn't really affect our operating cash flows. That's really more of an investing activity, and it's reflected there. And even then, throughout that period, there will still continue to be [ payable ] payments that are made and that we'll be getting on an annual basis.
Okay. So it won't go through -- it won't flow through the adjusted EBITDA line then?
No, that's -- it won't, that's correct.
Okay. And then on the AAGES, Atlantica, I saw recently, I think, Abengoa was awarded -- or was successful in bidding for a CSP project in Dubai. And I was just wondering if that's a type of project that AAGES would look at and eventually would be a candidate for AY or that has not been considered at this point.
Well, broadly, our arrangement with Abengoa is, to the extent that Abengoa is interested in providing EPC work for energy or water infrastructure projects on a worldwide basis, where there is a concession investment opportunity, clearly, first prize. And kind of, I'll say, our arrangement with Abengoa is that AAGES gets the first look at that. And so without being specific onto that project, clearly, that was the arrangement, that we kind of have a joined-at-the-hip relationship for global water and infrastructure investment projects, capitalizing on Abengoa's expertise.
Okay. And then maybe, if I can sneak another one in here, just in terms of the previous projects that you've -- the previous projects that you were talking about, the transmission and the Mexico concession. And I think there was -- it was mentioned in previous updates that it would be something like $650 million of total opportunities. And I was just wondering what the equity contemplated could be or the equity injection could -- contemplated could be from Algonquin into AAGES to finish those projects, notionally.
Well, [indiscernible] when one looks at kind of project finance opportunities, they generally have more debt than our 50-50. So I think for your estimate purposes, I don't know, 70-30 doesn't feel like an unreasonable -- if you wanted to kind of say that these guys are going to get between 70% and 75% debt on their projects and the balance in equity, that's probably not an unreasonable [ way ] to look at it.
This concludes the question-and-answer session. I would like to turn the conference back over to the presenters for any closing remarks.
Well, that's great. Thanks, everyone. We appreciate the indulgence of David being in Toronto and Chris and I being here in England. Looking forward to everyone joining us on our Q2 call. And until then, be safe, everyone. Thanks much.
This concludes today's conference call. You may...
And over to Ian now for the final disclaimers.
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 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 documents, filed by the company on SEDAR at sedar -- or www.sedar.com. 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 operation 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 any 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. Thank you.
This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.