Executives Chris Jarratt – Vice Chairman Ian Robertson – CEO David Bronicheski – CFO Amanda Dillon – IR Analysts Nelson Ng – RBC Capital Markets Rupert Merer – National Bank Sean Steuart – TD Securities Ben Pham – BMO Capital Markets Paul Lechem – CIBC Jeremy Rosenfield – Desjardins Securities Inc. Algonquin Power & Utilities Corp ( OTCPK:AQUNF ) Q3 2015 Results Earnings Conference Call November 6, 2015 10:00 AM ET Operator Good day, and welcome to the Algonquin Power and Utilities Corp Q3 2015 analyst and investor call. Today’s conference is being recorded. At this time I would like to turn the conference over to Mr. Chris Jarratt, Vice Chair. Please go ahead, sir. Chris Jarratt Thank you. Good morning, everyone. Thanks for joining us on our 2015 third-quarter conference call. As mentioned my name is Chris Jarratt and I’m the Vice Chair of the Board of Directors at Algonquin. Joining me on the call today are Ian Robertson, our Chief Executive Officer, and David Bronicheski, our Chief Financial Officer. For your reference, additional information on the results is available for download at our website. On the call today we will provide additional information that relates to future events and expected financial positions that should be considered forward-looking. Amanda will also provide additional details at the end of the call, and I also direct you to review the full disclosure on the quarterly results page of our website. This morning Ian is going to start with a discussion on the highlights of the quarter. David will follow with a review of the financial results, and then we’ll open the lines for questions. And we ask that you restrict your questions to two and then re-queue if you have additional questions to allow others the opportunity to participate. And with that, I will turn it over to Ian Robertson to review the quarterly results. Ian Robertson Thanks, Chris. Appreciate everybody taking the time today. It’s a blustery, rainy day here in Toronto and I guess given that we have hydro, wind, and solar facilities two out of three ain’t bad in terms of our production. But in summary for the quarter, we believe that the strong quarter results that we’ve posted are evidence of the continued solid growth in the earnings and cash flows from our generation and distribution businesses. We think that this type of growth is clearly the underpinning support for future dividend increases, and frankly it’s the basic investment thesis for Algonquin Power and Utilities Corp. During the third quarter, we realized a 70% increase in adjusted EBITDA, delivering 70.2 million versus the 41.4 million reported during the same period last year. Earnings per share growth was equally meaningful, with $0.06 per share this quarter comparing favorably to the Q3 2014 results. With $0.31 of earnings per share a year-to-date and a strong seasonal quarter in Q4 for us, we are cautiously optimistic regarding the ability to meet or outperform the current consensus earnings estimates for 2015. The year-over-year growth reflects contributions from our regulated and non-regulated business groups, with three renewable energy facilities having achieved commercial operations, positive rate case settlements within our distribution utilities, and the impact of a stronger U.S. dollar for the third quarter. The generation business group experienced natural resources in the third quarter that were lower than long-term averages. It’s a theme that appears somewhat consistent across the IPP sector with some blaming it on the El Nino impact. But happily more than offsetting this naturally occurring volatility the distribution business group had a great quarter, with a 20% overall increase in net utility sales and a 45% increase in operating profit primarily attributed to the implementation of recent rate cases. We believe that this yin and yang proves the effectiveness of the diversification strategy on which our portfolio is founded. So with that little summary of the quarter, I’ll turn things over to David to speak specifically to the Q3 financial results. David? David Bronicheski Thanks, Ian. Good morning, everyone. We’re very pleased to be again reporting strong quarterly results. Our focus on growth is clearly evident. Our adjusted EBITDA in the third quarter totaled $70.2 million, a 70% increase over the amount reported in the same quarter a year ago, which is primarily due to the impact of rate case settlements, commercial production at our St. Damase and Morse wind facilities and Bakersfield I Solar Facility, as well as the stronger U.S. dollar. Adjusted EBITDA for the nine months of 2015 was $266 million, a 29% increase over the amount reported for the nine months of 2014. The benefits of our diversified portfolio of regulated distribution utilities and independent power generation are clearly proving their worth. Moving on to some detail from our operating subsidiaries, in the generation group for the third quarter of 2015, the combined operating profit of the group totaled 35.5 million as compared to 24 million during the same period in 2014. For the nine months, the operating profit of the Generation Group totaled 27 million as compared to 108 million during the nine months of last year. During the third quarter of 2015, the Generation Group’s renewable energy division, which consists of wind, hydro, and solar facilities, generated electricity equal to 93% of long-term average resources, which is up significantly from the previous year. And this increase was primarily due to higher wind resources realized in Canada and the U.S. as compared to the previous year. For the nine months, our renewable energy division generated electricity equal to 90% of the long-term average, compared to 92% a year ago. Moving on to our Distribution Group, in the third quarter of 2015, the Distribution Group reported an operating profit of $32.6 million compared to $22.5 million reported in the same quarter a year ago. The increase in operating profit is primarily due to the impact of rate case settlements as well as contracted utility services. Contracted utility services represents an ongoing source of revenue for Liberty Utilities. This consists of utility services provided on U.S. government owned territories where the operating paradigm requires us to provide utility services under contract rather than through regulated tariffs. In the nine months of 2015, the Distribution Group reported an operating profit of $130.7 million as compared to $108.7 million for the nine months of 2014. Now to touch just briefly on our recent financing activities. On July 15, the Distribution Group issued $70 million of notes representing the second of two tranches of our $160 million senior unsecured financing of April 2015, where we were able to achieve a 30-year private placement with a coupon of 4.13%. The notes have been assigned a rating of BBB high by DBRS. The financing is the fourth series of notes issued pursuant to Liberty Utilities master indenture. I will now hand back things over to Ian. Ian Robertson Thanks, David. Before we open up the lines for questions as is our practice, I will provide you a quick update on some of our growth initiatives. And I will start with the projects that we have under construction. Our 200 megawatt Minnesota based Odell wind project commenced construction in mid-May of this year, and we’re pleased to report that currently all 100 turbine foundations have been completed and the first tower was erected this week. Transmission lines complete, construction of the substations is well underway. The first turbine is projected to deliver energy to the MISO grid in mid-January of next year, with commercial operations in the entire facility scheduled for early next year. I will mention that agreements were finalized during the quarter for the provision of certain tax equity financing to the project. The 10 megawatt Bakersfield II Solar Project, adjacent to our 20 megawatt Bakersfield I Solar Project, is now under construction following the granting of the final building permits during the quarter. Commercial operation is scheduled to begin in the fourth quarter next year. And lastly, during the quarter we were pleased to add another project to our portfolio with the addition of the 150 megawatt Deerfield Wind Project. Construction has now commenced on this project located in central Michigan. Energy from the project will be sold pursuant to a 20-year power purchase agreement with the local electric distribution utilities. Switching to the development pipeline of opportunities, the 75 megawatt Amherst Island Wind Project, located down near Kingston, received its approval to proceed with the issuance of the Renewable Energy Approval, or REA as it’s called, in August. The expected appeal of the REA by certain parties was raised in September. And we will point out with the Ontario Ministry of the Environment, taking over 29 months to comprehensively review and approve our application, we’re confident in the outcome of this review process which is expected to conclude in March of next year. Engineering and procurement of long lead equipment has commenced with the commercial operation of the facility expected in mid-2017. Final permitting approvals for our 177 megawatt wind project located near Chaplin, Saskatchewan, right now are expected to be secured in the next couple of months. Switching to our regulated distribution business group, applications have now been filed seeking a total of more than $30 million in revenue increases in California, Arizona, Massachusetts, and Georgia; and we expect final decisions on these six rate proceedings within the next 12 or so months. With respect to the acquisition of our Park Water company, our water utility located in California and Montana, a settlement agreement regarding approval from the California Public Utilities Commission was reached earlier this year and an order approving the transaction is expected before year end. In Montana, the hearing before the Public Service Commission is scheduled for early January of 2016, and consequently we expect a complete the transaction following the receipt of all approvals early next year. Lastly, with respect to the transmission business group, permitting work is continuing on the $3.3 billion Northeast energy direct natural gas pipeline in which we have an up to 10% interest. In July, we were pleased that Kinder Morgan announced that its Board of Directors had approved proceeding with the project subject to receiving all applicable permits. The environmental review was filed with FERC in June, and filing of the formal FERC certificate application is planned for later this year. Construction is expected to begin in January 2017, with commercial operation targeted for November 2018. The transmission business group development opportunities, with respect to those, we are continuing to expand our presence in the liquefied natural gas business in New England. In addition to the existing facility, which we have under development to serve LDC peak shaving needs, the transmission business group is working with Kinder Morgan to meet additional power generation natural gas loads in the Northeast which were the subject of a recent open season conducted by Kinder Morgan. I would note that several New England states are moving forward with regulatory initiatives to support the pass through, if you will, by electric utilities of long-term gas supply capacity costs, which will obviously help support further infrastructure development. And lastly, our transmission business group is working hard on expanding its pipeline footprint further upstream into New York and Pennsylvania. And while these tidbits and other development opportunities set might seem like teasers, it’s only because they are. For the full story on our growth pipeline, which is approaching $4 billion over the next 4 to 5 years, we would invite you to attend our investor morning being held on December 1st here in Toronto. Details are available on our website or please give Amanda Dillon of our investor relations group a call if you want to hear more about it. And lastly, before we go to questions, I’d like to offer a couple of comments about valuation and perhaps the noted change you would see in terms of our dividend. We believe that our dividend current — our current dividend deal is not fully reflective of the fundamental value of our business. In particular we speculate that perhaps the full Canadian dollar value of our dividend and its growth has not been fully appreciated by the market. Consequently we’ve taken the step of providing our shareholders clarity in terms of Canadian dollar dividend, which is available to our shareholders and in this quarter it is more than $0.125 Canadian dollars. And we hope that this certainty in value helps Canadian investors fully appreciate the compelling investment proposition which we believe that Algonquin provides. So with that, operator, I would like to open it up for the question-and-answer session. Thanks. Operator? Question-and-Answer Session Operator Thank you. [Operator Instructions] Okay. Now, we’ll take the first question from Nelson from RBC Capital Markets. Please, go ahead. Nelson Ng Great. Thanks, good morning everyone. Ian Robertson Great. How you are doing? David Bronicheski Good morning, Nelson. Nelson Ng Quick question on the utility division. I think there was like a large increase in other revenues. I think the disclosure indicates that it was contracted services. Can you provide a bit more color as to like whether this is a like recurring item, or did something one-off take place in Q3? Ian Robertson Sure, Nelson. It is most definitely recurring revenue. I think David had mentioned in his remarks that for services that we provide to let’s call it U.S. government owned facilities you can’t provide — even if we are the utility of record, you don’t get to provide them under the normal state supervised paradigm of regulated tariffs. You provide them under contract. It so happened in this quarter because it’s the summer we obviously did a lot of work on — in one of our facilities that we supply that. But it is ongoing revenue, it just so happens that this quarter happened to be a big quarter because of the summer. But if it is definitely recurring, we are the continuing utility service provider to these bases, and so that’s really the short answer. Nelson Ng I see. So going forward you would see continuing other revenue but generally it’s larger during the summer? Ian Robertson Oh, yes. Of course, I mean, most of the time obviously we do a lot of work during the summer, but yes, it’s just part of the ongoing business, Nelson. Nelson Ng Okay. And then, maybe we could take this offline, but what drove the reduction in interest expense on the renewable division? I think it was down year-over-year and also down relative to Q2, but I think the debt has been I guess flat or higher. David Bronicheski Yes, no. It’s primarily driven by capitalized interest. So we’ve got a number of projects that are under way, and so that’s been I would say the largest driver of that. In addition to that, we retired the LIPSCO bonds, and the LIPSCO bonds, and this is an accounting issue, we’re at a premium because it was on the books at the time. Because of the higher interest rate the bonds carried we retired it, and so that premium went through as is required under GAAP, the interest expense line. I think that was about $1 million I think. But the balance of that was largely just the fact that we’ve got such an extensive capital program that we have higher capitalized interest. Nelson Ng All right. Thanks. I will get back in the queue. Ian Robertson Thanks, Nelson. Operator Thank you. We will now take the following question from Rupert Merer from National Bank. Please, go ahead. Rupert Merer Thanks very much. Good morning, everyone. Ian Robertson Hey, Rupert. Rupert Merer Great quarter. Just a follow up with respect to the contracted services revenues. I see that we’ve had other revenues on that line in the past, but it does seem like quite a large step change. And I understand there’s some seasonality here, but I think if we went back last year it may not have been quite so large. So just wondering has there been any changes in the business that would see a higher sustainable rate in contracted services in the future? Or should we be looking more at a long-term average there? Ian Robertson Well, two things. Let’s point out that it’s the fourth good quarter in a row, Rupert. I didn’t want to cutback. Anyway, in terms of those contracted services, obviously as you can imagine that as projects arise over the course of pipes wear out, things need to be replaced, you just happen to be seeing that in this — with this customer because it happens to be called out on a separate line item. So yes, this quarter did represent — there’s a lot of work that was being done on the bases this quarter, and so it just so happens that they happen to have — should have aggregated together and shown up in the quarter. But as I point out, it’s really very normal course utility operations for us. And while there will be big quarters and low quarters, and as you pointed out last year we didn’t have as big a quarter, this year it happened — there happened to be a lot of projects that needed to be done and it just so happened to have generated substantial earnings. But the business is continuing on, so it’s probably not unreasonable if you want to think about this from your perspective, that there’s just a long-term average that would come out of this and this just happened to be a big quarter. Much as in the way we have other big quarters in other parts of our utility business, it just gets mapped and you don’t see it as — with the clarity because of the accounting treatment. Rupert Merer Okay. Great. And then quickly, you mentioned El Nino and there’s a broad expectation for warm weather in North America. And that could impact your power assets, but looking at the regulated utility business, can you remind us of the sensitivity to the weather and how much decoupling you have right now in your utilities business earnings? Ian Robertson It’s pretty broad based, our decoupling. I would actually flip it around and say their New Hampshire is probably one of the primary jurisdictions where we don’t have sort of solid decoupling from weather phenomenon. So, but in most other states the decoupling mechanisms are pretty effective. Meaning we are pretty insulated from the weather impacts. Rupert Merer What percentage of the … Ian Robertson Sorry, Rupert. Rupert Merer Sorry. What percentage of your earnings you think would be decoupled today? Ian Robertson Well over two-thirds. Well, and I’m speaking just of the utility business, obviously. Rupert Merer Right, yes. Okay, very good. Thanks very much. David Bronicheski And Rupert, I will add, and this will sound like an advertisement for our investor day again, but at our investor day we always provide an annual update on the progress that we’re making in all of our jurisdictions with respect to decoupling and other mechanisms. So we will definitely be providing a full update at our upcoming investor day. Rupert Merer Great. Thank you. Ian Robertson Thanks, Rupert. Operator [Operator Instructions] We will now take the next question from Sean Steuart from TD Securities. Please, go ahead. Sean Steuart Thanks. Good morning, everyone. David Bronicheski Hi, Sean. Sean Steuart Question on the discussions with the Emera with respect to the ownership cap. Has there been any progress there? Any update you can provide for us. Ian Robertson Yes, I will say that the discussions are ongoing. You can imagine we are probably not getting 100% of their attention right now that — with their TECO transaction going through. But as recently as this week, I sat down with Chris Huskilson and — there continues to be strong commitment certainly from the Emera side to their interest, enthusiasm, and excitement for their investment in Algonquin. The work on the strategic investment agreement, I think Chris Huskilson certainly shares my perspective that there are some synergistic opportunities that we can work on together to enhance shareholder value. So I guess I would just say, Sean, that — and I know people have asked the question because of the transformative work that Emera has done with TECO whether there is continued interest. I’d say from our perspective, the relationship feels as strong as it has ever been. Sean Steuart Okay. Thanks for that detail. And just follow up on Mountain Water. Just want to make sure I’m understanding the timing of the appeal for the condemnation, and I guess what happens between now and then and how this feeds into your closing time frame for that acquisition. Ian Robertson Sure. Let me start by saying the whole condemnation process is proceeding in parallel with and really unconnected to the regulatory approval process. Except that I will say that the noise from the condemnation definitely has spilled over to occasion some delays in the Montana Public Service Commission’s approval. The current hearing in that with the Montana PSC is scheduled to believe to start I believe January 16, if I’m not mistaken. And so that’s the regulatory approval process for which we’ve been working with MPSC on. And to be frank, it feels very normal of course for us. In parallel with this has been the whole city of Missoula’s aspirations to own the mountain water system. And that’s been a parallel process in terms of a right to take hearing, which as you accurately point out is under appeal in Montana. But in addition, there is a valuation proceeding, because the next step in a normal condemnation or appropriate expropriation as we would call it here in Canada, is the valuation process. And that’s being held by an independent board of three commissioners who are examining evidence from both sides as to the value of the utility. And their hearing is, if not concluded expects to conclude in the next couple of days with a decision from them probably before year end. And to be frank, if either party doesn’t like the outcome of that decision, there is an opportunity to pursue a jury trial. But I will say that whole condemnation process is independent and unrelated to our acquisition to be frank, when the MPSC completes their work and presumably grants us approval, we will complete and close the transaction; obviously the condemnation will continue on. But that is an under — an ongoing process that anybody who happens to own utilities, and particularly water utilities, which are coveted by the cities that they own, are always open to the condemnation proceedings. And so I will say, Sean, that whole process, you really need to separate the two. And if you’re focused on when we would see the utility join the Liberty Utilities family, it’s really tied to the MPSC hearing. I’m sorry for going on for so long with the answer, but I hope that was — added some more color. Sean Steuart No, that’s great. I appreciate it. Thanks, Ian. That’s all I had. Ian Robertson No worries, Sean. Operator Thank you. We’ll now take the next question from Ben Pham from BMO. Please, go ahead. Ben Pham Okay. Thank you. I wanted to go back to other revenue and then just dig inside a little bit more. And I’m wondering, are you providing — you said utility services to government customers. Is that you’re providing electricity and water? And why is it — why are you characterizing it as contracted? Is it some sort of contract you have in place for a set period of time? Ian Robertson No, well, yes and no, Ben. You can imagine that if a U.S. military base needs water, natural gas service, they don’t obtain those services in the same way as we provide those services under what’s called CC&N, or certificate of convenience and necessity, the way we would do in a normal community and so that you become the provider of those services under extremely long-term contracts. Like 50-year contracts. And so it just so happens that the provision of services to the U.S. government for their bases isn’t provided in a way that from an accounting point of view that it gets lumped in with all of the rest of our utility revenues and utility earnings. It happens to get called out as contracted services because we are the utility provider to that facility, or facilities which are quite large, via contract rather than via a tariff, which is issued and approved by the local state Public Utilities Commission. So it really is the exact same services that we would provide to a customer in Columbus, Ohio or Columbus, Georgia that we might provide to an Army base located in Columbus. Or an Air Force Base located in Goodyear, Arizona versus the customers that we would serve in Goodyear, Arizona. So it really is the exact same business, Ben, and I guess it happens to be step to standing out because this quarter happened to be a big quarter for us in providing services because there were lots of projects that were being undertaken in — on those bases in the summer. And as Rupert had pointed out earlier, yes, it’s a big seasonal quarter. Obviously you do a lot of your construction in the summer, but on an absolute basis it happens to be a big volume just because there was some pent-up demand over the past few years for work that needed to get done. But I would offer up that those revenues shouldn’t — should be thought of as ongoing and consistent recurring revenues, perhaps not in the exact same quantum that they happen to be there, but in the same way as we have yins and yangs in our — in the rest of our utility business across all of our service territories. This just happens to be as I said standout because of the accounting treatment that it receives. Ben Pham Okay. Are you earning the same returns on that? Ian Robertson Yes, we are, sir. Ben Pham Okay. All right. And lastly on Amherst Island, I’m wondering are you — it seems like you are moving ahead with getting the groundwork started before ERT. Is that the plan? Are you going to put a bit of capital before? Ian Robertson Sure. I think we’re highly confident in the outcome of the ERT, as I sort of mentioned in my opening remarks. Gosh, the Ministry of the Environment took 29 months to review and approve our renewable energy application. And to be frank, as you know, the ERT is really a review of the government’s work in terms of the review of the application. And we are highly confident that the government left no stone unturned in terms of their review. And so it makes common sense given that I will say time is money when it comes to projects like this, that we should move ahead on some of the long lead time items. Obviously, we’re doing it prudently, but it certainly represents I think our confidence in the outcome of the process. Ben Pham Okay, got it. Thanks, guys. Ian Robertson Thanks, Ben. David Bronicheski Thanks Ben. Operator [Operator Instructions] We will now take the following question from Paul Lechem from CIBC. Please, go ahead, sir. Paul Lechem Thank you. Good morning. Ian Robertson Hey, Paul. Paul Lechem Good morning. Just a couple of questions around the wind projects under construction, Odell and Deerfield. And you have 50% ownership in those. Just wondering what the terms are to acquire the other 50%? What your decision factors will be, whether you exercise the option or not. And why was it set up this way? Ian Robertson Well, I think in both cases, both Deerfield and Odell, our partners in those projects represent the original developers of those projects. And so clearly you can imagine the community relations, the relations with the — on the permitting point of view they made ideal partners for us in terms of becoming 50/50 partners. I think though having said that, it’s probably totally reasonable to understand that nobody goes into a partnership without a way to exit it. And so there are exit provisions for certainly for up to a buyout in the case of Odell and Deerfield, our 50/50 partners. But that’s certainly not going to happen until the projects get into commercial operation. And we will make the decision at the time as to what makes sense as we look going forward. But we are certainly thrilled to have those guys having a continuing interest. In my mind it’s certainly represents their commitment and belief in the value of those projects. And so what the future holds, don’t really know, Paul, whether we’re going to continue to be 50/50 owners or ultimately buy out our partners and those, which we certainly have the right to do. We will make that decision at the time. Paul Lechem Does the purchase price option — is it at a premium to the original investment or to reflect the de-risking through construction, or is at the same price? Ian Robertson Same price. Paul Lechem Got you. Just on the Ontario market, what’s your level of interest in participating in potential consolidation of the LDCs in Ontario? What would be your competitive positioning in that market if you were to do so? Ian Robertson Well, we obviously have a high interest in expanding our regulated distribution utility business. We would certainly like to participate in the consolidation of electric LDCs. As you know, it’s been a complicated process over the past number of years, largely occasioned by some structures that have been implemented by the government. In some respects I might argue to prevent commercial consolidation to the extent that with the — with Hydro 1 becoming a public entity, maybe the landscape is changing a little. I think our competitive advantages are a cost of capital which is as competitive as anyone from our perspective in the business, but perhaps as importantly a core competency in running regulated utilities. I think I’m very proud with the organization’s track record of providing cost-effective reliable service in all the utilities we provide and man, wouldn’t we love to do it in our own backyard. So I guess from my perspective, Paul, we’re sitting here watching this landscape unfold, but we are cautiously optimistic with the changes from Hydro 1’s perspective that maybe there are some changes afoot and maybe there would be some opportunities for us to participate. So I don’t know if that’s responsive to question. Paul Lechem One follow up on that. Have you actually initiated discussions within any municipalities? Ian Robertson Yes, we certainly have a list and we certainly have had some dialogues with them. Obviously I don’t think it’s appropriate that I disclose with whom with everyone which we’ve spoken, but we have been active in the process, let’s put it that way. Paul Lechem Okay, thank you. Ian Robertson Thanks, Paul. Operator We’ll now take the following question from Nelson Ng from RBC Capital Markets. Please, go ahead. Nelson Ng Great. Thanks. I just want to ask about Bakersfield 1. Could you elaborate on the equipment malfunction and the damage to the inverters? And is it covered — I presume it’s covered by insurance, and do you have business interruption insurance or would you get the missed revenues back some time in the future? Ian Robertson Well, I’ll answer very shortly, Nelson, yes, yes, and yes. But I’ll give you a little bit more color on that. The damage to the inverters occurred during an extremely high volume rain event, and it resulted from the ingestion of moisture into the forced air ventilation system in 3 of the 10 inverter houses. And so the inverters, as you can appreciate, don’t mix well with water. The replacement inverters are on-site and being commissioned as we speak. The repair costs are certainly covered under the original EPC contract. In fact, since final completion actually hasn’t been achieved, even though a substantial completion is there for commercial operations was, this remains the work of the original EPC contractor, and so we’re confident of that. Yes, in terms of business interruption insurance and it’s a 30-day waiting period. To be frank, you can imagine there’s a little bit of complexity with the original contractor as to who is responsible. Is it our insurance company or is it the original contractor to whom we can seek recourse for the lost revenue which is measured in the order of probably $150,000 a month, and so it’s real money. And but that’s the only reason we haven’t made the claim so far, because we’re still trying to sort out all of the contractual liabilities of the various parties. But we’re obviously comfortable that we’ll have recourse ultimately to our insurance company. I think the hope is that within weeks perhaps by the end of this month the plant will be restored to service, and so any lost revenue with respect to it will cease. Nelson Ng I see. Is there any risk of a design flaw for the ventilation system if it got wet because it was raining a lot? Ian Robertson Clearly, there are design changes being made to prevent a recurrence of that water ingestion. I mean the rain event, while being severe; it wasn’t like a tidal wave came from the coast all the way inland to Bakersfield. So clearly the contractor has made design changes, Nelson. And so we’re confident that we actually won’t have a repeat of this. Nelson Ng Okay. That’s good to hear. And then just one last question on the Deerfield wind project. Are you able to comment what level the PPA was set at and how that compares to Odell? Ian Robertson I don’t want to get into the specific numbers of the PPA because you can imagine obviously all the utilities are sort of sensitive to the specific quantum of the rates that are being paid. I think it is fair to say that both of the PPAs were awarded under a competitive process by the respective utilities. I will say that Deerfield enjoys a higher rate than Odell, just for whatever reason. We actually weren’t involved in the bidding of it, but the rate is higher at Deerfield than it is at Odell. But I think really from our perspective as we look at the those projects and we looked at our returns accretion from an earnings perspective, accretion from a cash flow perspective, and from an overall project value on an elaborate after tax IRR perspective, we are a little bit in different maybe agnostic as to the PPA rate as long as the projects meet all of those value accretion criteria which I’m pleased to say that both Deerfield and Odell handily meet. So they’re both solidly in our strike zone from a return perspective, sort of almost notwithstanding the fact that the PPA rates are slightly different. And that’s obviously affecting the total capital cost for the projects are different building in Michigan is different than building in Minnesota. But all in all, they’re both great projects from our perspective. David Bronicheski And Nelson, one other thing in case you may have missed it, as we normally do with projects and acquisitions we have posted a fact sheet on our website, and I’m happy to send it to you if you happen to have missed it. Nelson Ng And I read it and I was thinking like my rough guess was maybe $40, but I just wanted to check in terms of per megawatt hour, but if you don’t want to say it’s fine. Ian Robertson I’m going to be silent right now, Nelson. Nelson Ng All right. That’s great. Thanks again. Okay. Have a good one. Ian Robertson All right, thank you. Operator We’ll now take the following question from Jeremy Rosenfield. Please, go ahead. Jeremy Rosenfield And your silence speaks volumes. I’d like — just keeping on Deerfield, maybe you can provide a little bit of detail on the financing plan? I know looking at the tax equity and other sources of financing, can you just comment in terms of where you see that coming in and what the market is like for ongoing financings for this type of project? David Bronicheski Sure. I’m happy to take that. The financing for Deerfield would be very much the same as the plan that we have for Odell. I think half the project on a long-term basis is going to be financed from tax equity, and those discussions are ongoing. And I think the market is pretty deep for that in the US so we have full confidence of being able to get that. And then as we go through construction, the construction will be financed at a non-recourse basis through a club of lenders in the U.S. It will have the back leverage option for that as well, which the project can slide into for the leverage on the back part of it. And depending on whether we opt to purchase the other 50% or not, and if we do take it onto our balance sheet, then in that instance there’s every opportunity to simply finance the debt portion off our bond platform that we have. Jeremy Rosenfield Okay. Great. Let me just turn to Energy North. There was a comment in the results about potential system expansions in New England. Can you talk a little bit about what the size of that investment might be potentially? Ian Robertson Sure. It’s a bit of a longer answer, Jeremy, because it actually relates to our ability to maximize the synergies between our transmission business group, which as you know is involved in the development of the Northeast Energy Direct a pipeline which runs from right New York, through Massachusetts, up into New Hampshire, back down into Massachusetts at Dracut. Well, you can imagine that pipeline is running through some fairly virgin territory, and I mean virgin, virgin in the context of its service with natural gas. They don’t call New Hampshire the granite state for nothing. It’s very expensive to run pipelines. And so consequently, the installation of the Northeast Energy Direct is going to occasion substantial opportunities for towns to avail themselves of natural gas service to get off of heating oil as a primary heating fuel. We want to obviously support and encourage that conversion. We have filed a number of regulatory — opened a number of regulatory proceedings applying to be the utility of record for towns that we believe can be economically served by the proximity of the Northeast Energy Direct pipeline. And so the size of that opportunity could be material. We estimate that there is up to 30,000 new customers that could be served along the course of that pipeline in southern New Hampshire. And so it’s going to be substantial. I will point out that we are planning to give a lot more detail, Jeremy, at our investor morning. And so as I said, a shameless plug for our investor morning; I hope you make the trip up here from Montreal. But certainly it is part of the material expansion thesis for our presence of — in the New England natural gas marketplace. I don’t know if that gives you some comfort or some color. Jeremy Rosenfield I was kind of looking for sort of a dollar investment amount, but I guess I’ll have to make the trip up to find the correct answer there. Ian Robertson There you go. Jeremy Rosenfield I appreciate it. Those are my questions. Thanks. Ian Robertson Thanks, Jeremy. Operator [Operator Instructions] There are no further questions. Please continue. Ian Robertson Great. Thanks, everyone. Appreciate you taking the time on our Q3 2015 conference call. And obviously, as always, I ask you to remain on the line for a riveting review of our disclaimer by Amanda Dillon. Amanda? Amanda Dillon Thank you, Ian. Certain written and oral statements contained in this call are forward-looking within the meaning of certain securities laws and reflect the views of Algonquin Power and Utilities Corp with respect to future events based upon assumptions relating to among others the performance of the Company’s assets and the business, financial, and regulatory climates in which it operates. These forward-looking statements include, among others, statements with respect to the expected performance of the Company, its future plans, and its dividends to shareholders. Since forward-looking statements relate to future events and conditions, by their very nature they require us to make assumptions and involve inherent risks and uncertainties. We caution that although we believe our assumptions are reasonable in the circumstances, these risks and uncertainties give rise to the possibility that our actual results may differ materially from the expectations set out in the forward-looking statements. Material risk factors include those presented in the Company’s most recent annual financial results, the annual information form, and most recently quarterly Management’s discussion and analysis. Given these risks, undue reliance should not be placed on these forward-looking statements. In addition, such statements are made based on information available and expectations as of the date of this call and such expectations may change after this date. APUC reviews materials forward-looking information it has presented not less frequently than on a quarterly basis. APUC is not obligated nor does it intend to update or revise any forward-looking statements whether as a result of new information, future developments, or otherwise, except as required by law. With respect to non-GAAP financial measures, the terms adjusted net earnings, adjusted earnings before interest, taxes, depreciation, and amortization, adjusted EBITDA, adjusted funds from operations, per share cash provided by adjusted funds from operations, per share cash provided by operating activities, net energy sales, and net utility sales, collectively the financial measures, are used on this call and throughout the Company’s financial disclosures. The financial measures are not recognized measures under generally accepted accounting principles, or GAAP. There is no standardized measure of these financial measures. Consequently, APUC’s method of calculating these measures may differ from methods used by other companies and therefore may not be comparable to similar measures presented by other companies. A calculation and analysis of the financial measures and a description of the use of non-GAAP financial measures can be found in the most recently published Management’s discussion and analysis available on the Company’s website and on SEDAR. Per share cash provided by operating activities is not a substitute measure of performance for earnings per share. Amounts represented by per share cash provided by operating activities do not represent amounts available for distribution to shareholders and should be considered, in light of various charges and claims, against APUC. Thank you for your time today. Operator Ladies and gentlemen, this concludes the conference call for today. We thank you for your participation. You may now disconnect your lines and have a great day.