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NRG Yield’s (NYLD) CEO David Crane on Q3 2015 Results – Earnings Call Transcript

NRG Yield, Inc. (NYSE: NYLD ) Q3 2015 Earnings Conference Call November 04, 2015 10:30 AM ET Executives Chad Plotkin – VP of IR David Crane – Chairman and CEO Kirk Andrews – CFO Mauricio Gutierrez – COO Analysts Matt Tucker – KeyBanc Capital Markets Julien Dumoulin-Smith – UBS Daniel Eggers – Credit Suisse Steve Fleishman – Wolfe Research Ava Zar – Deutsche Bank Andrew Hughes – Bank of America Merrill Lynch Michael Lapides – Goldman Sachs Operator Good day, ladies and gentlemen, and welcome to the NRG Yield Third Quarter 2015 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer, and instructions will be given at that time. [Operator Instructions] As a reminder, this conference call may be recorded. I would now like to turn the conference over to Chad Plotkin, Vice President of Investor Relations. You may begin. Chad Plotkin Thank you, Nicole. Good morning, and welcome to NRG Yield’s third quarter 2015 earnings call. This morning’s call is being broadcast live over the phone and via webcast, which can be located on our website at www.nrgyield.com under Presentations and Webcasts. Because this call will be limited to 30 minutes, we please ask that you limit yourself to only one question. As this is the earnings call for NRG Yield, any statements made on this call that may pertain to NRG Energy will be provided from NRG Yield’s perspective. Please note that today’s discussion may contain forward-looking statements, which are based on assumptions that we believe to be reasonable as of this date. Such statements are subject to risks and uncertainties that could cause actual results to differ materially. We urge everyone to review the Safe Harbor statement provided in today’s presentation, as well as the risk factors contained in our SEC filings. We undertake no obligation to update these statements as a result of future events except as required by law. During this morning’s call, we will refer to both GAAP and non-GAAP financial measures of the company’s operating and financial results. For information regarding our non-GAAP financial measures and reconciliations to the most directly comparable GAAP measures, please refer to today’s press release and this presentation. And with that, I will now turn the call over to David Crane, NRG Yield’s Chairman and Chief Executive Officer. David Crane Thank you, Chad. Good morning, everyone and thank you for joining us on this, the third quarter 2015 NRG Yield earnings call. Today I am by joined Kirk Andrews, Yield’s Chief Financial Officer who will be delivering a portion of the presentation and also available for Q&A is Mauricio Gutierrez, who is the Chief Operating Officer of NRG Yield. We appreciate everyone joining us today and I am sure maybe you just participated in the NRG Energy earnings call, so in the spirit of keeping this call brief let’s get through it by turning to slide three and the business overview. First let me begin with a quick summary of our financial performance all of which delivered on to our expectations both in terms of being predictable and on target. In the third quarter, we delivered $198 million in adjusted EBITDA and $132 million in cash available for distribution. With the closing of the most recent NRG dropdown, we are now also updating our 2015 guidance to $705 million in adjusted EBITDA and $165 million in cash available for distribution. As we move into 2016, the full-year impact of our acquisitions and the commencement of the Alta X and XI PPAs underpins our guidance of $805 million and $265 million in adjusted EBITDA and cash available for distribution respectively. Looking at the bigger picture, when we first took NRG Yield public in 2013, our goal for NRG Yield was to establish a leader in a new investment class by highlighting the value of key long-term contracted assets within the NRG portfolio that were not from our perspective being appropriately priced within NRG Energy stock price and also by highlighting the growth opportunity arising for long term contracted assets as the power sector entered its post-merchant phase. And over the course of nearly two and a half years since NRG Yield went public, we have grown our dividend by 67% and are on target to growth by over 15% by the end of next year. Our generation portfolio is now at an equivalent of 6 gigawatts versus 2.5 gigawatts at the beginning. EBITDA and CAFD expectations in 2016 are now nearly three times where they were at the end of 2013, all of which has been accomplished through prudent financial management that has permitted a low payout ratio while also continuing to have visibility into significant growth through our sponsor NRG Energy. Obviously this positive self-evaluation does not comport with the market’s assessment as reflected in our recent share price performance. We can list a myriad of reasons why the stock is down, none of which go to the fundamentals described above, but I can tell you that the NRG Yield investment proposition is unchanged. The fundamental economics of the NRG business are solid, but the disconnect with the market means for us at NRG Yield, however, is that given the prudency with which we have managed our business, we don’t need to rush to judgment or make rash decisions, rather we can continue doing what we have been which is deliver on both results and growth commitments with the means we have available without sacrificing shareholder value. In other words, for the time being at least, we are going to stay the course. However, we do appreciate a persistent underperformance in our share price is not acceptable and in that regard what we will commit to you is that the management team and board of NRG Yield have no intention of waiting forever. We will continue to monitor over the months to come the overall yieldco environment and make strategic decisions as necessary to optimize the long-term value of NRG Yield. With that, I will turn it over to Kirk to go over the financials in great detail. Kirk Andrews Thank you, David. Turning to the financial summary on slide five, NRG Yield is reporting third quarter 2015 adjusted EBITDA of $198 million and cash available for distribution of $132 million, both exceeding our quarterly guidance. Adjusted EBITDA performance for the third quarter was slightly above expectations due to improved performance at our wind assets during the quarter while CAFD outperformed primarily due to the recent project debt repricing at El Segundo which benefitted – resulted rather than in a beneficial revision to that debt amortization schedule and also due to lower than expected maintenance capital expenditures during the quarter, simply reflecting a timing shift of some of those into the fourth quarter. On November 3, the company completed the acquisition of the latest set of right of first offer assets from NRG Energy, specifically it’s 75% interest in the portfolio of 12 wind assets, totaling 814 net megawatts of wind capacity for a total cash consideration of $210 million subject to standard working capital adjustment. NRG Yield funded this purchase with a mix of cash on hand and borrowings from its revolving credit facility. In accordance with GAAP, the company is updating 2015 adjusted EBITDA guidance from $660 million to $705 million to reflect the acquisition of the wind portfolio from NRG as if the 75% stake had been held for the full year 2015. The company is also updating 2015 CAFD guidance from $160 million now to $165 million, which reflects the CAFD impact of the acquisition over the balance of 2015. Moving to slide six, NRG Yield is also initiating 2016 financial guidance of $805 million in adjusted EBITDA and $265 million of CAFD in both cases reflecting the full year impact of the recent wind portfolio acquisition. We continue to target $1 annualized dividend per share by the fourth quarter of 2016, a 15% year-over-year increase. This targeted dividend comprise a payout ratio under 70% based on 2016 CAFD guidance providing increasing liquidity in 2016 and significant headroom for dividend growth in ‘17 and ‘18 without the need for additional dropdowns or new third-party capital. When combined with the robust pipeline of remaining ROFO assets, these factors underscore our confidence in our ability to maintain annual dividend growth consistent with long-term targets. Beginning this quarter we are providing CAFD sensitivity on our aggregate renewable portfolio in an effort to provide our investors clear visibility into the potential impact on CAFD resulting from possible fluctuations in wind velocity and solar inflation. Our 2016 CAFD guidance reflects our revised expected production cases for our wind and solar assets including the reduction to the expected wind production discussed on our second quarter call. The sensitivity charts illustrate the CAFD impact versus guidance of a 5% change in wind and solar production in each hour over the full year 2016. However, it is important to note that due to the seasonality of PPA pricing, which is typically highest from May to September, as depicted in the lower left chart, it is possible that an aggregate 5% change may have a different effect on actual results with a disproportionate amount of that change in concentrated in certain periods. As the chart illustrates, a 5% change in hourly production across the wind portfolio for the full year could increase or decrease CAFD by approximately 20 million, while a 5% change in hourly production across the solar portfolio for the full-year could increase or decrease CAFD by approximately 6 million. Finally, on slide seven, NRG Yield remains well positioned to achieve long-term, sustainable and efficient total shareholder return through superior execution of its business model and long-term strategic plan. With one of the most diverse mixes of conventional and reliable assets in sector, consisting of natural gas plants, thermal combined heat and power and district assets and an array of renewable assets, the company is well positioned to deliver stable, growing and tax efficient dividend growth to its shareholders. We continue to target a 15% annual dividend per share growth and as we have indicated in the prior quarter, this can be achieved through 2018, without the need for additional dropdowns or new third-party capital, as our low payout ratio provides us with the ability to deliver organic dividend growth. Through our right of first offer arrangement with NRG, NRG Yield has access to an estimated 135 million of additional CAFD runway, which excludes additional CAFD, which would be derived from 250 million of additional equity in ROFO dropdown of distributed generation and home solo leases. At NRG Yield’s current position, this represents approximately a 50% increase in CAFD from these ROFO assets alone and that excludes any additional growth from NRG’s efforts in a fast-growing residential and distribution solar market. Lastly, you can see in the lower right of this slide, NRG Yield ended the quarter with 572 million of liquidity versus 515 million at the end of the prior quarter. Pro forma for the recently closed wind acquisition, we have over 350 million remaining liquidity more than sufficient to fund the remaining dropdowns from our home solar and DG partnerships with NRG. We continue to expect this liquidity surplus to grow as our low payout ratio will provide near-term excess capital for incremental growth. And Nicole with that, I think we would like to move directly to Q&A. Question-and-Answer Session Operator Thank you. [Operator Instructions] Our first question comes from the line of Matt Tucker of KeyBanc Capital Markets. Your line is now open. Matt Tucker Hi, gentlemen. Good morning. Congrats on a nice quarter. David, I just wanted to follow up on the comment you made about not wanting to wait forever and taking steps to optimize NRG Yield’s value. Could you elaborate at all on what type of options may be considered there? David Crane Matt, what I would tell you is the basic message there which is, it seems like right now like we did forever in this extreme downturn, but if you sort of chronicle it back, it’s what four, five months that it is really and my main messages, we think that the fundamental business model of Yield is sound and that’s our dominant paradigm. But if this persists, and I can’t tell you exactly how much longer, six months, whatever, we have to consider all our options and the only thing I am really trying to convey to you and to the market, Matt and I know that the independent directors of NRG Yield feel the same way about this is like everything is on the table. NRG Yield is a public company with its own shareholders and while it’s got a strategic connection with NRG, we have to do what’s right by the shareholder. So you hear all sorts of things, should yields be combined, should they be boiled in, should it go private, and to be frank, we haven’t actually evaluated any of those in any great detail, I’m just sort of telling you that we will not ignore the existing share price performance forever or believe that even if we keep executing against the plan, and it doesn’t recover and what’s the problem is not our performance, but that the yield sector for whatever reason is just not going to attract the public company investors in the way that it did in the past, then we will take whatever steps it makes most sense for the existing NRG Yield shareholders at the time. Matt Tucker Thanks, David. And just as a follow-up to that, thinking just longer term and big picture, how would you address any concerns that the new NRG reset strategy could limit the development of additional assets that might be suitable for addition to NRG Yield’s ROFO portfolio just down the road in the future? David Crane Well, I mean, I think certainly my sense, speaking as the CEO of NRG Yield is first of all, I mean, there is a pretty big pipeline. I guess what I would say is the concern you’re expressing is not our primary concern at this place, because there is already a pipeline of growth assets that I think would be our first priority from NRG Yield’s perspective is just our ability to bring it what NRG already has in sort of the ROFO pipeline. I think that our understanding on behalf of NRG Yield is that NRG is not going to stop redeveloping its conventional plants with contracted assets nor on the distributed site, are the two companies that have long-term contracted assets, leases and home solar and the business to business solar that a greenco is being built around them and we would expect would continue to have a relationship with us, so we don’t really see what NRG has announced with respect to reset having that much of an impact and I think the bigger issue is the restoration of the value proposition around NRG Yield itself. Matt Tucker I think that makes sense. Thanks a lot. Operator Thank you. Our next question comes from the line of Julien Dumoulin-Smith of UBS. Your line is now open. Julien Dumoulin-Smith Good morning. I will make this super quick. Can you comment a little bit around a contemplated yield and also timing of drop-downs here, CVSR specifically? Obviously, markets evolve. How are you thinking about what a palatable acquisition yield or multiple might be, if you could give us your latest estimate? Kirk Andrews Well, Julian, it’s Kirk. From the perspective of NRG Yield, the company has not yet been efficiently offered CVSR for drop-down, although NRG has indicated it continues to intend to do so. All I can tell you is in much the same context as was the case with the most recent drop-down that yield and the total return associated with that dropdown will take into account the current market circumstances, including the cost of capital and CAFD yield for NRG Yield. It’s obviously important on both of those metrics, we have a total return that is value accretive relative to the cost of capital of NRG Yield, as well as CAFD accretive. And so both of those two, I would expect to be taken into account when we get into the negotiations between the two companies once NRG has actually made that offer. Julien Dumoulin-Smith Right. And CVSR as indicated previously was anticipated for the back half of the year? Kirk Andrews That is correct. That is what NRG has indicated it continues to intend, which is in the latter part of the year to offer that asset for drop-down. David Crane But that said, the offer and not necessarily a completion. Kirk Andrews That’s right. As I have said, that offer has not yet been made. I am simply acknowledging that NRG has repeated its intention to make that offer available sometime last year. Julien Dumoulin-Smith Thank you. Operator Thank you. Our next question comes from the line of Daniel Eggers of Credit Suisse. Your line is now open. Daniel Eggers Hey, good morning guys. Just remind me on the ROFO pipeline, is there a timeline where if NRG offers assets to NYLD and NYLD doesn’t like the price or the availability to capital that that commitment will go away? David Crane What I’d see Dan is that there is a right of first offer and the way you described the first iteration of that is what the commitment that underlies that agreement is. And that is that NRG has an obligation to first offer those assets to NRG Yield and thus far, each time that has taken place including the very latest one, which obviously takes into the current conditions in the market, cost of capital as I have alluded to in my response to Julien’s question, the two companies in being able to arrive at that agreement. I don’t want to speculate other than empirically speaking, we have been on a good path to progress with a favorable outcome under negotiations as to whether or not you can absolutely count on that. That is obviously up to both of those two parties, NRG on the one hand, NRG Yield as governed by the independent directors in those particular context on the other. So I certainly won’t predict on a go-forward basis what that outcome will be, but we’ve had a constructive process thus far. And in the event that that was not the case, NRG having met that obligations, you make that first offer, has the option or the opportunity to monetize that asset elsewhere. It doesn’t necessarily mean that NRG might do so. I can’t speculate on that from NRG Yield’s perspective, but that is the obligation that exists is that offer is first made to NRG Yield. Kirk Andrews I mean, there is no specifically prescribed by contractor or anything else that says that the offer has been outstanding for 120 days or 150 days. If that’s not specified, I don’t really –. David Crane Yeah, NRG Yield, under the ROFO arrangement has 30 days to respond to the offer when it gets made and that’s the process that we pursue each time. Daniel Eggers Okay. And I guess just when you think about evaluating strategic alternatives, because NRG is the majority voter in NYLD, I guess all those decisions will be approved or determined by NRG ultimately? Kirk Andrews Well, I mean, I think that – I mean, obviously NRG say in what NRG Yield does is significant. But I mean – but I think there is fiduciary responsibility, so all the shareholders of the company. So I mean – I think it would probably be difficult for NRG Yield to do something that NRG didn’t wanted to do. But I don’t think it can be done exclusively for the benefit of NRG. I would just add probably the best example of how we can address very important circumstances like that is obviously how we approach the recapitalization. Again, not to say that that’s prescriptive about how things work going forward in strategic alternatives of the like. But we have – from NRG Yield’s perspective certainly seen that NRG has been very mindful of the voice of the public shareholders as it did voluntarily in raising the threshold for the vote and the recapitalization to include a majority of the minority, which was not necessary, but something that NRG voluntarily did. And so I think that’s probably a good indication about the seriousness with which NRG as the majority shareholder, takes major decisions strategically and otherwise where NRG Yield comprehensively is concerned. Daniel Eggers Okay. I guess one last question. When you think about the drop-down potential, is there a price or a cost of equity capital, do you think, for NYLD where you would want to return back into issuing equity to execute more on the pipeline or how do you guys think about when you would be ready to raise outside capital given the fact that you don’t actually need any drop-downs for the next couple years to hit your dividend objectives? Kirk Andrews Yeah, I mean, from my perspective a couple of things come to mind. Obviously, we are certainly very mindful at the prices at which capital has been raised, and certainly that creates one consideration for future equity prices at which we’d begin to consider raising equity. Certainly, we are not at level today and as we have acknowledged, one parameter of that is – as you know, just by a way of example, the CAFD yield, I think under the both the distributed generation and residential solar pipeline on an average basis and of course as a contract is about 7.5%. That’s obviously and probably the lowest among the yields at which drop-downs have occurred and obviously that’s reflective of the fact that that’s really preferred return to NRG Yield with no residual exposure kind of terminal value beyond the contracted period. But judging by that, that CAFD yield would imply a price certainly at a north of $20 a share, which also comports directionally with the lowest price at which we have raised capital to-date. So that’s a long-winded way of saying, just academically speaking, I think certainly a price north of $20 is one that’s probably a decent parameter to look for, not to say prescriptively at whatever level above that we do it, but that’s a good threshold to think about. Daniel Eggers Very good, thank you guys. Kirk Andrews Thanks, Dan. Operator Thank you. Our next question comes from the line of Steve Fleishman of Wolfe Research. Your line is now open. Steve Fleishman Yeah, just on the Alta Wind, could you just talk about how that performed in the quarter and just how you feel about your kind of – you still feel the expectations going forward are, if anything, conservative, fair? David Crane I would not say, Steve that they are conservative. I think as we’ve said, we’ve revised our expected case with respect to wind production taking into account of what we have seen, most recently the averaging of the more recent periods. As to the quarter, we did say, as I alluded to in my prepared remarks, we did see some outperformance and most of that outperformance on the EBITDA side, in fact, practically all of it, was the outperformance of Alta Wind relative to our expectations and the guidance. But I think we feel comfortable having gone back through and reevaluating our expectations, which were reflected in our 2016 guidance. And obviously, we’ve supplemented that with the sensitivities around that revised expected case that we provided today as well. Steve Fleishman Okay. Great. And just one question on kind of strategic thoughts for NRG Yield. I recall during the kind of voting change that there are issues in NRG Yield at some of the projects and contracts with change of ownership. Would that impact, kind of limit some of the things that NRG Yield – that you can do with NRG Yield from a strategic standpoint? David Crane I wouldn’t say necessarily, with absolute certainty that it would prohibit, but as we’ve said before, it is – once there is a change of control, I mean, that’s the way to think about, both of those two circumstances, both in certain instances on the project financing side as well as certain instances on the PPA side, think about those as change of control. So certainly if those strategic alternatives constituted a change of control in terms of the voting shares that NRG has, then obviously it would entail having to take into consideration the impact of that change of control and potentially the reopening around certain of those project financings. Steven Fleishman Alright, thank you. David Crane Thanks Steve. Operator Thank you. And our next question comes from the line of Ava Zar from Deutsche Bank. Your line is now open. Ava Zar Thank you. During the NRG presentation, you highlighted the EBITDA and the debt associated with the ROFO assets. With increased focus on debt at yieldcos, how do you view the debt associated with those ROFO assets? Kirk Andrews I think it’s very important, I think specifically on the NRG side, I think — I don’t think there was a whole lot of discussion specifically about the ROFO assets other than the fact that that was one of the non-recourse subsidiaries. But the important distinction I think that was made is that all of that debt is fully amortizing and the duration of that amortization matches exactly the remaining duration of respective contract behind it. So you have a naturally delevering portfolio of assets. The original leverage levels of which were set and determined by the private finance and the cash flow coverage is there. So certainly we feel comfortable with the original debt levels underscored by the due diligence and all of the engineering that goes into determining what those levels are but important to remind everyone that that part of the debt capital structure both that resides at NRG Yield today as well as in the ROFO assets is fully amortizing. The only debt that is not is the corporate level, which is a very small piece of the overall debt. Ava Zar And with some of those assets not performing up to initial specs, are you still confident that that debt will amortize over the contract period? David Crane I mean are you — this is a question about the assets that are still in the ROFO? I think we’re confident in the amortization of all the assets that are within NRG Yield, if you’re asking us about amortization of assets that are still at NRG, we probably should take that call in the context — take that question in the context of an NRG call not this because NRG Yield doesn’t really have visibility into that. Ava Zar Great. I will follow up. Operator Thank you. And our next question comes from the line of Andrew Hughes of Bank of America Merrill Lynch. Your line is now open. Andrew Hughes Good morning guys, question on future drop-downs. As you look towards the timing of those, including CVSR and then what is behind it, are you or can you consider a cadence or timing there that enables you to avoid equity markets altogether just given — to finance those drop-downs just given where the payout is and your access to your revolver? Kirk Andrews I’d say with respect to the aggregate $135 million of remaining CAFD from the ROFO portfolio. I certainly would not expect all of that is possible or even a significant portion of it will be possible without third-party equity, but as we’ve said, as I said in my prepared remarks, taking into account that both there are — there is the remainder of the existing agreements for residential solar and distributed generation, as well as taking into account NRG’s stated intentions to offer CVSR. We feel comfortable with liquidity as being sufficient and that liquidity obviously building given the low payout ratio into 2016, because that would certainly be sufficient to fund those. Beyond that, I think it’s safe to assume that that would require — anything beyond that would require at this point third-party capital and that will be more likely to be equity in the next iteration of that. Andrew Hughes And then when you do consider those incremental drop-downs, are you thinking about it now more as extending the 15% growth target into the 2020s, or more along the lines of growing faster in the short term? Kirk Andrews I think for the time being the answer to that question is yes, extending the 15%. The ability to accelerate those things will certainly be most notably a function of the equity markets at the end of the day. And also taking into account the ongoing expansion of the ROFO pipeline, both with NRG as it exist today and take into account the potential for future drop-downs, depending upon the nature of business plan comprehensively greenco, as we talked about before. Andrew Hughes And just one last one, if I may. In talking about when you might trigger some of these strategic decisions about what to do with Yield if you are not happy with the valuation, is there a metric that you can point to where you might start contemplating those plans more seriously? Is it the $20 share price? Is it a specific yield number? Is it timing related? Any incremental color would be great. Thanks, guys. David Crane No, I actually don’t think there is any incremental color. If you go through all of our answers some of what I would call more indicators in terms of the time that I talked plus or minus six months, the $20 a share plus or minus what Kirk has summed up. And the third factor and this goes the question of sort of the question whether you want to extend the – we want to extend the 15% growth rate into 2020 and beyond. I mean, the whole yieldco space as well as NRG Yield for its long-term vitality depends on regular access to the capital market. And if that doesn’t come back, then we have to look at all the other alternatives, and so I sort of think those are the three factors, the value of yield what it looks like in terms of access to equity capital and roughly when I say we’re not lasting forever, you can certainly narrow that out. You should think in terms of multiple months rather than multiple years. So I mean Nichole, I think we have time for one more question. I’m sorry, we’ve gone over the hour, but we appreciate your interest. So could you and again, if anyone is left in the queue after this last question, please give us a call we want to follow up and answer your question. Operator Our next question comes from the line of Michael Lapides of Goldman Sachs. Your line is now open. Michael Lapides This will be a very, very quick housekeeping question. Your guidance for 2016 includes or excludes CVSR? Kirk Andrews Excludes CVSR, it is the existing portfolio, including the drop-down we most recently closed but excludes CVSR. Michael Lapides Got it. Thanks, Kirk. Much appreciate it. David Crane Thank you Michael and Nicole, thank you and we appreciate your interest. We look forward to talking to you next quarter. Operator Ladies and gentlemen, thank you for participating in today’s conference that does conclude today’s program, you may all disconnect. Have a great day everyone.

Algonquin Power & Utilities’ (AQUNF) CEO Ian Robertson on Q3 2015 Results – Earnings Call Transcript

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.

Alliant Energy’s (LNT) CEO Pat Kampling on Q3 2015 Results – Earnings Call Transcript

Alliant Energy Corporation (NYSE: LNT ) Q3 2015 Earnings Conference Call November 06, 2015 10:00 AM ET Executives Susan Gille – Manager, IR Pat Kampling – Chairman, President & CEO Tom Hanson – SVP & CFO Robert Durian – Vice President, Chief Accounting Officer and Controller Analysts Andrew Weisel – Macquarie Capital Brian Russo – Ladenburg Development Operator Thank you for holding, ladies and gentlemen, and welcome to Alliant Energy’s Third Quarter 2015 Earnings Conference Call. At this time, all lines are in a listen-only mode. And today’s conference is being recorded. I would now like to turn the conference over to your host, Susan Gille, Manager of Investor Relations at Alliant Energy. Susan Gille Good morning. I would like to thank you of — on the call and the webcast for joining us today. We appreciate your participation. With me here today are Pat Kampling, Chairman, President and Chief Executive Officer; Tom Hanson, Senior Vice President and CFO; and Robert Durian, Vice President, Chief Accounting Officer and Controller; as well as other members of the senior management team. Following prepared remarks by Pat and Tom, we will have time to take questions from the investment community. We issued a news release last night announcing Alliant Energy’s third quarter 2015 earnings narrowing 2015 earnings guidance. I’m providing 2015 through 2020 forward capital expenditure guidance. We also issued earnings guidance and the common stock dividend target for 2016. Press release, as well as supplemental slides that will be referenced during today’s call, are available on the Investor Page of our website at www.alliantenergy.com. Before we begin, I need to remind you the remarks we make on this call and our answers to your questions include forward-looking statements. These forward-looking statements are subject to risks that could cause actual results to be materially different. Those risks include, among others, matters discussed in Alliant Energy’s press release issued last night and in our filings with the Securities and Exchange Commission. We disclaim any obligation to update these forward-looking statements. In addition, this presentation contains non-GAAP financial measures. The reconciliation between non-GAAP and GAAP measures are provided in the supplemental slides, which are available on our website at www.alliantenergy.com. At this point, I’ll turn the call over to Pat. Pat Kampling Good morning and thank you for joining us today. The Veterans Day is just a few days away. I would like to take a moment and pay tribute to the approximately 400 proud veterans that work here at Alliant Energy and to those veterans are on the call with us today. We thank you for your service to our country and for protecting our freedoms. Enjoy your special day. Yesterday we issued press releases which included third quarter and year-to-date financial results our revised 2015 earnings guidance range. And for 2016, our earnings guidance and targeted common stock dividend. That release also provided updated detailed annual capital expenditure plans through 2019 and our capital expenditure total for 2020 to 2024. Tom will later provide details of the quarter, but I am pleased to report that we delivered another solid quarter. And since temperature was close to normal with the third quarter, at first we had no impact on our year-to-date earnings. So with the summer behind us, we are now in our 2015 earnings guidance but we are now including an adjustment to our ATC earnings to reflect the anticipated lower ROE. ATCs current authorized ROE is 12.2% we are reserving $0.03 per share for the year reflecting an anticipated ROE of 11.5%. Therefore we are changing the midpoint of this year’s earnings guidance range from $3.60 per share to $3.57 per share. Now looking at next year, the midpoint of our guidance for 2016 is $3.75 per share a 5% increase from our projected 2015 guidance as detailed on Slide number 2. This increase reflects a forecast with customer sales increase of 1% and earning on capital additions. Our long-term earnings growth objective continues to be 5% to 7% supported by our robust capital expenditure plan modest sales growth and constructive regulatory outcomes. The ability to earn our authorized returns on rate base additions of book utilities was incorporated in both retail electric base rate settlements. Those settlements have unique treatment that will allow you to reach earn on an increasing rate base while keeping customer base rates flat. The IPL settlement utilized the historic DAEC capacity payments that are included in base rates to more than offset rate-based growth and other changes in revenue requirements. This allows us to refund the difference to customers included $25 million refund in 2015 and a $10 million refund in 2016. The WPL settlement utilized previously recovered energy efficiency revenues it also increases in revenue requirements including the return on rate base additions. A balance of approximately $32 million will be amortized in 2016 and the amortization for this year is expected to be $80 million. To summarize, both creative retail rate case settlements allow us to earn on our increasing rate base or keeping retail electric base rates stable through 2016, which is last year of the settlement. Yesterday we also announced a 7% increase in a targeted 2016 common dividend level to $2.35 per share from our current annual dividend of $2.20 per share. By 2016, dividend target payout ratio is 62.5% which is consistent with our long-term targeted dividend payout ratio of 60% to 70% of consolidated earnings. We issued an updated capital expenditure plan for 2015 to 2019, totaling $5.8 billion, as shown on Slide 3. In addition, we have provided a walk from the previous 2015 to 2018 capital expenditure plan to our current plan shown on Slide number 4. As you can see the change in our forecasted 2015 to 2018 capital expenditure plan are driven primarily by additional investments on our electric and gas distribution systems and a $50 million reduction for the proposed Riverside Energy Center expansion in Wisconsin. The lower cost estimate of $680 million to $720 million excluding AFUDC and transmission was filed in supplemental test [indiscernible] with the PSCW yesterday. On Slide 5, we have provided a 10-year view of our forecasted capital expenditures. As you can see our planning additional new generation needs beyond 2019 which we anticipate will include gas, wind and other renewable resources. The additional renewables in our plan with economical for our customer energy needs as we continue to retire all the generating facilities. While reviewing Slide 5, it is also important to note that approximately 45% of the 10-year capital plan will be spent to enhance our electric and gas distribution systems to meet customers changing and growing needs. Investments in our gas distribution system are becoming more significant as evidenced by our recently completed $15 million [indiscernible] Wisconsin and we are supposed to cross $65 million [indiscernible] project in Iowa. Also for your convenience, we have already posted on our website the EEI Investor presentation that details the separated WPL and IPL updated capital expenditures through 2019 as well as updated rate-based estimates for 2014 through 2018. Now, let me brief you on our current construction activities. As year-end approaches, this has certainly been one of our busiest construction years. I must thank the employees and approximately 800 contract workers on our properties for working safely and for their assistance on these important projects. I’m extremely proud of the achievements we have made and continue to make and transitioning the environmental profile of our fossil generation fleet. We plan to reduce NOx emissions by approximately 80% and SO2 mercury emissions by approximately 90% by 2020 and we will continue to plan for a reduced carbon future. In Wisconsin, the installation of the scrubber and baghouse at Edgewater Unit 5 is approximately 75% complete and is expected to be in service in the second quarter of 2016. We are anticipating this project will come in approximately 10% below budget. We have recently a signed a contract with a joint-venture between Graycor industrial contractors and Sargent & Lundy to fund the engineering procurement and construction of the Columbia unit 2 SCR. The construction is scheduled to start in the second quarter of 2016 and WPL share the expenditure for this project of approximately $50 million. We do have an excellent track record of executing well on our these large construction projects, I am very pleased on power magazine name two of our power generating stations as our top plants for 2015. The recognition of IPLs [thermal] generating station and WPLs Columbia’s Energy Center which were excellent execution of this major investments and a dedication to a cleaner and more efficient operations. Construction of IPLs 650 megawatt combined cycle natural gas fired Marshalltown generating station is progressing well. The project is approximately 65% complete and is expected to be in service in the second quarter of 2017. KBR is the engineering, procurement, and construction contractor for this project which includes Siemens’ combustion turbine technology. In 2013, WPL announced that it would retire several older coal facilities and natural gas peakers. This retirements begin next month at Nelson Dewey and as well as in Unit 3. When WPLs prime retirements are completed the forecasted accredited capacity loss will be nearly 700 megawatts. As a consequence, WPL evaluated a wide range of alternatives to meet long-term energy and capacity needs for its customers. In 2014, WPL issued an RFP for market-based options. After evaluating all of our options, we concluded that Riverside Energy Center expansion with a new approximately 650 megawatt highly efficient natural gas generating facility was in the best long-term interest of our customers. This past April WPL applied for a certificate of public convenience and necessity or CPCN with the Public Service Commission of Wisconsin. The CPCN is progressing and in accordance with its procedure schedule on September 22 we filed that direct testimony and yesterday filed supplemental testimony through [indiscernible] updated cost projections. Intervener and Staff testimony will be filed by November 13, a public care will be conducted on November 17 in [indiscernible] and technical hearings are scheduled for December 21. We anticipate the commission issue decision on Riverside Expansion by May 2016. The proposed riverside expansion includes an approximate 2 megawatt solar installation on the property. Adjacent to riverside, on our Rock River landfill Hanwha Q Cells is currently constructing the largest solar plant at Wisconsin at 2.25 megawatts and we will purchase the power from them over the next 10 years. At our Madison general office installation of above 1000 solar panels from multiple manufacturers with 11 different types of solar modules is well underway. For this project we have partnered with the Electric Power Research Institute or EPRI to collect data and make it available to others. We also have several other solar projects under development from which we anticipate gaining valuable experience and how to best integrate solar in a cost-effective manner in our electro systems. Solar projects is in the developmental stage include owning and operating the solar panels at the Indian Creek Nature Center in Cedar Rapids Iowa and our recently issued RFP was placed in [indiscernible] solar project between 1 and 10 megawatts within our Iowa service territory. The projects resulting from the RFP will increase our system wise solar generation by 50%. Last month the EPA published its final rules through those carbon emissions from electric generating stations. We understand this is just one more step what will be a long process that includes legal challenges and the development of compliance plans. As we develop strategies, we will continue to take the approach of doing what’s best for our customers and the environment. We are fortunate that we operate in a state that has a long history of energy efficiency programs, environmental stewardship and support for renewable energy. There’s a some sort of excitement as you work to transform into the company our customers need as to be not only now, but well into the future. A major improvement to our customer experience is happening as we went live with our new customer care and billing systems for Wisconsin customers several weeks ago. And planned to go live with Iowa customers in early 2016. A $110 million investment replaces vintage mainframe systems from the 1980s. They will make communications with our customers more convenient and timely. We have already accomplished a great deal as a company as we transition to a cleaner more modern energy system. I want to thank a lot of employees for their creativity and finding cost-effective solutions in serving our customers well. Let me summarize the key message for today. We had a solid first three quarters of the year and are well positioned to deliver on this year financial and operating objectives. Our plan continues to provide for [audio gap] 5% to 7% earnings growth and 60 to 70% common dividend payout target. Our target 2016 dividend increased by 7% over the 2015 target dividend. Successful execution on our major construction projects includes completing projects on time and at a below budget in a safe manner. Work with our regulators consumer advocates, environmental groups and customers in a collaborative manner. We shape our organization to be lean and faster while keeping our focus on serving our customers and being good partners in the community. We will continue to manage the company to strike a balance between capital investment, operational and financial discipline, and cost impacted customers. Thank you for your interest in Alliant Energy and I will now turn the call over to Tom. Tom Hanson Good morning everyone. We have released third quarter earnings last evening with our non-GAAP earnings from continuing operations of a $1.63 per share and our GAAP earnings from continuing operations to a $1.59 per share. The non-GAAP to GAAP difference is due to a $0.04 per share charge resulting from approximately of 2% employees accepting voluntary separation packages as we continue focusing on effectively managing cost for our customers. 2015 third quarter non-GAAP earnings are $0.23 higher than the third quarter 2014 primarily due lower retail electric customer billing credits at IPL, higher electric sales and lower energy efficiency cost recovery amortization to WPL. Higher quarter-over-quarter EPS was partially offset by higher electric transmission service expense at WPL and the delusion impact of shares issued in 2015. Comparisons between third quarter of 2015 and 2014 earnings per share are detailed on slides 6, 7 and 8. For the first six months of this year we experienced virtually no temperature normalized retail sales growth. We are pleased that the third quarter brought an estimated $0.06 per share increase in earnings resulting from higher temperature normalized sales. Some of the growth experience in the third quarter of 2015 for residential and commercial is due to an earlier fall grain harvest in 2015 when compared to 2014. Of the retail sectors industrial continues to be the largest sales growth driver year-over-year. Quarter-over-quarter we have recognize in earnings increased of $0.05 per share from higher sales due to temperatures since the third quarter of 2014 had approximately 20% fewer cooling degree days compared to normal. However, the first three quarters 2015 temperatures were close to normal. Year to date non-GAAP earnings are tracking in line with the 2015 earnings guidance range comparing non-GAAP earnings from continuing operations for the first nine months of 2015 versus 2014, earnings are up 8% year-over-year. Drivers of the differences between the statutory tax rates for IPL, WP&L and AEC and the actual forecasting effect the tax rates for 2015 and 2014 is profiled on slide 9. Now let’s review our 2016 guidance. Last evening we issued our consolidated 2016 guidance range of $3.60 to $3.90 earnings per share. A walk on the mid points of 2015 to 2016 estimated guidance range is shown on slide 10. The key drivers for the 5% growth in earnings relate to infrastructure investments including higher AFUDC related to the construction of the Marshalltown generating station. The 2016 guidance range assumes normal weather and modest retail sales increases of approximately 1% for IPL and WP&L when compared to 2015. Also the earnings guidance is based upon the impact of IPLs and WP&Ls previously announced retail electric base rate settlements. The IPL settlement reflected rate based growth primarily from placing the Lansing scrubber in service in 2015 and the Ottumwa baghouse scrubber and performance improvement in service in 2014. The increase in revenue requirements related to rate base editions is offset by the elimination of DAEC purchase power capacity payments. In 2016 IPL expects to credit customer bills by approximately $10 million. By comparison the billing credits in 2015 are expected to be approximately $25 million. During 2016 IPL expects to provide tax benefit billing credits to electric and gas customers with approximately $62 million when compared to $72 million in 2015. As in prior years the tax benefit riders have a quarterly timing impact, but are not anticipated to impact full year 2015 and 2016 results. The WP&L settlement reflected electric rate base growth for the Edgewater unit 5 baghouse projected to be placed in service in 2016. The increase in revenue requirements in 2016 for these and other rate base additions were completely offset by lower energy efficiency cost recovery amortizations. Also included in WP&L’s rate settlement was an increase in transmission costs primarily related to the anticipated allocation of SSR costs. As a result of a third quarter issued after the settlement the amount of the transmission cost billed to WP&L in 2016 will be lower than what was reflected in the settlement. Since the PSCW approved escrow accounting treatment for the transmission cost. The difference between the actual cost billed to WP&L and those reflected in settlement will accumulate in a regulatory liability. We estimate that this regulatory liability will have a balance of approximately $35 million by the end of 2016. We view this regulatory liability as another mechanism we can use to minimize future rate increases for Wisconsin retail electric customers. Retirement plan expense is currently expected to be approximately $0.03 per share higher in 2016 largely due to lower than expected asset returns forecasted for 2015. These amounts will be updated at year end 2015 when determining the actual 2016 plan expense. Given the changes expected in income tax expense in 2016 slide 11 has been provided to assist you in modeling the forecasted 2016 effective tax rates for IPL, WP&L and AEC. Turning to our financing plans cash flows from operation are expected to be strong given the earnings generated by the business. We also will benefit given we do not expect to make any material federal income tax payments in 2016. These strong cash flows will be partially reduced by credits to customer bills in accordance with IPL’s tax benefit riders and IPL’s customer billing credit resulting from the settlement. We believe that with our strong cash flows and financing plans we will maintain our target liquidity and capitalization ratios as well as high quality credit ratings. Our 2016 financing plan assumes will be issuing approximately $25 million of new common equity through our shareowner direct plan. The 2016 financing plan also anticipates issuing long-term debt including up to $300 million at IPL and up to $310 million at the [parent] and Alliant Energy Resources. The $310 million of proceeds at the parent and Alliant Energy Resources are expected to be used to refinance maturity of term loans. We may adjust our plans as deemed prudent if market conditions warrant and as our debt and equity needs continue to be reassessed. As we look beyond 2016 our equity needs will be driven by the proposed riverside expansion project. Our forecast assumes that the capital expenditures for the riverside expansion in 2017 and 2018 will be financed primary by a combination of debt and equity. Our current financing forecast assumes no extension of bonus depreciation deduction. Under this assumption Alliant energy will be making modest federal tax payments starting in 2017 it will continue to use net operating losses for the next two years as offset to federal taxable income. We have several current and planned regulatory dockets of notes for the rest of 2015, 2016 and 2017 which we have summarized on 512. Later this year we anticipate a decision from PSCW on the 2016 fuel monitoring level. Next year we anticipate a decision on the Wisconsin riverside expansion proposal and on the Iowa natural gas pipeline. Also in 2016, we plan to file a emissions planned budget in Iowa and the Wisconsin retail electric and gas base case per rates in years 2017 and 2018. The next Iowa retail electric and gas base rate cases are expected to be filed in the second quarter of 2017. We very much appreciate your continued support of our company and look forward to meeting with you at EEI. The slides to be discussed at EEI are posted on our website as we do with all of our investor relations conference slides. At this time I will turn the call back over to the operator to facilitate the question-and-answer session. Question-and-Answer Session Operator Thank you, Mr. Hanson. [Operator Instructions] And we will take our first question from Andrew Weisel with Macquarie Capital. Andrew Weisel Good morning guys. First question is on the [four set] charged for voluntary employee separation. What does that impact on? How is that going to impact OEMs going forward? Tom Hanson That will be a reduction to ONM on going forward and that’s reflected in our forecast in terms of 2016 guidance. Andrew Weisel And what is the forecast for ONM next year? Tom Hanson We are assuming that it will be about a 2% increase now recognizing that this excludes the normal energy efficiency cost as well as any of the regulatory amortization that flow through ONM as well. Andrew Weisel Got it. Next a couple of questions on riverside, first in terms of the CapEx you laid out. I see that you lowered it for next year spending by that 95 million can you give little more detail on that. Is that assuming a little bit of a delay when the construction begins? Pat Kampling No not at all. Now that we are getting bids from the contractors, this is the timing of the bids, the cash flow that they are laying out while we changed the not only did we change the total number but we changed the timing of the payments. Andrew Weisel Okay. The total number if I heard you correctly was only down about 20 million is that right? Pat Kampling No, it’s down, if it goes from mid-point to mid-point it’s down 50 million, 50. Andrew Weisel Okay. Then next question I have is with the potential for PTA instead of riverside, if riverside were to be either delayed or canceled could you talk about how you might be able to back fill some of that spending in terms of what might go in and how soon you will be able to show those results? Pat Kampling Yes, Andrew it’s a little preliminary first to give a backup for capital for riverside right now. It would be honest to tell you though for 2016 it would be tough to fill the capital that we have laid out in 2016, but we’ll discuss as we get further down the year in 2016 what the back fill could possibly be. Andrew Weisel Okay. Thank you very much. I’ll let other people ask questions. Operator And we will take our next question from Brian Russo with Ladenburg Development. Brian Russo Good morning. Pat Kampling Good morning Brian. Brian Russo Just in terms of the 2016 guidance what kind of earned ROE are you seeing at IPL and WP&L maybe at the mid-point? Tom Hanson We are assuming that we would earn our authorized returns in both jurisdiction. Brian Russo Okay. So what gets you to the high end of the range? Pat Kampling The high end sales are higher than we expect. We currently expect 1% increase in sales but if they come in higher it would definitely bring us to the high end of the range. Brian Russo Okay and then as you we looked into 2017 Marshalltown will be added base rates and I believe correct me if I am wrong but that’s the allowed ROEs of 11.4%. So I would imagine that your earned ROE in 2017 will be enhanced relative to the earned ROE assumption in 2016. Is that the way to look at it? Pat Kampling Brian so the allowed ROE for Marshalltown is 11%, 11.0. Brian Russo Okay. Pat Kampling But as we go through internal and final rates you will see our earned returns increase at Iowa. Brian Russo Okay great. Thank you very much. Operator And Ms. Gill there are no further questions at this time. Susan Gille With no more questions this concludes our call. A replay will be available through November 13, 2015 at 888-203-1112 for U.S. and Canada, or 719-457-0820 for international. Callers should reference conference ID 8244179. In addition, an archive of the conference call and a script of the prepared remarks made on the call will be available on the Investors section of the company’s website later today. We thank you for your continued support of Alliant Energy. And feel free to contact me with any follow-up question. Operator And ladies and gentlemen that does conclude today’s conference. Thank you for your participation. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. 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