Algonquin Power & Utilities Corp. (AQN) Q4 2018 Earnings Report, Transcript and Summary

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. As a reminder, all participants are in listen-only mode and the conference is being recorded. After the presentation, there will be an opportunity to ask questions. [Operator Instructions] I would now like to turn the conference over to Christopher Gerhardt, Vice Chair of Algonquin Power & Utilities Corp. Please go ahead, Mr. Gerhardt.

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 Gerhardt, and I am 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 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 on 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 will then open the lines up for questions and as usual we have to restrict your questions to a maximum of two and then re-queue if you have additional questions. And with that, I am going to turn things over to Ian to start with the 2018 highlights.

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 on the progress we have made over the entire year. And looking in that rearview mirror, we see a number of corporate achievements supported by another solid year with financial performance. We will then spend some time looking in a bit more detail their plans in the current year and also longer term as our team works on successful persecution against our five-year strategic plan. So, given that this year 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 business has 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 are pleased that we exited 2018 on solid ground from the credit metrics perspectives. And lastly, we are 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 business as our Board of Directors approved 10% increase in our dividend again in 2018. Secondly, 2018 saw 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 generated 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 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 plants 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 continue our history of successful M&A with our initial entrée into the Canadian utility marketplace to the announcement of an agreement for the acquisition of the provincial New Brunswick Gas franchise and acquisition is expected to be accretive and provide opportunities for future growth. Lastly, we advance our commitment to investor owned electric transmission here in Canada by partnering with Fortis in our respective First Nation partners. We are confident this has combined electricity transmission project will greatly improve energy accessibility and reduce environmental impacts for ‘17 remote First Nation’s 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 $7.5 billion line of sight pipeline of growth opportunities, which our business groups are committed to capitalizing on over the coming five years. Within our Liberty Utilities businesses, we have an extensive array of organic investment initiatives underway with the focus on providing new solutions to customers, while maintaining competitive utility rates, specifically we are focused on accelerating Liberty Utilities’ transition through our renewable energy supplies and improved energy accessibility with our greening the fleet initiative. Within Liberty Power, a total of $2.2 billion investment is expected to be allocated to nine separate power projects in North America and also toward international growth such as our ATN3 transmission line which you have heard about in Peru. And finally, we remain committed to maintaining a sustainability and to drive to operational excellence as core components of how we operate our business. And with that, I will turn things over to David for our overview of our Q4 and full year 2018 financial results. David?

Thanks, Ian, and good morning, everyone. As you had mentioned, referenced at the start of the call in 2018 APAC has again showed its ability to grow its business in an accretive 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 non-cash 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 the full year basis, our adjusted net earnings per share grew by 16% to $0.66 per share. We posted the 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, an incremental HLBV income of $63 million. These were slightly offset by a 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 an increased operating expenses. Further, improved contributions from our electricity and natural gas facilities were slightly offset by lower results from our water distribution and waste water facilities. Now, I would 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 that 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 the majority of our regulators covering approximately 93% of our customers. This resulted in orders that lower 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 also 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 capital structure. In 2018, we completed two common equity financings for total proceeds of approximately C$617 million to accretive really 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 the total of $287.5 million worth of 60-year non-call five 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 are also quite proud of the fact that we recently issued our inaugural green bond earlier this year, prices of C$300 million ten-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 will hand things back over to Ian.

Thanks, David. Before we open up the lines for question, I want to spend a few minutes on some of our growth opportunities. As typical in early December timeframe, 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, pre-empting some of the questions that might be on your minds 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 noted that the Liberty Power portion of this program has increased from that which was presented at Investor Day and it 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 project, we are focused on advancing construction for seven facilities, which in the aggregate would add over a 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 [inaudible] projects, which are part of the greening the fleet opportunity in Missouri and Kansas. 80 megawatts represented by our Phase one of the Broad Mountain project in Pennsylvania and lastly Sugar Creek and the Sandy Oaks expansion both in Illinois. And while development is pressing ahead on the Walker Ridge project of which I have spoken to you in the past, I would know that our development efforts have been partially frustrated by the California wildfires, which understandably occupied the U.S. Bureau of Land Management, who are responsible for processing our [inaudible] application. And the bankruptcy of PG&E, who are the interconnecting utility and while we are disappointed by the delay we are pleased to note that the regulations that governing U.S. PTCs recognize 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 complete until early 2020, we are hopeful that we will still qualify for 100% PTCs. And in respect to all of these projects we are wrapping up 2020 turbine delivery slots with an agreement with from Vestas and EPC contractor 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 noted in our MD&A, we have now acquired a 100% of the project interest from 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 our commence sort of construction later this year. And for those of you who are -- who have active Google web crawler alerts, you will have noticed that AGGES is active in RRPs piece for our 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 I assured I wanted to highlight them to give you some insight into the types of opportunities on which AGGES has engaged. For Liberty Utilities in addition to our normal course capital investment programs and reliability initiatives, we are focused in 2019 on a number of major capital investment programs. As you know that renewable energy has been that the forefront of our company since we founded at 30 years ago. As outlined the cornerstone of our Greening the Fleet program is that 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 doc is for filed last quarter and we are 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 two 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 are 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 with -- 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 have teamed up with Fortis for the development of this important project and while we are excited about investing in this C$1.6 billion 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 entrée into the regulatory 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 am proud of the value created for our shareholders during 2018 and grateful for our talented team. I think they have proved that in agile, entrepreneurial, culturally aligned team, all rowing in the same direction is clearly a powerful force. We have set an ambitious growth plan for ourselves and we are committed to standing our track record of creating shareholder value in the current year and beyond. And with that, I will turn things over to the operator to open it up for questions. Operator?

Thank you. [Operator Instructions] Our first question is from David Quezada from Raymond James. Please go ahead.

Thanks. Good morning guys. My first question here…

Good morning.

Good morning. My first question here is just on, I have been there’s a line item in the MD&A higher operating costs at Empire and Granite State. I am just wondering if you could provide any color on that?

Really it’s just I think in the quarter was just a matter of timing and you know we are also increasing our capabilities in those regions on a number of fronts from an administrative point of view.

But 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.

Okay. Okay. Great. Thank you. And then my other question here on AAGES, obviously, there is a couple of moving parts there at Atlantica, sounds as those things with the bidding there on new projects are proceeding as normal. Is there any potential for change your strategy on AAGES and the drop downs into Atlantica depending on how things play out with PG&E in the strategic review?

Well, I mean, a big question there David and it’s probably worth a little bit of longer answer. As I have said in the past, Atlantica is an important vehicle for us. It gives us an appropriate place into which to drop asset that are -- of 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 there’s 10 seconds, there’s probably 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 are obviously supportive of this strategic review that is targeting improving the cost of capital for Atlantica and so we are supportive of that. In terms of change of strategy from our perspective, you know that it obviously AAGES is itself is not directly involved in Atlantica, that’s a joint venture we have with Abengoa. And AAGES is actively working away on, on development projects. And I certainly hope that those projects could find their way into Atlantica. To the extent that it 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. Because I think it is 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 a final thoughts on the strategic review committee for Atlantica, we are not on that committee obviously I think it’s appropriate given our ownership 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 have got an investment in that company and it will be a great tool if it could be sharp head enough for our tool box, right. I don’t know if that answers your question David but.

It certainly does. That’s great color. Thanks, Ian. I will get back in the queue.

Yeah. It was -- I am sure I am sure it was a long answer to a short question, so.

That’s okay.

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

Great. Thanks. Good morning, everyone.

Hey, Nelson.

Quick one, can you give a bit more background in terms of how you got involved in the Northwest Ontario transmission line. I don’t want to attempt to pronounce the project names. 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 and…

Yeah.

…with your close to I will call it a 10% stake, I presume that’s like your capital commitment is about 10% of that, so.

Yeah.

This is like a I guess maybe it’s a long question with a short answer, but depending on what you could say, but is there a longer or bigger picture play in terms of Northwestern Ontario, given that you only have 10% now and is that…

Yeah. So…

Yeah. What does the angle there?

Yeah. So let me give you a little of -- I will say background and color, and Nelson, if you kind of flip back to some of our MD&As from a few years ago, you will note that we were pursuing a project in Northwestern Ontario with the two First Nations [ph] partners the mission the [inaudible] band and sort of a similar, but perhaps, not as ambitious project in terms of scope. At the same time, I guess, in parallel our 22 First Nations band 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 joined the group of 22, it 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 our First Nations partners. And maybe just to put some color on that, the First Nations partners, this is a First Nations’ communities led initiative with 51% of that -- of the project and so between Fortis and ourselves we have got our 49% of share in that 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 inter-Connecticut, 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 represents 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 that our home province, I think we had 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, we will welcome. Well, we hope so and but you have got to get the first park in the net to for your 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 are looking for Nelson.

Yeah. No. That’s fair. That’s really good color. Now I was just also wondering whether there were generation opportunities you can do there by getting involved in that transmission line?

Well, I don’t know if I say we have a particular, I will say, monopolistic look 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 am thinking of the opportunities from a mineral exploitation perspective in that area, god, can’t help it think that you have now just created an economic opportunity for new, perhaps, hydroelectric wind project. So I think it’s good news for the entire IPP sector, when you start to -- can open up areas that were previously economically accessible.

Okay. Great. And then moving on to my second question, you mentioned that the, I guess, the generation segments capital investment increase, because you have 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 I remember rather than a cash flow item?

Yeah. I think that’s a fair way to characterize it. In our $7.5 billion grow program that we laid out last year, we have 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 what 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 five-year program. So, I think, I agree with you, I think, that your characterization is correct.

Thank you. [Operator Instructions] Our next question is from Ben Pham with BMO. Please go ahead.

All right. Thanks. Good morning.

Good morning, Ben.

Good morning. Thanks. I wanted to go back to the question on a lot of your strategic review.

Yeah.

And I guess, I know you are not involved with the committee and whatnot and I guess the ideal scenario is you have a low cost players step in pick up the public equity and then you can, that’s how it drop downs. But I guess is there scenario where it may not be conducive to you guys where you may have to revisit your ownership percentage?

Well, let me start by saying, Ben, we are neither sellers nor actually candidly buyers in this process on the basis that not owning, not controlling Atlantica is an important element of this thesis around that vehicle. But we are not sellers of that vehicle either. And so 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 are 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 good for everyone. There’s 58.5% of the public capital of the shares are held in the public capital markets and I think this 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 are 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 41.5% shareholder.

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

Yes. Okay. Thanks for clarifying and that makes a lot of sense. And then on the ATM, should we think about the ATM as just kind of like the external equity portion and that’s funding part of you guys provided last December?

Yeah. It’s just another tool to the tool box is kind of how we are 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 in typical two shelve spread that are put up there you often just put a little bit more than you might ultimately need just to make sure that you have got a little bit of flexibility. But there is -- at this point in time no pre-determined level of exercise of that program that’s been determined by our Board. We will 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.

Okay. All right. Got it. Thanks everybody.

Thanks, Ben.

Your next question is from Rob Hope with Scotia Bank. Please go ahead.

Good morning, everyone.

Hey, Rob.

I want to go back and revisit Atlantica and I appreciate your prior comments on leaving projects in AGGES. 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 that would be dropped down to Atlantica eventually. So how are you thinking about that project with the uncertainty at Atlantica?

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

Yeah. 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 have seen CapEx move up a little bit. Is this kind of why you brought the ATM and then you can lean on that a little bit to maintain your metrics?

Two comments on there. The equity raise in December was really a specific to our announcement that we were acquiring New Brunswick Gas and so that equity offering was, I will 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 common place in the U.S. and are becoming increasingly common here in Canada. But we don’t have any pre-determined amount of equity necessarily that we can or will issue off of that. I mean there is issuers here in Canada that have ATM program, some have used it, some have it and so we just wanted to make sure that we had additional flexibility for us over the next 20 months.

Thank you.

Okay, Rob.

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

Good morning, everyone.

Hey, Rupert.

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

Yeah. So I’d say we are resetting to different level of costs within the Power group, but that’s really because we have decided to form a single worldwide development platform through AAGES and so there is 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 reshifting of the income statement if you will.

Okay. So those will be mostly developing costs and I suppose?

Correct.

Yes.

Okay. Excellent. And on Amherst so acquire 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?

Yeah. I mean, one way to think about it Rupert is that, it was always contemplated I think over the five-year program that Amherst, the other half of Amherst would come home. And so, when you know our third-party partner as you know was the EPC contractor and but a large share of those of the cost 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 why I was saying is, we both funded equity in the project to get it up and get it going and get it through construction. So, but I will say that the equity interest in comparison to the total project cost where we are 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.

Yeah. Yeah. All right. Very clear. Thank you.

Great. Thanks, Rupert.

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

Hey, there. Good morning team.

Good morning.

Yeah. Good morning, Nicholas.

Hey. So I just wanted 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?

We don’t provide that as public guidance in terms of cross-border structures for obvious reasons. But let me just comment kind of generally. I mean, we avail 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 are -- we have got a lot of smart people all of the accounting firms also have a lot of smart tax people as well and so we are looking at alternative structures that can give us the same or similar benefit to which we are 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.

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

Well, I mean, that will be determined on the outcome of the rates once they are final in June and we have 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.

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

And I would add one other thing on the cross-border structures. I mean -- and this is has been, I will say from day one, 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.

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 you know it sounds like the general strategy is not dependent on AY success. So it’s -- 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 you are framing that?

No. I mean, I think, Nick, you have probably heard me say that last year when we announced our intention to, I will 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 hold I will say the other half of those opportunities and we do want somebody hold the other half of those opportunity just because the nature of our projects and transmission projects in Chile or whatever are generally more highly levered than we would do on our domestic balance sheet. I don’t say we are indifferent to who holds the other half this projects. We would like it to be in Atlantica. I think it could be Atlantica. But clearly they have got a cost of capital challenge which their Board acknowledges and try to fix. But it certainly doesn’t change our growth plans or our growth trajectory and that was kind of my comment to answer to do something like Sugar Creek. With respect to the growth and maybe we just give you a comment on the dividend. I think you know the people who look at Atlantica, I know your team does do that. I think we are comfortable at this 10 second 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 was it withheld for a payout ratio less than one 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 that threat for Atlantica being a tool in our tool box is having shareholders and the other half of that, I used the word, but the other half of that vehicle who have an appetite for a depreciation of the appropriate discount rate for international infrastructure projects and so were cheering Atlantica on, but to the extent that they are unable to solve the problem that will slow it down one iota, Nick. I hope that sort of add some perspective to how we think of Atlantica.

Absolutely. I appreciate that. I will get back in the queue here. Thank you.

Yeah. Thanks, Nick.

The next question is from Sean Steuart with TD Securities. Please go ahead.

Thanks. Good morning, everyone.

Good morning, Sean.

A couple of questions. You have got a full plate with growth clearly, but wondering if you can comment on how the M&A opportunity set for utilities. North America has developed. What is the opportunity that look like and what’s your appetite for acquisitions at this point?

Well without telling stories of this goal, you obviously know that Emera has been very public about addressing some of their balance sheet challenges through the sale of Emera Maine and we obviously 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 I don’t know how that’s going to turn out. But sticks on the ice Sean don’t know if the parts coming our way. More broadly you have 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 with something better be strategic realigned it 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 accommodation of the capital markets to tolerate organizations that stretch their balance sheets to accommodate M&A. Those days have shut off, the sun has set on those days and so while we are proud of the fact that we are able to complete the acquisition of Empire and maybe we stretched our balance sheet a little to do our first hand we 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 wane. So anyway Sean I don’t know if that’s kind of comment that you -- we are 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, 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.

Okay. That’s great context. Thanks. Just follow-up on the [inaudible] project of short net.

Check-in.

When do you guys start deploying capital and can you give us some context on expected economics returns for you guys on that investment.

Well, it’s a regulated asset as you know with rate returns determined by the OAB. Right now the project is seeking it’s LTC, leave to construct for the next phases of the project and not 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, our transmission out 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 to high single-digit ROE is probably it’s not an unreasonable way to think about it. And then so you know I think we are enthused by this opportunity in the same way as we are enthused at putting capital work in the rest of our regulated utility that’s maybe one way to look at it. With the added benefit as I had answered to Nelson’s question which is I think this positions us to be part of what’s happening obviously in Ontario with the, I will say privatization opportunity for private capital will come to there for the transmission system.

Okay. That’s great. Thanks, Ian.

No worry, Sean.

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

Hey. Good morning.

Hey, Mark.

You probably don’t want another question on Atlantica Yield, but I am going to come at it again here. So if a buyer came in and this did go private and they wanted to change the business model not just been 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 you are operating assets and a high payout vehicle?

Well, I mean, it’s a 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 are generally not in the buy and sell mode for projects. If a new owner, now we are about our hypothetical, new owner came in who had an appetite for investing in development of new projects, whether we certainly let them fund a portion of the AAGES costs because we are not really in the business of building to flip so to speak. And so -- now you talk about if they wanted to change the entire business model, I don’t know they have to have the conversation, we know why we invested in Atlantica, we know what role Atlantica is suppose to playing us, would we be open to a rational conversation about someone who want to help share and invest in some of the development cost for some of the projects have ultimately find the way in that vehicle, well, of course, that will 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 will be open to it.

Okay.

And I would just have I mean I think, we are very confident in our development capabilities within AGES. 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 attractive to the developer platform that we have to…

Well, you might actually argue that, an investment in Atlantica isn’t really about just buying the existing portfolio of asset. 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 the next billion dollars to work, put a billion dollars after that rather than the billion dollars it would take -- to take Atlantica private.

Okay. That’s helpful. Thanks. And I mean…

All right.

…here’s a little bit, a quick question on, some of the assets you guys required a while ago [inaudible] wind assets had an option to acquire them post like you are on 2020. Have you guys had any discussions on that or any views around maybe by now the tax equity post-flip or post…

Oh! Yeah. So let’s be, how the typical structure works is that after the PTCs are done, there’s a 5% continuing interest in these projects I will 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 acquired back out. I think the very first project and maybe I am wrong Mark is 2021 if I am not mistaken that and so that, but we fully would expect not to have tax equity as a post-PTC partner, if that’s where your question goes? But they are 5%. So it’s not a, it’s not a huge opportunity but we have definitely assumed that we do.

And generally speaking the tax equity investors their business model is a predicated on sticking around with that 5%.

Right.

...have been native.

Yeah. Understood. Thanks guys.

Hey. Thanks very much.

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

Yeah. Thanks. 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 impact could be for that project specifically? And since we are only allowed two questions I will pancake in other questions on PG&E’s bankruptcy. If there are any other impacts for other assets that you hold and I am thinking of Sangar? And then more broadly if there are any impacts for Calpico in the California environment. Sorry that’s…

So and I tried to kind of give the color in, in my prepared remarks, everybody thinks of that December 31, 2020 as a hard cliff deadline for 100% PTCs. But the reality is, it’s really just the 2020 happens to be end of I will 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 regulations. So what that actually means and I think the California fires are a perfect example of force majeure to the effect 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 that California market is sufficiently deep and robust that Walker Ridge is actually an attractive project event with the 80% PTC. So I am not saying this is a gift because we have 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 will say the uncertainty at this 10 seconds is whether we can make the 2020 deadline. So there is your, it’s a first part of your 3D. The second part of your 3D 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’s around 1% of our EBITDA, it’s subject to PPAs that are with PG&E and that’s primarily Sanger and our Bakersfield two solar project. The Sanger PPA actually expires I am going to say next year or the year after. But there isn’t much left on that PPA. So it’s not like there is a huge inherent value proposition associated with that PPA. Bakersfield obviously is a little bit more -- little bit younger and so therefore there is probably exposure. Thought I will say it was more recently negotiated so that over market nature is that PPA is certainly, I will 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 Santiago 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 29th, 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 are 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 in the CPUC have suggested they’d like to have happen. So I will say no panic right now with PG&E. Now you are more and then you are the third part of our 3D was, so tell me about CalPeco and PG&E. Well, specific to 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, they are 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 are not arguably in the same market. And so I don’t know if that kind of speaks to the all three elements of your question Jeremy.

Yeah. That was pretty comprehensive. I don’t want to harp on it but I was wondering if CalPeco had 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 PG&E may have had that may now be subject to question as to whether they should retain or something like that?

Well, clearly, like any good vulture will circle above that target if that’s where your question is going. Well, I mean, I think there are some questions about PG&E’s footprints and is it optimal going forward. I think one of the questions I am going to 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 we felt PG&E certainly causes every electric utility in California to sit up and take notice and we do that ourselves. And so we are looking at how do we make our system more resilient, more robust opportunities for us for investment in Wildfire Protection Capital. So I think I am going 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, yeah, so something good will come up something bad.

Yeah. Okay. Good. Thank you that’s it from me and I will leave it there.

Thanks, Jeremy.

And our final question is from Nicholas Campanella with Bank of America and Merrill Lynch. Please go ahead.

Hey. Just a follow up on CalPeco there. You guys just recently saw an wildfire plans as part of, part of the wire SP 901 mandate. Is there capital in those plants that would be incremental to your base plan right now. And then I am just also curious, how do we think about your wildfire insurance for 2019?

Well, I mean, so, I will say, yes, the wildfire plan addresses sort of all aspects, both operational and capital. So the short answer is our incremental capital. Yeah, there probably are, but let’s keep in mind the size of CalPeco against our organization. So I am going to tell you it’s a least significant digit in the 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 -- states in the union that have kind of a total liability paradigm from a utility perspective and that you don’t actually have to be found to be imprudent or negligent for what’s, for liabilities to accrue. And so I think I think it’s very difficult to imagine that that customers would -- would or should pay sufficient insurance to be able to insure against the breadth of that kind of exposure, it is just the fact of life operating in California. I think the more practical mitigated mitigation approach to dealing with wildfire risk is to manage your system in a prudent way to invest in vegetation management and I am telling you that’s an area, as well as the pass through from a cost perspective, it’s an area we are very much examining you need to make your system resilient to these sort of challenges. Climate change is definitely changing the composition of the force floor and the field source for fires and while we can’t ensure against them we can sure take all measures to ensure that we don’t’ start them and we are not involved in them and so insulation coded transmission lines to be -- to allow tree strikes not to create fire. Those are the type of things that if you want to talk to about incremental capital that you would 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, just not practically possible there.

And they will also say I presume it’s not lost on people from a climate perspective than 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 got 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.

Yeah.

Thank you very much.

All right, Nick. Thanks very much.

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

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

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, belief, estimates, projection, 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 commission. 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 more 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.

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