Algonquin Power & Utilities Corp

TSX:AQN

Earnings Call Transcript 2018-Q4

[Operator]

Thank you for standing by. This is the conference operator. Welcome to the Algonquin Power & Utilities Corp. Fourth Quarter 2018 and Full Year Results 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 Corp. Please go ahead, Mr. Jarratt.

[Christopher Kenneth Jarratt, Vice Chairman]

Great. Thank you very much. Good morning, everyone, and thank you for joining us on our fourth quarter and full year earnings results conference call. As mentioned, my name is Chris Jarratt, and I'm the Vice Chair of Algonquin Power & Utilities Corp. And joining me on the call today are Ian Robertson, our Chief Executive Officer; and David Bronicheski, our Chief Financial Officer. We do have a supplemental webcast presentation that accompanies this call, and you can access that from our website. Our audited financial statements and the MD&A are also available on our website, SEDAR and on EDGAR. Before continuing the call, we would like to remind you that our discussion in this call will include forward-looking information and non-GAAP financial measures. And at the end of the call, we will read a not-so-brief legal notice in respect of both forward-looking information and non-GAAP financial measures. On the call today, Ian's going to start with the strategic highlights of Q4 as well as our full year 2018. David will follow with the financial performance highlights, and then Ian will conclude the prepared portion of the call with an overview of our strategic growth plan for 2019 and beyond. As usual, we'll then open the lines up for questions. [Operator Instructions]And with that, I'm going to turn things over to Ian to start with the 2018 highlights.

[Ian Edward Robertson, CEO & Director]

Thanks, Chris, and good morning, everyone, and thanks for taking the time to join us today from lovely Oakville, Ontario. It's a solar-friendly, sunny but cold day. We appreciate that the last quarter call gives us a chance to, perhaps, pause and reflect in the progress we made over the entire year. And looking in that rearview mirror, we see a number of corporate achievements supported by another solid year of financial performance. We'll then spend some time looking in a bit more detail at our plans for the current year and also longer term as our team works on its successful execution against our 5-year strategic plan. So given that this here is our year-end earnings call, and while the quarter itself is important, it's probably more relevant to examine the main elements which we believe underpin the value of our organization. So firstly, I am pleased to report that the current businesses delivered strong and stable year-over-year growth in our key financial metrics. Adjusted earnings per share of $0.66 for the year marks a 16% improvement over the prior year. 2018 adjusted EBITDA also increased by around 16% as compared to 2017. With our commitment to maintaining a strong balance sheet, we're pleased that we exited 2018 on solid ground from a credit metrics perspective. And lastly, we're very mindful of the core role that our dividend plays in the total return expectations of our shareholders. Signaling their continued conviction in the growth and stability of our businesses, our Board of Directors approved a 10% increase in our dividend again in 2018. Secondly, 2018 saw the successful execution on a diverse array of growth initiatives, which will deliver future shareholder value. Capitalizing on one of our core competencies, we completed development of 150 megawatts of sustainable wind and solar generating capacity with the commissioning of our 75-megawatt Great Bay Solar project in Maryland and our 75-megawatt Amherst Island Wind Project here in Ontario. Outside Canada and the U.S., we advanced our international growth strategy with significant development activities underway in our AAGES joint venture and completed our acquisition of a 41.5% interest in a company called Atlantica Yield. Within our regulated utility business, we made meaningful progress on our plans to save customers up to $300 million through replacing a material portion of our fossil-based power supply with 600 megawatts of new wind capacity in Missouri and Kansas. In terms of growing our regulated footprint, 2018 saw us continue our history of successful M&A with our initial entrée into the Canadian utility marketplace through the announcement of an agreement for the acquisition of the provincial New Brunswick Gas franchise, an acquisition that's expected to be immediately accretive and provide opportunities for future growth. And lastly, we advanced our commitment to invest our own electric transmission here in Canada by partnering with Fortis and our respective First Nations partners. We're confident this combined electricity transmission project will greatly improve energy accessibility and reduce environmental impacts for 17 remote First Nations communities in Northern Ontario. More about that in a bit. And lastly, the third element of our value proposition is our diverse pipeline of identified growth opportunities across our business groups. At our 2018 Investor Day, we highlighted the $7.5 billion line-of-sight pipeline of growth opportunities, which our business groups are committed to capitalizing on over the coming 5 years. Within our Liberty Utilities businesses, we have an extensive array of organic investment initiatives underway with a focus on providing new solutions to customers while maintaining competitive utility rates. Specifically, we're focused on accelerating Liberty Utilities' transition to a renewable energy supplies and improved energy accessibility with our Greening the Fleet initiatives. Within Liberty Power, a total of $2.2 billion investment is expected to be allocated to 9 separate power projects in North America and also toward international growth opportunities such as our ATN3 transmission line, which you have heard about, in Peru. And finally, we remain committed to maintaining sustainability and to drive to operational excellence as core components of how we operate our business. And with that, I'll turn things over to David for a review of our Q4 and full year 2018 financial results. David?

[David Bronicheski, Chief Financial Officer]

Thanks, Ian, and good morning, everyone. As Ian mentioned -- referenced at the start of the call, in 2018, APUC has, again, showed its ability to grow its business in an accretive way through a stable utility and long-term contracted renewable power platform. On a consolidated basis, our Q4 results were positively impacted by the colder winter weather, plus we had dividend income from Atlantica and income from new operating facilities, which combined to increase our EBITDA and funds from operations this year compared to Q4 last year. But our net earnings were muddled a bit at the end of the year by the final noncash accounting revaluation impacts related to U.S. tax reform. So let's now turn to the full year results. Our overall operating performance was impressive. As Ian referenced earlier, on a full year basis, our adjusted net earnings per share grew by 16% to $0.66 per share. We posted an adjusted EBITDA for the full year 2018 of $803 million, an increase of 17% over the prior year. Digging a little deeper, Liberty Power delivered strong results in 2018, posting $303 million of operating profit, an increase of nearly 58% from the $193 million in 2017. These results were driven by contributions from our U.S. solar and thermal facilities, dividend income from Atlantica of close to $40 million and incremental HLBV income of $63 million. These were slightly offset by flat wind and hydro results as well as higher operating expenses over the course of the full year. On a year-over-year basis, Liberty Utilities delivered $550 million in operating profit in 2018. Steady growth in electricity sales of 9% and natural gas sales of 5% were partially offset by increased operating expenses. Further, improved contributions from our electricity and natural gas facilities were slightly offset by lower results from our water distribution and wastewater facilities.Now I'd like to touch briefly on the effects of U.S. tax reform. We provided detail throughout 2018 on the progress we have made incorporating the effects of tax reform into our business, including the utility rates paid by our customers. As we explained back in late 2017 and early 2018, we believe the tax reform would, on an overall basis, be neutral to slightly positive to our business and that the effects on our regulated utility business would be gradually absorbed given that we operate in 13 different regulatory jurisdictions and have several rate reviews in process at any given time. This has proven to be the case. Throughout the course of 2018, the Liberty Utilities group received a number of orders specific to tax reform from a majority of our regulators covering approximately 93% of our customers. This resulted in orders that lowered our annualized revenues by $35 million, and we realized about $18 million of that in 2018. But as you can see, overall, this is barely noticeable in our results due to the fact that we also had various rate reviews concluding in the year, which still resulted in higher overall rates, which were also implemented. The final topic I want to cover up relates to our capital structure and the steps we took in 2018 to strengthen our balance sheet. As everyone knows, Algonquin Power targets a BBB flat capital structure. In 2018, we completed 2 common equity financings for a total proceeds of approximately CAD 617 million to accretively fund our growth prospects while maintaining our solid BBB flat credit metrics. In October 2018, we completed our first issuance of listed debt sold directly into the U.S. capital markets with our subordinated notes offering. We raised a total of $287.5 million worth of 60-year nonqualified fixed-to-floating subordinated notes at a coupon of 6.875%. These notes now trade on the New York Stock Exchange under the symbol AQN. I'd also point out that the notes also provide us with additional equity credit from our rating agencies. We're also quite proud of the fact that we recently issued our inaugural green bond earlier this year, pricing a CAD 300 million 10-year senior unsecured bond at an attractive 4.6%. This is a key element of our sustainability commitments and represents the good housekeeping seal of approval, so to speak, that the proceeds for the bonds were used for sustainable purposes. Finally, by now, you would have seen the press release announcing that we have established an at-the-market equity program or ATM. Our ATM program is intended to provide us with additional financing flexibility, allowing us to raise a modest amount of equity over the next 20 months efficiently both from an overall cost perspective and from a timing perspective. With that, I'll hand things back over to Ian.

[Ian Edward Robertson, CEO & Director]

Thanks, David. Before we open up the lines for questions, I want to spend a few minutes on some of our growth opportunities. As typical in early December time frame, our leadership team met last December with investors and analysts, many of whom are likely on the call today, to discuss our current operations and our plans for the future. So at the risk of repeating what many of you heard at Investor Day, but perhaps, hopefully, preempting some of the questions that might be on your mind for today, I wanted to update you on our organic growth program. For 2019, our year-end filings laid out a capital plan of between $1.4 billion and $1.6 billion across both of our business groups. You might have noticed that the Liberty Power portion of this program has increased from that which was presented at Investor Day. And this has occurred as a result of the post-year-end decision to bring 100% of the Amherst Island Wind Project back home onto our balance sheet. With respect to our 2019 renewable energy projects, we're focused on advancing construction for 7 facilities, which, in the aggregate, would add over 1 gigawatt of sustainable new wind and solar capacity to our fleet in advance of the 2020 100% PTC deadline in the U.S. These projects include 600 megawatts represented by our Kings Point, North Fork and Neosho Ridge projects, which are part of the Greening the Fleet opportunity in Missouri and Kansas; 80 megawatts represented by our Phase 1 of the Broad Mountain project in Pennsylvania; and lastly, Sugar Creek and the Sandy Oaks (sic) [ Shady Oaks ] expansion, both in Illinois. And while development is pressing ahead on the Walker Ridge project, of which I've spoken to you in the past, I would note that our development efforts have been partially frustrated by the California wildfires, which understandably occupy the U.S. Bureau of Land Management, who are responsible for processing our [ permit ] application, and the bankruptcy at PG&E, who are the interconnecting utility. And while we're disappointed by the delay, we are pleased to note that the regulations governing U.S. PTCs recognized an extension to the December 31, 2020 is possible for reasons of force majeure. And so on this basis, while the Walker Ridge project may not be completed until early 2021, we're hopeful it will still qualify for 100% PTCs. And with respect to all of these projects, we're wrapping up 2020 turbine delivery slots with an agreement from Vestas and EPC contract reservations for erection cranes. On the international front, investment continues to advance with an early 2019 focus on commencing construction on the ATN3 transmission line in Peru. And as you all noted in our MD&A, we've now acquired 100% of the project interest of Abengoa and are working on obtaining the necessary amendments to the transmission concession from the Peruvian government. We hope to finalize the arrangements to allow commencement of construction later this year. And for those of you who have active Google web crawler alerts, you will have noticed that AAGES is active in RFPs for a large electric transmission concession in Panama and a significant desalination opportunity in Chile. And while, obviously, these are competitive process and our success in those opportunities is anything but assured, I wanted to highlight them to give you some insight into the types of opportunities on which AAGES is engaged. For Liberty Utilities, in addition to our normal-course capital investment programs and reliability initiatives, we're focused in 2019 on a number of major capital investment programs, as you know that renewable energy has been at the forefront of our company since we founded it 30 years ago. As outlined, the cornerstone of our Greening the Fleet program is the Customer Savings Plan in our central region, which is focused on saving our customers $300 million over the asset life of 600 megawatts of new wind generating capacity. Final regulatory approval dockets were filed last quarter, and we're expecting a decision in Q2 2019. Construction is planned to commence in Q3 of this year. Second, we continue to press ahead with the Granite Bridge pipeline and its associated 2 Bcf gas storage capacity tank. This project will improve reliability and lower energy cost for our New Hampshire customers by addressing the ongoing New England natural gas supply constraints. We're hoping that the current New Hampshire PUC process can be completed by late Q2 to allow moving forward with our New Hampshire Site Evaluation Committee filing to support a decision late this year or early next. You may have noted in our MD&A our partnership for the Wataynikaneyap transmission project to be located in Northwestern Ontario. Together with our First Nation partners, we've teamed up with Fortis for the development of this important project. And while we're excited about investing in this $1.6 billion Canadian opportunity in our home province of Ontario, more importantly, this project has the ability to make important economic and social contributions to 17 remote Northern Ontario communities by the delivery of reliable and clean energy. The regulatory process is expected to conclude early this year to allow construction to commence before year-end. And lastly, on the M&A front. In December, we announced an agreement for the acquisition of New Brunswick Gas, which marks our first entry into the regulated utility space in Canada. We expect to close this transaction along with our previously announced St. Lawrence Gas acquisition within the year, representing approximately $350 million in new utilities to be added to the Liberty Utilities footprint. And to wrap up my prepared comments today, I'm proud of the value created for our shareholders during 2018 and grateful for our talented team. I think they proved that an agile, entrepreneurial, culturally aligned team, all growing in the same direction, is clearly a powerful force. We've set an ambitious growth plan for ourselves. And we're committed to extending our track record of creating shareholder value in the current year and beyond. And with that, I'll turn things over to the operator to open it up for questions. Operator?

[Operator]

[Operator Instructions] Our first question is from David Quezada from Raymond James.

[David Quezada, Equity Analyst]

My first question here, just on -- I think there's a line item in the MD&A, higher operating costs at Empire and Granite State. Just wondering if you could provide any color on that.

[Ian Edward Robertson, CEO & Director]

Really, it's just -- I think in the quarter, it was just a matter of timing. And we're also increasing our capabilities in those regions on a number of fronts from an administrative point of view.

[David Bronicheski, Chief Financial Officer]

And so just to be clear, David, as you know, our operating costs form an element of our rate reviews, which are slated in the central region, a number of them, for next year so...

[David Quezada, Equity Analyst]

Okay. Okay, great. And then my other question here, on AAGES. Obviously, there's a couple of moving parts there at Atlantica. It sounds as though things, with bidding there on new projects, are proceeding as normal. Is there any potential for a change in your strategy on AAGES and the drop-down into Atlantica, depending on how things play out with PG&E and the strategic review?

[Ian Edward Robertson, CEO & Director]

Well, I mean, big question there, David, and it's probably worth a little bit of a longer answer. As I've said in the past, Atlantica is an important vehicle for us. It gives us an appropriate place into which to drop assets that are -- international assets that may have a financing structure which is inconsistent, perhaps, with the way we might do things here in Canada and the U.S. Consequently, one of the -- in order for that tool to be effective for us, we need to have a competitive and deep access to capital -- or Atlantica needs to. And I think it's not an unreasonable observation to say that at this 10 seconds, there's probably a difference between the inherent value of the assets that are currently owned by Atlantica and its share price. So consequently, we're obviously supportive of the strategic review that is targeting improving the cost of capital for Atlantica, and so we're supportive of that. In terms of change of strategy from our perspective, you know that -- and obviously, AAGES itself is not directly involved in Atlantica. That's a joint venture we have with Abengoa. And AAGES is actively working away on development projects. And I certainly hope that those projects could find their way into Atlantica. To the extent that Atlantica was unable to buy those projects, there are other options, including leaving them in AAGES from our perspective. So I think it's important to note that execution on our international strategy isn't dependent on but would be enhanced by kind of an improvement in the cost of capital and access to capital within Atlantica. So I think it's just important, David, to kind of separate the issues of our continued focus on international development from what's happening with the strategic review. And maybe then just some final thoughts on the strategic review committee for Atlantica. We're not on that committee, obviously. I think it's appropriate given our ownership that, that our committee kind of focus without influence on its process. And so -- but we are hopeful and standing on the sidelines cheering them on because, obviously, we've got an investment in that company, and it will be a great tool if it could be sharpen up for our toolbox. So I don't know if that answers your question, David, but...

[David Quezada, Equity Analyst]

It certainly does. That's great color.

[Ian Edward Robertson, CEO & Director]

Yes. I'm sure it was a long answer to a short question so...

[Operator]

The next question is from Nelson Ng with RBC Capital Markets.

[Nelson Ng, Analyst]

Quick one. Can you give a bit more background in terms of how you got involved in the Northwest Ontario transmission line? I didn't want to attempt to pronounce the project there, but you did a good job. Just in terms of like how you got involved, like just based on what I could find online, is that project -- the total project size, including I guess Phase 1 to Phase 2, is it about like $1.6 billion in costs?

[Ian Edward Robertson, CEO & Director]

Yes.

[Nelson Ng, Analyst]

And with your close to, call it, a 10% stake, I presume that's like a -- like your capital commitment is about 10% of that. So this is like -- I guess maybe it's a long question with a short answer, depending on what you could say. But like is there a longer or bigger picture play in terms of Northwestern Ontario given that you only have 10% now? And is there -- yes, what's the angle there?

[Ian Edward Robertson, CEO & Director]

Yes. So let me give you a little bit of, I'll say, background and color, and Nelson, if you kind of look back to some of our MD&As from a few years ago, you'll note that we were pursuing a project in Northwestern Ontario with 2 First Nation partners, the Mish and the Saugeen band, a similar but, perhaps, not as ambitious project in terms of scope. At the same time, I guess in parallel, our 22 First Nations bands had teamed up with, ultimately, Fortis to pursue a broader-scope project that looked at connecting a fairly large number of First Nations communities up in the Ring of Fire area in Northern Ontario. I think it was concluded that having our First Nations partners join the group of 22 just made sense in terms of bringing those ambitions together. And we were -- we negotiated with Fortis, basically, to acquire a 20% interest in the 49% interest which is held by non-First Nations partners. And maybe just to put some color on that, the First Nations partners, this is the First Nations communities-led initiative with 51% of the project. And so between Fortis and ourselves, we've got 49% to share, and that odd 9.8% just represents 20% of the 49%. Your math is correct. It is about a $1.6 billion project when you look at all of the phases interconnected. And perhaps -- and while I agree with you, you do the math and you say, well, gosh, $160 million doesn't seem like a massive exposure. Here's the bigger play. I think this project and maybe the East-West line, which is being pursued by Enbridge and, arguably, perhaps, others, I think represent the entry of Ontario into the investor-owned transmission sector. And I think we want to be part of it. We want to -- it is our -- I mentioned in my prepared remarks, it's our home province. I think we have a lot of local color and bring a local perspective to that project. And so I think you might see this, Nelson, as a strategic commitment to being part of the evolution of an investor-owned transmission sector here in Ontario. So will more come? Well, we hope so. But you got to get the first puck in the net for future goals. I don't know -- that's probably a long answer to your long question, but I don't know if that was the color you're looking for, Nelson.

[Nelson Ng, Analyst]

Yes, that's really good color. And I was just also wondering whether there were like generation opportunities you can do there like kind of involved in the transmission lines.

[Ian Edward Robertson, CEO & Director]

Well, I don't know if I'd say that we have a particular, I'll say, monopolistic walk on that, but think of it this way. To the extent that you are opening up significant areas that could have significant load, and I'm thinking of the opportunities from a minerals exploitation perspective in that area, God, I can't help but think that you've now just created an economic opportunity for new, perhaps, hydroelectric, wind projects. So I think it's good news for the entire IPP sector when you start to open up areas that were previously uneconomically accessible.

[Nelson Ng, Analyst]

Okay, great. And then moving on to my second question. You mentioned that the, I guess, Generation segment's capital investment increased because you've included the Amherst Island project into the, I guess, 2019 plan. But can you just give a bit more color into that given that, that project was completed last year? Is this more of an accounting item rather than a cash flow item?

[Ian Edward Robertson, CEO & Director]

Yes, I think that's a fair way to characterize it. In our $7.5 billion growth program that we laid out last year, we've always assumed that, from a balance sheet perspective, that project would come home at some point in time. As you know, it was equity accounted for because of our joint venture. And while we had made the decision at 2018 Investor Day, in early 2019, we decided to bring it home sooner than, perhaps, it might have otherwise had been timed in that 5-year program. So I think I agree with you. I think that your characterization is correct.

[Operator]

[Operator Instructions] Our next question is from Ben Pham with BMO.

[Benjamin Pham, Analyst]

I wanted to go back to the question on Atlantica Yield, the strategic review. And I guess I know you're not involved in the committee and whatnot. I guess the ideal scenario is you have a low-cost player stepped in, pick up the public equity, and then you can -- [ saw where ] it drop-downs. But I guess is there a scenario where it may not be conducive to you guys, where you may have to revisit your ownership percentage?

[Ian Edward Robertson, CEO & Director]

Well, let me start by saying, Ben, we are neither sellers nor actually, candidly, buyers in this process on the basis that you know not owning, not controlling Atlantica is an important element of this thesis around that vehicle. But we're not sellers of that vehicle either. And with 41.5%, we actually have the ability to just say no. So I think it's not unfair for us to say, we're not going to be jammed into a situation that ends up strategically misaligned with what our objective for Atlantica was. Having said that, we acknowledge that if, ultimately, something gets done, it's got to be, I think, good for everyone. There's 58.5% of the public capital -- of the shares that are held in the public capital markets. And I think the strategic reviews committee is looking at all options to say, how do I make sure I maximize value for that group. But I think we're comfortable that the outcome will never be something that we say, oh, my gosh, what a perversely negative outcome for us. That's not what happens to a 41.5% shareholder.

[David Bronicheski, Chief Financial Officer]

And I think we've been clear, and just to reiterate, that we have no desire or intention to control or go over the 50% ownership in Atlantica.

[Benjamin Pham, Analyst]

Yes, okay. That makes a lot of sense. And then on the ATM, should we think about the ATM as just kind of like external equity portion in that funding part that you guys provided last December?

[David Bronicheski, Chief Financial Officer]

Yes. It's just another tool to the toolbox is kind of how we're looking at it. And I think people shouldn't read too much into the fact that it's $250 million. I mean, it has a 20-month life, and typical to shelves that are put out there, you often just put a little bit more than you might ultimately need just to make sure that you've got a little bit of flexibility. But there's, at this point in time, no predetermined level of exercise of that program that's been determined by our board. And we'll, I think, be looking at dribbling out equity kind of opportunistically going forward. But I think it's -- people should understand this sort of much more modestly than what you might think of the $250 million. The $250 million is just there to have additional flexibility because it does have to last for 20 months.

[Operator]

The next question is from Rob Hope with Scotiabank.

[Robert Hope, Analyst]

I want to go back and revisit Atlantica, and I appreciate your prior comments on leaving projects in AAGES. But if we take a look at Sugar Creek, it looks like that's now proceeding and you have some off-takers there. That was going to get project debt and be dropped down into Atlantica eventually. So how are you thinking about that project with the uncertainty at Atlantica?

[Ian Edward Robertson, CEO & Director]

Well, I think, Rob, you've kind of heard me say that a drop-down to Atlantica is an optimization of kind of capital structure opportunity. We would never have sort of pursued or invested in Sugar Creek if we weren't happy to kind of own it ourselves in the same way as we own Senate, Minonk, Shady Oaks, Sandy Ridge. So the drop-down to Atlantica is an optimization of the ownership structure. But pursuing Sugar Creek is not predicated on Atlantica being, I'll say, in a -- I'll call it a good place from a cost of capital and access to capital point of view to be our partner. I think that's our intended course of action. I think that the Atlantica Board of Directors are committed to their strategic review committee in terms of optimizing the cost of capital. I'm cautiously optimistic that they'll be able to achieve their objectives. But it doesn't change our commitment to things like Sugar Creek or any of the other things that we might drop down into Atlantica. So Rob, you should think it's full steam ahead from our perspective on all of those opportunities. I don't know if that is kind of the clarification you were looking for, but nothing in our books from a development point of view is contingent on the outcome of the strategic review process.

[Robert Hope, Analyst]

That's what I was looking for. And then second question, just moving over to the financing. I think the thought was that the equity issue at the end of '18 fulfilled your common needs for 2019. We've seen CapEx move up a little bit. Is this kind of why you brought the ATM in and you can lean in on that a little bit to maintain your metrics?

[David Bronicheski, Chief Financial Officer]

Two comments on there. The equity raise in December was really specific to our announcement that we were acquiring New Brunswick Gas, and so that equity offering was, I'll say, notionally sized to accommodate that. The ATM program, as I said earlier, really, is just another tool in the toolbox. We have a DRIP program. ATMs are certainly very commonplace in the U.S. and are becoming increasingly common here in Canada. But we don't have any predetermined amount of equity necessarily that we can or will issue off of that. I mean, there's issuers here in Canada that have an ATM program. Some have used it and some haven't. And so we just wanted to make sure that we had additional flexibility for us over the next 20 months.

[Operator]

The next question is from Rupert Merer with National Bank Financial.

[Rupert M. Merer, Managing Director and Research Analyst]

I have a couple housekeeping questions. So looking at the performance in the power group, pretty solid in the quarter, and it seemed like a good part of that outperformance was driven by lower cost. Just wondering if you could comment on what drove the costs there and how we should look at the cost going forward.

[David Bronicheski, Chief Financial Officer]

Yes. So I'd say we're resetting to a different level of cost within the power group, but it's really because we've decided to form a single worldwide development platform through AAGES. And so there's costs that previously were directly incurred by the power group that are now being incurred in our joint venture with Abengoa. And so it's sort of a re-shifting of the income statement, if you will.

[Rupert M. Merer, Managing Director and Research Analyst]

Okay. So those are being mostly development costs then, I suppose.

[David Bronicheski, Chief Financial Officer]

Correct.

[Ian Edward Robertson, CEO & Director]

Yes.

[Rupert M. Merer, Managing Director and Research Analyst]

Okay, excellent. And on Amherst Island, so you acquired the second half of the project here. Can you tell us when you expect that to close? And I understand the acquisition price was predetermined, so we assume the price is consistent with your typical hurdle rates on acquisitions or development.

[Ian Edward Robertson, CEO & Director]

Yes. I mean, one way to think about it, Rupert, is that it was always contemplated, I think, over the 5-year program that Amherst -- the other half of Amherst would come home. And so when -- our third-party partner, as you know, was the EPC contractor. But a large share of the costs of the project were actually funded by ourselves through subordinated debt. And so I think that the acquisition of that project is probably more about consolidation onto our balance sheet rather than economic investment. And that's what I was saying as we both funded equity in the project to get it up and get it going and getting it to construction. But I will say that the equity interest in comparison to the total project costs were relatively modest. So I wouldn't be thinking about it as -- so much as a consolidation onto our balance sheet rather than an acquisition so much of 50% on a hurdle rate or price basis. It's really just kind of bringing it home. I don't know if that's clear.

[Rupert M. Merer, Managing Director and Research Analyst]

Yes, yes. All right. Very clear.

[Operator]

The next question is from Nicholas Campanella with Bank of America Merrill Lynch.

[Nicholas Joseph Campanella, Research Analyst]

So I just want to start and ask about the disclosure in the MD&A surrounding the cross-border structure. Could you just, perhaps, quantify the net income benefit you might have realized from that in '18 versus where it could potentially go if this IRS guidance does come to fruition?

[David Bronicheski, Chief Financial Officer]

We don't provide that as public guidance in terms of the cross-border structures for obvious reasons, but let me just comment kind of generally. I mean, we avail of ourselves with a number of cross-border structures, some of which are, I guess, being addressed in the draft IRS regulations and some of which are not being addressed in the draft IRS regulations. And it's still to be determined which structures generally may or may not be affected. We do know that there's also transitional rules for some of them so that it won't actually come into effect until 2020. And in the meantime, we're -- we've got a lot of smart people, all of the accounting firms, also have a lot of smart tax people as well. And so we're looking at alternative structures that can give us the same or similar benefit which we're achieving through the structures that potentially are at risk. So until the proposed regulations are final, and that won't be until June, it's really not possible to provide any further color on that.

[Nicholas Joseph Campanella, Research Analyst]

Okay. So I guess you guys gave guidance at your Analyst Day for tax rates. I think they were 23%. So in terms of 2020, should we still be using the same tax rate there?

[David Bronicheski, Chief Financial Officer]

Well, I mean, that will be determined on the outcome of the rates once they're final in June and we've had an opportunity to assess the different structures that still might be available for us going into 2020. I mean, it's, I would just say, a little too early to be saying too much about those forward tax rates.

[Ian Edward Robertson, CEO & Director]

But Nick, it's Ian, I think the expectation is that we'll be, first of all, updating that -- those thoughts and guidance as clarity comes from the tax professionals. But I think fundamentally, we don't think our business is sort of fundamentally exposed. This isn't a tax-driven business. The underlying value of the business is it stands on its own. We obviously have certain efficiencies and opportunities that are available to us as a non-American, I'll say, investing 95% of our capital in the U.S. And I think we're cautiously optimistic that there a lot of smart minds, making sure that we can kind of preserve the status quo going forward. But we'll obviously keep you up to speed as those things evolve.

[David Bronicheski, Chief Financial Officer]

And I would add one other thing on the cross-border structures. I mean -- and this is -- has been -- I'll say, from day 1, any investment that we made, any acquisition that we made over the years, none of those were ever predicated on having these structures in place. This was always viewed as an over-and-above.

[Nicholas Joseph Campanella, Research Analyst]

Got it. I definitely appreciate that color. I guess my second question just goes back to some of the questions previously around AY and the fact that it sounds like the general strategy is not dependent on AY's success. So I guess, if AY doesn't continue to grow the dividend at the current clip that they just kind of gave out in yesterday's analyst call, does that affect your own growth trajectory? Or how are you framing that?

[Ian Edward Robertson, CEO & Director]

No. I mean, I think, Nick, you've probably heard me say that last year, when we announced our intention to, I'll say, go international, I mean, outside of Canada and the U.S., the really strategic element of that was the formation of a group of professionals kind of similar to the group we had internally and, I'd say, domestically to chase projects externally. Who ultimately holds, I'll say, the other half of those opportunities, and we do want somebody to hold the other half of those opportunities just because the nature of projects in -- transmission projects in Chile or whatever are generally more highly levered than we would do on our domestic balance sheet, I don't think we're indifferent to who holds the other half of those projects. We'd like it to be Atlantica. I think it could be Atlantica. But clearly, they've got a cost of capital challenge, which their board acknowledges and is trying to fix. But it certainly doesn't change our growth plans or our growth trajectory, and that was kind of my comment and answer to something like Sugar Creek. With respect to the growth, and maybe we'll just give you a comment on the dividend, I think the people who look at Atlantica, and I know your team does do that, I think we're comfortable at these 10 seconds that, to the extent that things didn't end well with respect to PG&E and the Mojave project, the dividend that we contemplated when we made our acquisition is probably not being threatened. Clearly, there is capital that, right now, is being withheld by a payout ratio which is kind of in the 80% range. But you know that the corporate finance says that, that capital which was withheld ultimately just translates into a higher AY share price. That's just the way the math works. And as you know, we write out of our results increases or decreases in the AY share price. So I don't want to say that capital that's withheld for a payout ratio less than 1% is lost to us, but it's practically lost to us. And so the threat to us is not so much PG&E. I think the threat for Atlantica being a tool in our toolbox is having shareholders on the other half of that, I'll use the word half, the other half of that vehicle who have an appetite for and an appreciation of the appropriate discount rate for international infrastructure projects. And so we're cheering Atlantica on, but to the extent that they're unable to solve the problem, that won't slow us down one iota, Nick. I hope that sort of adds some perspective to how we think of Atlantica.

[Operator]

The next question is from Sean Steuart with TD Securities.

[Sean Steuart, Research Analyst]

A couple of questions. You've got a full plate with growth, clearly. But I'm wondering if you can comment on how the M&A opportunity set for utilities in North America is developed. What does the opportunity set look like? And what's your appetite for acquisitions at this point?

[Ian Edward Robertson, CEO & Director]

Well, without telling stories out of school, you obviously know that Emera has been very public about addressing some of their [ balancing ] challenges through the sale of Emera Maine. And with New Hampshire and Massachusetts in Liberty Utilities footprint, Maine would be a nice addition. It's a competitive process. We will never do anything which is dilutive to our earnings or our strategic plan, and so [ they'll ] know how that's going to turn out. But sticks on the ice, Sean. We don't know if the puck is coming our way. More broadly, you've heard me say that the M&A market is fiercely competitive, and you have to be opportunistic in it. We will look at all of the opportunities but with the lens of, at the end of the day, something better be strategically aligned and better be accretive to earnings. It needs to be financed in a way which is constructive to our credit metrics. I think it's not an unfair statement to say that the culmination of the capital markets to tolerate organizations that stretch their balance sheets to accommodate M&A, those days are sort of -- the sun has set on those days. And so while we are proud of the fact that we were able to complete the acquisition of Empire and maybe we stretched our balance sheet a little to do it, first of all, we're kind of totally back in line, and we never broke it. And I think we would be very mindful of looking at M&A that required our balance sheet to come into play in any way. I don't think our shareholders would be, at all, supportive of that, and Lord knows I know that the rating agencies' tolerance for that has definitely waned. So anyway, Sean, I don't know if that's the kind of color that you -- we're giving you on the M&A thing. You know that other than New Brunswick Gas and St. Lawrence Gas, no M&A is included in our $7.5 billion. And as you said, it's an ambitious plan. I think it's totally executable. It will drive continued growth of our EPS to support our DPS growth objectives. But it's certainly not premised on us doing any further M&A.

[Sean Steuart, Research Analyst]

Okay. That's great context. Just a follow-up on the Watay project. I've shortened it. When do you guys start deploying capital? And can you give us some context on expected economics, returns for you guys on that investment?

[Ian Edward Robertson, CEO & Director]

Well, it's a regulated asset, and as you know, with the rates of returns determined by the OEB. Right now, the project is seeking its LTC, its leave-to-construct, for the next phases of the project. And that's a regulatory process which is currently underway. One way to think about it from a return point of view is, as I said, to think about it as -- this is practically a dollar-for-dollar investment in a regulated asset -- transmission asset here in Ontario. There isn't a long and rich history of ROEs in the same way as you can look to FERC. But I think a single-digit, a high single-digit ROE is probably -- is not an unreasonable way to think about it. And so I think we are enthused by this opportunity in the same way as we're enthused at putting capital work in the rest of our regulated utilities. That's maybe one way to look at it, with the added benefit, as I mentioned to Nelson's question, which is -- I think this positions us to be part of what's happening, obviously, in Ontario with the, I'll say, privatization opportunity for private capital to come to bear for the transmission system.

[Operator]

The next question is from Mark Jarvi with CIBC Capital Markets.

[Mark Thomas Jarvi, Director of Institutional Equity Research]

You probably don't want another question on Atlantica Yield, but I'm going to come at it again here. So if a buyer came in, did go private and they wanted to sort of change the business model, not just being operating but also explore development, would you guys be okay with that structure? Or would you want to defend the position where you want to keep it as operating, particularly -- or majority of operating assets in a high-payout vehicle?

[Ian Edward Robertson, CEO & Director]

Well, I mean, it's hypothetical. But then let me give you a hypothetical answer, Mark. From our perspective, we see our international development team, AAGES, creating investment opportunities for us. As you know, we're generally not in the buy-and-sell mode for projects. If a new owner, now we're back to your hypothetical, new owner came in who had an appetite for investing in development of new projects, well, then we'd certainly let them fund a portion of the AAGES costs because we're not really in the business of building to flip, so to speak. And so I don't -- now you talk about if they wanted to change the entire business model. I don't know. We'd have to have the conversation. We know why we invested in Atlantica. We know what role Atlantica is supposed to play in us. Would we be open to a rational conversation about someone who wanted to help, share and invest in some of the development costs for some of the projects that will ultimately find their way in that vehicle? Of course, that would be a rational thing from our point of view. That isn't the model right now, as you know, but of course, I think we'd be open to it.

[David Bronicheski, Chief Financial Officer]

And I would just add, I mean, I think we're very confident in our development capabilities within AAGES. And to be quite honest, that's not an easy platform to recreate sort of overnight. And so I think any objective investor coming in is going to be quite attracted to the development platform that we have.

[Ian Edward Robertson, CEO & Director]

Well, you might actually argue that an investment in Atlantica isn't really about just buying the existing portfolio of assets. I get it. That portfolio of asset is probably undervalued in today's marketplace. But the real opportunity for an investor who comes into Atlantica and using your hypothetical on a go-private transaction has really got to be more enthused about the opportunity to put that next $1 billion to work or the $1 billion dollars after that rather than the $1 billion it would take to take Atlantica private.

[Mark Thomas Jarvi, Director of Institutional Equity Research]

Okay. That's helpful. And then maybe switching gears a little bit. A quick question on -- some of the assets you guys acquired a while ago like the Gamesa Wind assets had an option to acquire them post -- I think it was like around 2020. Have you guys had any discussions on that or any views around maybe buying out the tax equity post flip or post...

[Ian Edward Robertson, CEO & Director]

Yes. So let's be -- you know how the typical structure works. It's that after the PTCs are done, there's a 5% continuing interest in these projects, I'll say, from year 11 onward. I think it's not unreasonable to say that the normal course would see the original developer acquire that 5% interest. We, in all of our models, assume that we acquire it back out. I think the very first project, and maybe I'm wrong, Mark, is 2021, if I'm not mistaken, that -- and so -- but we fully would expect not to have tax equity as a post-PTC partner, if that's where your question goes. But they're 5%, so it's not a huge opportunity, but we definitely assume that we do.

[David Bronicheski, Chief Financial Officer]

And generally speaking, the tax equity investors, their business model isn't predicated on sticking around with that 5% as an item.

[Operator]

The next question is from Jeremy Rosenfield with Industrial Alliance Securities.

[Jeremy Rosenfield, Equity Research Analyst]

I just wanted to touch on the subject you talked about previously with Walker Ridge and PG&E's bankruptcy and if you could just sort of clarify what the potential impacts could be for that project specifically. And since we're only allowed 2 questions, I'll pancake in other questions on PG&E's bankruptcy, if there are any other impacts for other assets that you hold, and I'm thinking of Sanger. And then more broadly, is there any impacts for CalPeco in the California environment? Sorry, that's one.

[Ian Edward Robertson, CEO & Director]

You're a trained professional, Jeremy, clearly. No worries. So let me start with Walker Ridge. And I tried to kind of give the color in my prepared remarks. Everybody thinks of that December 31, 2020, as a hard cliff deadline for the 100% PTCs. But the reality is it's really just the 2020 happens to be the end of, I'll call it, the safe harbor for proving continuous construction. And so consequently, there's a reasonable interpretation to say that if force majeure somehow intervened and delayed your continued construction, that you wouldn't be penalized by that in terms of the interpretation of the tax regulation. So what that actually means, and I think the California fires are a perfect example of force majeure, to the extent that the Walker Ridge project was not commissioned in 2020 but was commissioned in 2021, I think there's a reasonable argument to say that, that project may still qualify for 100% PTCs. I will add, though, that historically, I have said that the Walker Ridge project economics are sufficiently strong and the California market is sufficiently deep and robust that Walker Ridge is actually an attractive project even with the 80% PTC. So I'm not saying this is a gift because we've been working on this project as a 2020 project, but it certainly doesn't spell doom and gloom for Walker Ridge as a result of, I'll say, the uncertainty of these 10 seconds as to whether we can make the 2020 deadline. So there's your -- there's the first part of your three-bie. The second part of your three-bie was something about PG&E and its impact across your entire portfolio. And most broadly, it's relatively limited. I think we may have quantified it. It's around 1% of our EBITDA is subject to PPAs that are with PG&E, and that's primarily Sanger and our Bakersfield II Solar project. The Sanger PPA actually expires, I'm going to say, next year or the year after. But there isn't much left on that PPA, so it's not like there's a huge inherent value proposition associated with that PPA. Bakersfield, obviously, is a little bit more -- a little bit younger, and so therefore, there is probably exposure. Though I will say it was more recently negotiated, so the "over market" nature of that PPA is certainly, I'll say, less apparent when you look at the price. I think you have to layer in on top of that how do you think things with PG&E ultimately unfold. And right now, the general thinking is PG&E is paying their bills. If you listened in on Santiago's call for Atlantica yesterday, he confirmed that PG&E actually paid the Mojave bill for the post-filing period. So subsequent to filing for energy delivered after January 29, they received a check for it. So I think PG&E is making good on their "It's business as usual until it's not business as usual anymore." So I think we're sort of cautiously optimistic that things will continue on. And as you know, the bankruptcy judge is the same bankruptcy judge who presided over the 2000 bankruptcy of PG&E, in which all of the PPAs were ratified and preserved kind of in the way that Gavin Newsom, the governor of California, and the CPUC have suggested they like to have happened. So I'll say no panic right now with PG&E. Now your -- and then your -- the third part of your three-bie was "So tell me about CalPeco and PG&E." Well, specifically with PG&E, there's no exposure. You may or may not be aware we don't have, really, any dealings with PG&E. We are a sister to PG&E, not a -- they're not a supplier of ours in any practical way. And in fact, just physically, most of our energy comes from Nevada rather than from California, so we're not arguably in the same market. And so I don't know if that kind of speaks to you all 3 elements of your questions, Jeremy.

[Jeremy Rosenfield, Equity Research Analyst]

Yes, that was pretty comprehensive. I don't want to harp on it, but I was wondering if CalPeco has sort of an opportunity if there were parts of the system that were adjacent or could be opportunity for CalPeco to expand into service territory that PG&E may have had that may now be subject to question as to whether they should retain or something like that.

[Ian Edward Robertson, CEO & Director]

Well, clearly, like any good vulture, we'll circle above the carcass if that's where your question is going. Well, I mean, I think there are some questions about PG&E's footprint and is it optimal going forward. I think one of the questions, I would say, that you didn't ask is I think there's a heightened opportunity, and maybe this creates an investment opportunity, maybe you can say investment obligation, to be thinking about our system with respect to resiliency and redundancy and hardness with respect to fire prevention going forward. I think what befell PG&E certainly causes every electric utility in California to sit up and take notice, and we are -- we do that ourselves. And so we are looking at how do we make our system more resilient, more robust, opportunities for investments in wildfire protection capital. So I think there -- I think -- I want to say there's an opportunity because I hate to look at what is obviously, a tragic outcome is creating an opportunity. But I think the practical matter is that we need to invest further in our system to preserve it. So yes, so something good will come of something bad.

[Operator]

And our final question is from Nicholas Campanella with Bank of America Merrill Lynch.

[Nicholas Joseph Campanella, Research Analyst]

Just a follow-up on CalPeco there. You guys just recently filed wildfire plans as part of the wider SB 901 mandate. Is there capital in those plans that will be incremental to your base plan right now? And then I'm just also curious, how do we think about your wildfire insurance for '19?

[Ian Edward Robertson, CEO & Director]

Well, I mean, so I'll say, yes, the wildfire plan addresses sort of all aspects, both operational and capital. So the short answer -- is there incremental capital? Yes, there probably is. But let's keep in mind the size of CalPeco against our organization. So I'm going to tell you it's a least significant digit from an estimate perspective in terms of our total capital plan in terms of the incremental -- any incremental capital that wasn't already reflected in our budget. I think that, I would say, the question you asked about wildfire insurance, I think that is a very big California-focused question. As you know, California and Alabama are the only company -- or states in the union that have kind of a total liability paradigm from a utility perspective in that you don't actually have to be found to be imprudent or negligent for risk -- for liabilities to accrue. And so I think it's very difficult to imagine that customers would or should pay sufficient insurance to be able to insure against the breadth of that kind of exposure. It is just a fact of life operating in California. I think the more practical mitigation approach to dealing with wildfire risk is to manage your system in a prudent way to invest in vegetation management, and I'm telling you that's an area -- while it's a pass-through from a cost perspective, it's an area we're very much examining. You need to make your system resilient to these sort of challenges. Climate change is definitely changing the composition of the forest floor and the fuel sources for fires. And while we can't insure against them, we can ensure -- take all measures to ensure that we don't start them and we're not involved in them. And so insulation-coated transmission lines to be -- to allow tree strikes not to create fire, those are the type of things that, if you want to talk about incremental capital, that you'd want to put in there to be able to harden your system against that risk. Practically, the only possible -- we obviously carry insurance, but $30 billion of liability from the Paradise fire could never have been insured against. It's just not practically possible, Nick.

[David Bronicheski, Chief Financial Officer]

And I will also say, I mean, I presume it's not lost on people from a climate perspective and a weather perspective, our Lake Tahoe utility is decidedly different than other parts of California. I mean, it actually does precipitate 75 days a year. They get 50 inches of rain and 400 inches of snow on average annually. So yes, we take fire seriously, but the climate is a significantly different climate than many other parts of California.

[Operator]

This concludes the question-and-answer session. I would like to turn the conference back over to the presenters for any closing remarks.

[Ian Edward Robertson, CEO & Director]

Thanks very much, operator. And I appreciate everybody taking the time. I'll say we're pleased that I say another successful year is behind us in terms of 2018, but we are enthused and excited about what 2019 will bring. Maybe just a quick comment of welcome to Johnny Johnston, who's joined us as Chief Operating Officer from National Grid. And so we welcome Johnny to the team. And many of the questions and issues that came up on the call today are falling squarely into Johnny's responsibility. And so welcome, Johnny. And with that, we'll leave you all with our riveting financial disclaimer. Ian, take it away.

[Ian Tharp, Vice President, Investor Relations]

Thanks, Ian. Our discussion during this call included certain forward-looking information that is based on certain assumptions and is subject to risks and uncertainties that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Forward-looking information provided during this call speaks only as of the date of this call and is based on the plans, beliefs, estimates, projections, expectations, opinions and assumptions of management as of today's date. There can be no assurance that forward-looking information will prove to be accurate, and you should not place undue reliance on forward-looking information. We disclaim any obligation to update any forward-looking information or [ to explain ] any material difference between subsequent actual events and such forward-looking information, except as required by applicable law. In addition, during the course of this call, we have referred to certain non-GAAP financial measures, including, but not limited to, adjusted net earnings, adjusted EBITDA, adjusted funds from operations and adjusted earnings per share. There can be no standardized measure of such non-GAAP financial measures, and consequently, APUC's method of calculating these measures may differ from methods used by other companies, and therefore, they may not be comparable to similar measures presented by other companies. For other information about both forward-looking information and non-GAAP financial measures, including a reconciliation of the non-GAAP measures to the corresponding GAAP measures, please refer to our most recent MD&A filed on SEDAR in Canada or EDGAR in the United States and available on our website. Thank you.

[Operator]

This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.