Algonquin Power and Utilities Corp (NYSE:AQN) Q4 2017 Earnings Conference Call March 2, 2018 10:00 AM ET
Executives
Christopher Jarratt - Investor Relations
Ian Robertson - Chief Executive Officer
David Bronicheski - Chief Financial Officer
Alison Holditch - Investor Relations
Analysts
David Quezada - Raymond James
Rupert Merer - National Bank
Nelson Ng - RBC Capital Markets
Ben Pham - BMO Capital Markets
Sean Steuart - TD Securities
Mark Jarvi - CIBC
Rob Hope - Scotiabank
Jeremy Rosenfield - Industrial Alliance Securities
Operator
Thank you for standing by. This is the conference operator. Welcome to the Algonquin Power & Utilities Corp Fourth Quarter and Year End Conference Call. As a reminder, all participants are in listen-only mode and the conference is being recorded. [Operator Instructions] I would now like to turn the conference over to Christopher Jarratt, Vice Chair of Algonquin Power & Utilities Corp. Please go ahead, Mr. Jarratt.
Christopher Jarratt
Great, thanks very much. Good morning, everyone. Thanks again for joining us on the 2017 fourth quarter and year end earnings conference call. As mentioned, my name is Chris Jarratt and I am the Vice Chair of the company.
And as usual, joining me in the call today are Ian Robertson, our Chief Executive Officer and David Bronicheski, our Chief Financial Officer. To accompany this earnings call, we also have a supplemental webcast presentation that you can access on our website algonquinpowerandutilities.com. This presentation as well as additional information on our Q4 and year end results is available for download from that website.
Over the course of this call, we will be providing information that relates to future events and expected financial positions, which should be considered forward-looking and I direct you to review our full disclosure on forward-looking information and non-GAAP financial measures, which are available on the website. We will read a full disclaimer at the end of this call.
On our call this morning, Ian will review our 2017 strategic achievements, Dave is going to follow with the 2017 financial highlights on what we think was a great year and quarter and then Ian will conclude with the outlook for 2018 and beyond. We will then open the lines up for questions and I ask you to restrict your questions to two and then re-queue if you have additional questions.
And with that, I am going to turn it over to Ian to start with the 2017 strategic achievements.
Ian Robertson
Thanks, Chris and good morning everyone. Thanks for taking the time to join us for our call. I hope that those in the call would agree that 2017 actually marks another year of strong performance for our organization. And I would like to start off the call by summarizing the strategic achievements of the year.
We split them up into three areas as you can see on the screen there: firstly, our financial performance; second, a review of the main activities that drove that performance; and then lastly, summary of some of the key strategic initiatives that we have underway. So, firstly, Q4 marked a solid financial finish to the year. We are obviously pleased that we achieved year-over-year growth in our results, which has been very strong. And the contributors from our historic successive growth initiatives and that’s most notably our Empire acquisition, which closed at the January 1 of last year. These are the most material drivers of our achievement. We saw an 85% increase in adjusted EBITDA over 2016. And perhaps more importantly from the creation of shareholder value, a 30% increase in adjusted per share net earnings. We understand the importance of our dividend as the core component of the APUC total shareholder value proposition. We believe that our strong 2017 financial and operational performance has been supportive of the 10% dividend increase last year, which was announced by our Board of Directors and we are confident in our ability to continue to deliver strong earnings and cash for our growth to support industry-leading dividend growth.
Secondly, we see our 2017 achievements as consistent with our commitment to diversify and continue to grow our business. 2017, we added over 200 megawatts of new electrical generation capacity to our fleet, with commissioning up to 150 megawatt Deerfield wind facility and 10 megawatt Bakersfield 2 solar facilities early in the year. We also noted the addition of 50 megawatts of Luning solar facility to the regulated asset base of our Liberty Utilities Group to cost effectively serve the customers within our California electric utility.
As we have already noted, our Liberty Utilities Group significantly grew its service base with the addition of over 220,000 new utility customers in 2017 with the completion of our previously announced Empire acquisition. While the financial benefits of the Empire acquisition are evident in our annual results, we are also particularly proud of the seamlessness at which the integration of Empire to our operations has been accomplished by our teams.
Late last year, we successfully completed a $575 million equity offering with the proceeds to be used in part to support our recently announced international expansion strategy, which includes acquisition of a 25% ownership stake in a company called Atlantica Yield and can find new global energy and water infrastructure projects. And then lastly, the delivery of a continued pipeline of accretive growth initiatives is at the forefront of our business strategy. We outlined our 5 year $7 billion plus CapEx plan at our 2017 Investor Day that we held in December. Some of the key components of our growth strategy include our November 1 announcement of the formation of our joint venture Algonquin – our Abengoa Algonquin Global Energy Solutions with our team and the investment in 25% ownership stake in the Atlantica Yield. Collectively these investments we believe positioned APUC well to pursue new avenues of growth within the global clean energy and water infrastructure development space.
We continue to make positive strides in our commitment to greening our generation fleet and in early Q4, we announced our proposed plan to lower customer energy costs in the Midwest by phasing out our coal generation in favor of up to 800 megawatts of new wind generation by the end of 2020. Late last year, we also announced our Granite Bridge opportunity, a new natural gas infrastructure project designed to lower customer energy costs by bringing additional natural gas supply into historically constrained U.S. Northeast. And lastly we will continue to grow our customer base through the completion of accretive acquisitions such as the St. Lawrence Gas and City of Paris water distribution systems that we announced last year.
And with that, I will turn things over to David to review the financial results. David?
David Bronicheski
Thanks Ian and good morning everyone. I would like to shorten my remarks today on our financial results in order to allow a bit more time for our discussion on U.S. tax reform, which seems to be quite topical these days for obvious reasons. As Ian outlined earlier, we achieved our growth targets in 2017 and that growth is reflected in our financial results. Modestly, I think I can say that we are reporting results that by any measure can only be described as impressive. Year-over-year, our adjusted EBITDA was up 85%. The acquisition of Empire was clearly a large part of this, but not to be missed were rate case increases in our existing utilities totaling $23.8 billion and the contributions from Liberty Power from new generating facilities. More meaningfully we achieved a growth of 30% in our adjusted earnings per share, bringing it to $0.74 for the full year of 2017. And finally, our adjusted funds from operations grew 72% to $614.5 million during 2017. To summarize, while Empire has obviously had a significant beneficial impact on our 2017 performance, we were equally pleased with the results from our existing operations and remain highly confident that our entrepreneurial spirit and ambitious future growth plans will enable APUC to continue to deliver peer leading long-term growth.
So now onto U.S. tax reform, on December 22, 2017, the U.S. signed into law the tax cuts and jobs act which made sweeping changes to U.S. tax law. Given the scale of the changes, the SEC has allowed for a 1 year measurement for SEC registrants to complete their analysis, interpretations, assessment and presentation of the changes. While we are still interpreting various aspects of the legislation as of December 31, 2017, we consider all amounts related to the U.S. tax reform in our year end financial statements to be reasonable estimates. In terms of the impacts outlined in our Q4 results we released last night, I am happy to say that they are largely in line with the initial expectations we provided on our Investor Day, back in December of last year. We expect that the effects of U.S. tax reform in 2018 will be neutral to slightly positive to EPS at approximately 2% to 3% negative to 2018 EBITDA, which is certainly within the planning parameters that we have for normal variability in our business cycle whether from wind, hydrology, weather or unforeseen events.
We have always operated Algonquin in a manner that allows us to adjust to this modest level of variability and our EBITDA without disrupting our business plans. So with that backdrop, let’s unpack some of the larger elements of tax reform. To the frame the impact of tax reform is useful to identify those things that are unique about Algonquin. Firstly, our business mix, which is about 10% non-regulated in Canada, 20% non-regulated in the U.S. and 70% regulated in the U.S. Secondly, we have a significant regulatory diversification. We have 34 utilities operating in a dozen different regulatory jurisdictions. Third, we have a modest amount of leverage in our capital structure, certainly less than many pure-play utilities. Finally, we have a strong track record of growth that we expect to continue as we execute on our 5-year $7.7 billion investment program.
So now, let’s look at specific elements of U.S. tax reform starting first with the lower tax rates. First, lowering the U.S. corporate tax rate from 35% to 21% has impacted our 2017 Q4 results. On a consolidated basis taking into account both our regulated and non-regulated businesses in the U.S. we like most companies with U.S. operations recorded a one-time non-cash accounting charge related to the re-measurement of deferred income taxes, which for us was $22.4 million. In that re-measurement, we assumed the excess deferred income tax liabilities from our utility operations will eventually be given back to customers and so have setup a regulatory liability for that amount. As required by legislation the regulatory liability for the most part will be amortized over the remaining lives of the applicable assets. On average, you can think of it as about 30 years.
Looking forward, for our regulated businesses, taxes are a pass-through expense for customers. So, this will be neutral to EPS for 70% of our business once this tax change has fully worked its way through all of our utilities. For the 20% of our business that is non-regulated, it’s actually positive. On the non-reg side, we are not cash taxable, so lower taxes are neutral to FFO in the short run, but positive to FFO in the long run. Given that we are not cash taxable today in the U.S. on our regulated size for a couple of more years, this will be modestly negative to EBITDA in 2018 as we have previously noted, but this is within our expectations in our normal course planning for variability in our business.
Let’s chat a bit about interest deductibility and tax depreciation. As everyone knows, tax reform has restrictions on interest deductibility and has accelerated tax depreciation. Neither of these things affects our regulated utilities group. We have assumed that the interest deductibility exemption applies to holding company interest expense. Therefore, the company believes that most of its U.S. holding company interest can be properly allocable to its U.S. regulated utilities and is therefore exempted from the interest deductibility limitations. Being a Canadian-based company investing in the U.S. we have also looked at our cross-border financing and believe that they are largely unaffected by U.S. tax reform.
Turning our attention to rate based growth, U.S. tax reform has eliminated bonus depreciation for our regulated utilities and taken together with the lower tax rate reduces accumulated deferred income taxes as we make needed investments in our utilities. Both of these things work to increase our rate base at a faster pace over time than it otherwise would. At Investor Day, we provided a forward view on our future rate based growth of approximately 8.3% CAGR at our utilities. As a result of tax reform, we are now seeing a rate base growing at about 8.8% CAGR with our rate base now expected to be approximately $100 million higher in 5 years’ time than it would have been pre-tax reform. That’s a 2% to 3% increase in our expected rate base 5 years from now.
Finally, what about the U.S. renewable energy production tax credits? We are pleased that U.S. tax reform largely left the PTCs and ITCs for renewable energy projects intact. There was no change in the definition of continuous construction and the existing phase-out of 2021 remains in place. As far as availability of tax equity, since the enactment of U.S. tax reform, we have had an opportunity to meet with most of our existing tax equity partners as well as some new ones. We are pleased that it appears that between the company’s ability to absorb a portion of the renewable energy tax credits in future years and anticipated future demand from third-party tax equity investors that we will be able to satisfy the tax equity financing component for our U.S. renewable energy projects outlined in our 5-year financing plan at Investor Day.
And just a few final thoughts, on credit metrics, we have always believed that having a strong balance sheet as the foundation for growing our business is important. We believe this is important to our equity investors as it is to our fixed income debt investors. Prior to U.S. tax reform, our credit metrics were improving post our acquisition of Empire and we expect this to continue. We remain committed to maintaining our BBB flat credit rating and we believe that our various state regulators also want to make sure that the regulated utilities that they oversee maintain strong credit metrics.
I would like to end by saying that while it may be only natural to focus first on potential downside risks from tax reform, we shouldn’t forget that U.S. tax reform is supposed to be a good thing and it actually is. There are a number of positives to U.S. tax reform that investors will see in the months and years to come. Tax reform is positive to our non-regulated business in the U.S. and on the utilities side, the new tax regime provides an opportunity to reduce rates to customers, but it also affords utilities an opportunity to accelerate needed investments in utility infrastructure, which will improve service delivery, customer service, system reliability and safety. We look forward to being productively involved in discussions with our various state regulators about working through the best options for delivering all of these benefits to our customers.
With that, I will now turn things back to Ian.
Ian Robertson
Thanks David. I appreciate the color. As always, we will open the lines up for questions in a movement. But first I want to provide an update on our near-term to mid-term growth initiatives for 2018. Three of them I would like to speak about. Firstly, Great Bay solar, our 75 megawatt solar facility being constructed in Maryland. We are now finishing up construction and commissioning on the project, 75% of the solar field is energized in producing power. We expect the facility to make a full contribution to earnings starting next month. The project has suffered some delays in construction primarily related to the heavy rains that occurred over the course of 2017, which made strong water management challenging and to be frank what’s the contractor had a hard time dealing with, but we are – we rectified the problems and as I said we are looking forward to commissioning before the end of that month.
With respect to Amherst Island construction is also continuing at the 75 megawatt wind facility located down near Kingston, Ontario. Play completion is well underway with over 50% of the foundations being completed. Approximately 25% of the turbines are erected with more going up every week. The underwater cable and main power transformer are now installed. We expect construction to be substantially completed before the end of Q2 2018. Not surprisingly, we have been challenged by the severe winter weather this year, but we believe the construction crews have logistics well in hand now.
I would like to point out that we see both Great Bay and Amherst as adding further diversity to our non-regulated power production fleet both by geography and generating source. The diversity of our generation portfolio remains a key element of our continued delivery of stable long-term financial results. And the last, I would like to speak about is Granite Bridge. Granite Bridge was a pipeline infrastructure project that we announced last year. And we see that this New Hampshire based pipeline in LNG project has an opportunity to reduce energy costs for our New Hampshire LDC customers. Granite Bridge consists of a 27 mile underground lateral pipeline and our liquefied natural gas liquefaction, storage and re-gasification facility. This approximately $350 million investment is expected to result in significant customer savings through – new lower cost supply by easing the historic source constraints in the Northeast along with increased tax revenues for the various supportive communities in the region. We are currently advancing the regulatory approval process pursuant to filings, which were made late last year.
Next, I would like to kind of talk a little bit about some of the growth initiatives, broader growth initiatives that we outlined at our investor morning a couple of months back. Within our Liberty Utilities Group, we remain committed to pursuing our greening the fleet initiative across all of our systems, superior economics for renewables are driving comprehensive change in the U.S. electric utility landscape and specifically, in Missouri, Arkansas, Oklahoma and Kansas. Our customers stand to benefit greatly from our plans to transition our fleet from its current coal focus to a low cost sustainable renewable energy supply. On October 31 we announced a proposed plan to phase-out existing coal generation in favor of up to 800 megawatts of new wind generation by the end of 2020. This plan is forecast to generate customer cost savings of up to $300 million over the investment horizon of these assets.
Secondly, in terms of rate cases within the Liberty Utilities Group obviously an important part of our active capital investment program was just improvements is actually you see recoveries of these investments in customer rates. On this front in 2018, we are planning to prosecute another eight rate cases totaling approximately $45 million in requested incremental revenues. With respect to our customer first initiative, as our business has continued to grow and we are close to 800,000 customers today, we have been highly focused on the implementation of best in class business processes to effectively manage our growing operations and team. It’s important that we also in future improve if you will our business to capitalize on the rapidly changing customer desires and needs and to equip our company with the infrastructure tools we need for success. We refer to this initiative as our customer first investment program.
We are pleased that David Pasieka, who currently provides executive oversight of our regulated utility operations is able to bring his deep customer centric knowledge to bear and providing strategic leadership to this initiative. And lastly, but certainly not least, we continued to be excited about the inaugural steps we have taken into international infrastructure investment due to formation of AAGES and our investment in Atlantica. As we outlined in detail on our most recent Investor Day, we believe that AAGES represents a low risk strategy for executing on APUC’s international growth aspirations. Closing on the initial investment in 25% of Atlantica Yield is now in hand with all material conditions present the closing satisfied and the mechanical process of closing to be completed in the next couple of days.
Perhaps more strategically, we are pleased to report that AAGES is fully staffed with XSOP [indiscernible] and Algonquin developers who are up and running with project opportunities being actively pursued in concert with our new partners. Specifically, we are actively working on the near-term projects which we identified at the time of the announcement of the Atlantica acquisition. Finally, we remain confident in APUC’s ability to execute on our financial and strategic objectives through these various avenues for growth and deliver our 10% per day projected annualized earnings growth. Our historic earnings and cash flow growth has supported an industry leading dividend growth profile which we are confident we can continue with the coming few years.
With that operator, I would like to open it up for questions.
Question-and-Answer Session
Operator
Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our first question comes from David Quezada of Raymond James.
David Quezada
Thanks. Good morning guys.
Ian Robertson
Good morning David.
David Quezada
My first question is just on the popular topic of tax reform, but just on kind of the positive elements of it, wondering if you can provide any color on what the potential is to speed up capital over your call 5-year planning horizon?
Ian Robertson
Sure. And so why don’t we – our focus first on the regulated utilities and clearly lowering the amount of customer – not the customers effectively have to pay for the income taxes, since that’s the pass-through to customers. I think you are referring that it certainly if you will maybe creates notional headroom in customer rates. And so to the extent that we had safety or reliability in other project that we might have otherwise have pushed out to another year, it creates an opportunity to invest in those project. We could have estimated that as a couple of $300 million a year over the next 4 years or 5 years. So it is a significant opportunity, obviously we have to continue to be prudent with our investment from our customers perspective. But I think it’s certainly an acknowledgment that lowering what our customers have to pay for taxes is obviously a good thing. And to the extent that we can provide better service at the same costs they are incurring today, we are all over it. I don’t know if that’s a response to your question, David, it’s kind of where you were going.
David Quezada
It is. Absolutely. Thank you. That’s helpful. My only other question is that I know that the California Public Utility Commission has recently come out with a new planning process and that’s aimed to support renewables. I am wondering what your most recent thoughts are there and if you see any incremental opportunities from that new planning process?
Ian Robertson
Well, we certainly see California as a target market for two things, our non-regulated generation business we have been talking over the past quarter or so about our Walker Ridge project that we are pursuing. It’s strategically located in a market, which as you kind of point out is both supportive now in order to be getting more supportive of new renewable generation as they kind of push to the ultimate goal of 100% renewable in the state, which I actually think they will ultimately get to. But secondly, within our little California utility, we actually think through initiatives like our battery and solar installation that we have announced up in Squaw Valley, our Luning 50 megawatt solar facility, another 10 megawatts of solar that was just approved by the CPUC. We think we are actually well positioned to achieve the 100% renewable that actually our customers have reached out to us to communicate their desire for us to get to. So, we only see the planning process and improvements in that as being supportive to our initiatives. So we are keen on California just getting keener, I don’t know that’s – if that’s what you are looking for.
David Quezada
That’s great. Thank you very much. I will get back into queue.
Ian Robertson
Thanks, David.
Operator
Our next question comes from Rupert Merer of National Bank.
Rupert Merer
Good morning, everyone.
Ian Robertson
Good morning, Rupert.
Rupert Merer
So, a good solid quarter and looking at the changes from U.S. taxes I realized it’s early and you work in a number of jurisdictions. But do you have a sense as to how long it’s going to take before you see a change to your rates to reflect the lower taxes and with those changes typically be retroactive?
David Bronicheski
Right now, we are not anticipating things to be retroactive. I mean it will obviously vary state by state. We are expecting some of the things to get us this year and that was really what was driving behind the 2% to 3% negative impact on our EBITDA. So, some of them will start to work their way into our operations this year, but like I said, we think it’s relatively modest. And as far as getting through the rest of our 34 utilities in all of the different jurisdictions it currently based on what we are seeing, it looks like it’s going to be somewhere in this 24 to 36-month period, 36 will be the outside that the outside date I would think. So people should think of it in that sort of time horizon.
Ian Robertson
And I’d offer up Rupert just to square that circle that the – that we have to kind of look at net impact, obviously, we have got ongoing capital investment in all of these utilities, which would – I guess will change the outcome of those rate cases. Well, certainly the cost for customers will be positively affected by income taxes kind of pursuant to David’s previous question. I think there is an opportunity for us to advance some other safety and reliability initiatives that would kind of offset those impacts.
Rupert Merer
Okay, great. And then secondly, looking at your CapEx plan for 2018, I think it’s $1.2 billion to $1.4 billion, is that down a little from the Analyst Day, I think we are looking at $1.7 billion and if so they are pushing out of some of the schedules is that something you are doing deliberately or have you had some moving parts in some of the approvals for some projects, just your comment on the CapEx plan?
David Bronicheski
Sure. First, I think it’s important to understand that really it’s just a think of it as that changes the deferral of CapEx into future year largely next year. And so it doesn’t change our 5-year CapEx plan in anyway. Following tax reform, we have looked at the regulatory schedules and not surprising the regulatory schedules, are very busy throughout the U.S. And so what that has afforded us is an opportunity to defer some CapEx and align it more closely to when we now expect that rate case to actually occur. So, it really is just a deferral, it’s certainly not a diminution in our CapEx plan over the next few years.
Rupert Merer
Excellent. Thanks very much. I will get back into queue.
Operator
Our next question comes from Nelson Ng of RBC Capital Markets.
Nelson Ng
Great, thanks. Congratulations on a good quarter.
Ian Robertson
Hi, thanks Nelson.
Nelson Ng
Yes, no problem. Quick one on Amherst Island, so are you – I was just wondering how much of the costs have been locked in given the increase in the range, do you use EPC contractor for the construction of that site?
Ian Robertson
We do, but I will say and I don’t think this is kind of unusual in its construct. The EPC contractor gives us a price, but that price is kind of premised on certain expectations of conditions. And I think it’s probably not unreasonable to say that between the cold at the beginning of the year and the rain and the thoughts that have taken place those conditions have kind of deviated and I think that’s probably the largest source of where that increase in costs have come. I will say that as we look for it and have forecast those costs, we have tried to reflect the best knowledge we have in terms of the conditions that we are encountering. And so well, there is no guarantee of God’s will when it comes to weather going forward. We have tried to be as prudent as we possibly can. So, I don’t want to say just bad luck, I don’t think it’s an unreasonable observation that the Ontario permitting and renewable energy environment kind of causes perhaps sub-optimality in terms of the timing of construction or they have some very specific dates that you need to comply with, there is little latitude in those days and maybe that’s understandable, but you certainly end up doing things that if you had as much time as you were wanted, then you might say well, I will defer building that road until May instead of doing it in the middle of January, but it is what it is, I think where we continue to be comfortable that the returns from the project are attractive and accretive to us. And so while it’s obviously disappointing and nobody likes to see capital cost increases, when we look at it in the context of this project maybe the size of the organization is certainly something that’s manageable.
Nelson Ng
And just to follow-up on that, so for Blue Hill Wind, I guess the expectation is you also use an EPC contractor and there is likely going to be I guess fewer moving parts in terms of scheduling?
Ian Robertson
Well, there is no doubt about it to be building a wind project in the prairies is materially different than doing it on an island in Southwestern Ontario. I think if you kind of look back at our say/do ratio from a capital cost perspective on our projects like Odell and Deerfield, which probably from a geography point of view are way more representative, that Chaplain or Blue Hills as we call it, the Blue Hills is way more consistent with those projects than perhaps Amherst Island. So, I think we acknowledged the differences and yes, we do use an EPC contract and we expect to have that kind of same level of success we have had historically.
Nelson Ng
Okay. And then just my second question is more on the, I guess the dividend I know it’s a board decision. In the last few years it’s kind of taken place in the first half of the year. I was just wondering is there typical period where the board kind of reviews the financials and the payout ratio in more detail?
Ian Robertson
Yes, there is. And historically, if you go back I will say more than last year maybe the year before, it’s always been a QQ initiative. We have our strategic planning process than we review with the board our expectations of growth going forward. And so typically it’s been handled and your are correct kind of at the midyear mark after our Q2 results. We were – Empire represented such a material initiative for us in 2017 that the Board felt comfortable advancing that. But historically, it’s always been a mid-year initiative I think you probably conclude that the results were strong and supportive of our objectives on the dividend and increased perspective. But I think we decided that from the Board’s perspective we would I will say revert back to, but there was no reason to change from our historic practice of kind of looking at it in the middle of the year.
Nelson Ng
Okay. Thanks again.
Ian Robertson
Thanks Nelson.
Operator
Our next question comes from Ben Pham of BMO Capital Markets.
Ben Pham
Thanks. Good morning. I wanted to go back to Nelson’s question on dividend and I wanted to clarify when you think about your 10% is that really promising shareholders that they raise the dividend 10% sometime during the year or you think of it as a calendar year average through late decade?
Ian Robertson
What it should to be frankly, probably don’t get that fine in our math Ben. I think as we think about it is I will say sometime during the year and generally you see there in Q1 or Q2, the Board would consider the dividend. And I think the historic practice has been to just increase it by 10% at that time. So I don’t think we have actually cut it that fine with a scalpel to kind of make the increase time to the quarter. So I guess arguably it may to be specifically responsive to your question. We have kind of looked at it as year-over-year increases in the dividend of 10%.
Ben Pham
Okay, alright. And on tax reform, thanks a lot for the calculations on that. I was wondering on the cash flow impact, is that when you think about quantification of that is - is using the EBITDA range a good proxy for that or is there some other factors that driving up or down to that starting point?
Ian Robertson
Our – as we looked at trying to provide the market with guidance on the impact, we looked at EBITDA as being a more universally kind of understood metric. And so that’s why we expressed it in terms of its impact on EBITDA. Obviously, as you move down from EBITDA to FFO, there is not a universally acknowledged way of calculating FFO. And certainly the rating agencies even make the adjustments to the FFO to come out with a rating agency adjusted FFO. So just given that EBITDA seems to be more universally accepted as a metric that’s what we chose to give.
Ben Pham
Okay. So it’s possible that impact might be a little bit worse than 3% on cash flow then?
Ian Robertson
It’s as we said it’s 2% to 3% on EBITDA.
Ben Pham
Okay. So you are not planning to disclose the cash flow impact then?
Ian Robertson
No, we don’t think that that’s necessary.
Ben Pham
Alright, okay. Thanks a lot of guys.
Ian Robertson
Thanks Ben.
Operator
Our next question comes from Sean Steuart of TD Securities.
Sean Steuart
Thanks. Good morning guys.
Ian Robertson
Good morning Sean.
Sean Steuart
Good morning. Maybe just following-up on Ben’s question, have you guys spoken with the rating agencies on the tax reform followed and any indication you can provide on how they are thinking about their calculations and potential impact?
David Bronicheski
We actually have. We have had discussions both with – with S&P and DBRS. And I think for both of those agencies, unlike Moody’s I think they are taking a more practical and I will say business approach to it. In our discussions with S&P, I think they acknowledged the things that make us unique being in 12 different regulatory jurisdictions and having so many different utilities and having kind of less leverage in our capital structure. And that’s a key thing, I think too understand and maybe it’s not fully appreciated by people. Given our business mix, we just historically have had less leverage in our capital structure than other pure play utilities. And so the fact that has meant that the impact of tax reform hasn’t been perhaps as a good on us. But so I mean as the rating agencies are looking at, they are certainly the ones that we deal with their – that we are taking a practical approach in kind of a wait and see. And we have open dialogue with them on a regular basis. They know the provisions that and flexibility that we have in our projections and the impact that we see on our 2018 EBITDA. I think our – I could say it’s no worse than having a warmer winter as an example and we face those sort of variabilities all the time just like mother nature can give, mother nature can take away. So there are other things that could go positive this year. We could have a [indiscernible] and those sort of normal variabilities are things that we deal with on a regular basis. And we don’t see that the impact on us this year is anything more than that.
Sean Steuart
Okay. Thanks for that detail David. And I am wondering if you can just comment on the broader opportunity set for late stage wind and solar development projects in the U.S. as developers and investors have had time to digest tax reform, how has the landscape changed?
Ian Robertson
Well, I guess one of the comments that I will just echo the sentiment that David had talked about in terms of the availability of tax equity. So that’s obviously been an important driver in terms of – in terms of renewable energy in the U.S. during the sunset on the tax attributes. And maybe just to add a word to David’s comments, I think we are pleased that or maybe comfortable is the right word that as we have continued our conversation with historic providers of tax equity which are generally the large banks and the insurance companies, etcetera, but there is a little bit of slight quality [ph] going on in terms of the nature of the developers that they want to back, obviously with just a lower tax rate the number of dollars that they have to pay in taxes are expected to drop. And so therefore you might argue that they have a fewer dollars of tax equity that they need to spread around to address their tax needs. I think what they are looking at, we have had some very specific conversations with a number of developers. They want to focus on individual organizations that have a strong track record in terms of being able to get the projects over the finish line that they themselves are an investment grade counterparties. These are all important elements which I think are characteristics that we have. And as I said some of the major providers of tax equity have advised us that we remained on their list. So that is an important driver of value. I think it is undeniable that the price of renewable energy continues to fall even arguably maybe notwithstanding the DOJ solar panel tariff that is still on [ph]. Wind projects are coming down, rotors are getting bigger, efficiency is continuing to grow. I think that you are seeing projects like our Turquoise Solar Project in California being approved, continued focus on California increasing its proportion of renewable energy in a way that lowers customers costs. There is no – from our perspective the wave is continuing, it hasn’t hit the beach yet, Sean. And so we remain confident and comfortable this is a good place for this organization to be with the 30% of our business which is in in the regulated utilities base. And so I think it’s we actually sort of see it as an opportunity for us to do well and do good at same time, just given that the societal benefits from it. I don’t know as if I am starting with a bit of a rambling answer to your question Sean, but hopefully I hit a bunch of the points you are looking for.
Sean Steuart
That’s great context. Thanks Ian.
Ian Robertson
Well, I appreciate it.
Operator
Our next question comes from Mark Jarvi of CIBC.
Mark Jarvi
Good morning. Just wanted to go back…
Ian Robertson
Hi, Mark.
Mark Jarvi
Hi. I wanted to go back to the comments on 2% to 3% impact on adjusted EBITDA, but one if you can clarify the timing of that, is that the expectation for 2018, if that’s the average over the next couple of years and sort of when we will sort of say that the peak of the largest drag is it through 2019, 2020?
David Bronicheski
The guidance we provided was specific for 2018. Beyond that we just don’t have sufficient visibility with the regulatory processes that will be there. So that’s why we have only provided guidance to 2018.
Mark Jarvi
So there is the potential that it could a bit more significant in ‘19?
David Bronicheski
No, I wouldn’t say that at all. I think as we look at it, it certainly wouldn’t be anymore in 2019 than it would be in 2018.
Mark Jarvi
Okay. And then my other question would be on the Bill 564 [ph] which is going through I guess approval in Missouri, just how that constraints you or changed your outlook for capital deployment, the pace of it, rate base growth in that regulatory environment?
Ian Robertson
Yes. It’s obviously challenging legislative environment in Missouri, I think in general we were actually pretty supportive of the bill. As you know one of the big drivers in that is the decoupling aspect of it, which we actually think is a great thing from a customer’s perspective. It’s got a little bit wacky I have to admit in terms of the interactions between State House and the State Senate in terms of that bill. And right now that bill well has passed the house or passed the senate is being debated in the house. So we are actually not exactly sure how this one is going to unfold. But in general, if it got passed the way it was approved in the State Senate, we are actually in support of it Mark. We see it’s constructive in terms of it’s – in terms of the decoupling, it’s constructive in terms of the way we think about investing capital in the utility. So all-in-all, we are cheering it on and I got to tell you that we are just not exactly sure of how others players are interacting on it.
Mark Jarvi
But it wouldn’t impact your plans for greening the fleet initiative?
Ian Robertson
No.
Mark Jarvi
Okay. Thanks.
Operator
Our next question comes from Rob Hope of Scotiabank.
Rob Hope
Good morning everyone. Maybe just a follow-up on Mark’s question thereon about Bill 564, just on the rate cap there wouldn’t that be supportive of the greening the transmission fleet just given that it would reduce customer bills. And then I guess secondly, if you are able to contain costs and manage capital would there be a potential to earn a little bit higher returns there?
Ian Robertson
Well, I wouldn’t say earned higher returns. I mean I think aspirationally we are always looking to earn our authorized return. I think the question that comes up is, are we also able to grow our total investment in the utilities. So between – you are actually – you are absolutely right, you pointed out that our investments in the greening the fleet is actually intended to lower customer bills. And if you want to think of it in the same way as the tax reform, in some respects it lowers customer – it lowers customer bills, create potentially opportunity for us to continue to prosecute our investment going forward. And then with the benefit of decoupling in the state that’s a big start to variability. You will recall that a year ago maybe not quite a year ago this time, we were talking about the warmest wet winter on record in Missouri in terms of its impact on Empire’s results. Clearly, our objective is that’s not helpful for anybody, it’s not helpful for the customers, it’s not helpful for utility. And I think one of the big drivers from our point of view is decoupling. So I will just kind repeat my answer to Mark question, we don’t see the constraints that are in that bill as material and we see the impact on decoupling as a big positive.
Rob Hope
Alright, that is helpful. And then just following the strong Q4, the kind of indicative 2018 guidance that you outlined at your Investor Day, are you seeing more tailwinds or headwinds there or how are you tracking – how does your outlook or has it changed at all?
Ian Robertson
Well, we are in a marathon as you know in terms of the year and we are a couple of months into it. I don’t think it comes as a surprise to anyone that it was a cold start to the winter which if you are in a decoupled electricity and natural gas environment which we are in a couple of our states. That was actually constructive to earnings. But as we said is a fair amount of roads still to walk over the course of the year. So there is nothing we wouldn’t be updating our guidance in as a result of it being cold. I will say one of the things that David didn’t touch on 2018 we are likely to be reverting not likely, we are really reverting to reporting our results in U.S. dollars. And I think that’s part of it is intended to help reduce some of the volatility we see in our Canadian denominated results as a result of FX. Part of that Rob will include a publishing of a little investor talk if you want to think of it that way where we represent historic results in U.S. dollars and then kind of update our guidance for the year. I will use the word small g guidance, because we don’t offer sort of formal guidance, but update our guidance for the year in U.S. dollars. And so I think if there was an opportunity for us to revisit the guidance in the context of all of the changes that have taken place and arguably maybe including how the year has gone so far, that would be something that you can expect to see in the next few weeks, certainly before we announce our Q1 results that will be a denominated and presented in U.S. dollars.
Rob Hope
That sounds great. And then the investor pack would very much be appreciated. So thank you. Thank you all.
Ian Robertson
Yes. We are trying to make your life easier Rob.
Operator
Our next question comes from Jeremy Rosenfield of Industrial Alliance Securities.
Jeremy Rosenfield
It sounds like you are creating more work for us not less, but that’s okay. Let me just ask a couple of questions quickly here, you did comment on Walker Ridge and I am just wondering if there are any updates that you can provide on that and just more generally on the environment for contracting or hedging some wind development projects that you have in the pipeline, how does that look right now?
Ian Robertson
Sure. You accurately pointed that the work is being done right now on Walker Ridge is about obtaining revenue certainty either through power purchase agreements or hedges. And we are discussing that project with a number of potential counterparties. It’s an attractive project and that it’s located strategically in the power market which is empathizing in support of renewable energy and the wind profile of Walker Ridge fits well with the solar profile which as you know is now dominating the California marketing in areas. And so we actually think that the Walker Ridge project and the counterparties that we are speaking share the view that the Walker Ridge project has strategic value and its positioning in the California market. And so we are working our way through that. It is a – obviously it’s a gating item to us making investment in the project. We don’t build merchant energy projects, no matter how much we think the market is supportive of them. And so – but we wouldn’t be continuing for that time and effort in it. We didn’t think there was an opportunity. I think the more broad comment on the market is I guess I will refer back to the rambling answer that I gave earlier in terms of how we think about renewable energy in specifically California. So we continue to see it’s an important part of our business where we are pleased that we have an investment in safe harbor turbines and it’s locked in the 100% PTCs. We are actually pleased that tax reform didn’t impact that in a material way. So it continues to be all full steam ahead from our perspective as we think about renewable energy as part of the overall Algonquin proposition. It us kind of part of that why are we in business here. And I think the pricing and the prospects of renewable energy are definitely supportive of our I will say why for our company, Jeremy.
Jeremy Rosenfield
Okay, good. And maybe if I can just ask one more on tax reform from a broader perspective again thinking of all the companies that potentially have a weaker balance sheet or weaker credit metrics as a result of the impact of tax reform, to what extent if any do you think that, that may open the door for future acquisition opportunities and that along with potentially the slide in valuations in stocks and in light of just a broader rising interest rate environment having weakened sort of valuations and how you see your own valuation relative to maybe potentially acquisition targets?
Ian Robertson
It’s a great thought. And it’s certainly consistent with BD activities that we have been undertaking. We have run some screens on U.S. utility – existing US utilities to kind of identify those utilities for whom tax reform has created pressure on their credit metrics and for whom maybe sale of some or all of their business might be an interesting solution to managing those credit metrics in what is otherwise a fairly mixed equity market right now. Obviously, you can fix your credit metrics by issuing equity, but if your equity is also down as a result of a mixed equity market that maybe the better solution is to sell a portion some or perhaps all of your business at a PDE ratio, which is better than what you could achieve in the equity markets. We definitely see that as a business development basis. I will point out that as you know Jeremy, future M&A is just not part of the type of guidance we give, because it will be completely speculative, but I think your question is insightful in that it’s I think the prospects have actually improved rather than deteriorated for us to execute on things like St. Lawrence Gas, no, I know it didn’t exactly fit the back pedal, but I think we were using a good Canadian simile. We are going to keep our stick on the ice and I think the fact maybe coming our way a little bit more frequently as a result of those things. I don’t know if that’s kind of responsive to where you were going.
Jeremy Rosenfield
Yes, that definitely scores the goal. Thanks.
Ian Robertson
Thanks, Jeremy.
Operator
This concludes the question-and-answer session. I would like to turn the conference back over to the presenters for any closing remarks.
Ian Robertson
Appreciate it, operator. And again, thanks everyone for taking the time and our call today. Before I turn it over to Allison for our riveting disclaimer, I did want to offer a quick comment regarding one of the important, but perhaps less prominent heroes that have been instrumental in building APUC into a leader in our field, Mike Snow, who currently heads up our non-regulated generation business is planning to retire from APUC in the coming few months before we are going to get to speak again on a quarterly call. And so consequently I want to publicly thank Mike, both on a personal basis and on behalf of the APUC family for that. The passion and drive is demonstrated during his time with us. And so again, thank you Mike.
With that, please stay on the line as I said for our riveting disclaimer from Alison Holditch who actually you won’t be hearing next quarter as well, because she will be off on maternity leave, but take it away Alison.
Alison Holditch
Thanks, Ian. During the course of this conference call, we may have made statements relating to the future performance of Algonquin that contains forward-looking information, including statements with respect to the expected performance of the company, its future plans and its dividends to shareholders. While these forward-looking statements represent our current judgments based on certain material factors or assumptions, actual results could differ materially from such forward-looking statements made today.
Additional information about the material factors that could cause actual results to differ materially from such forward-looking information and the material factors or assumptions that were applied in making any forward-looking statements as well as risk factors that may affect the future performance and results of Algonquin are contained in the results press release and Algonquin’s public disclosure documents filed by the company on SEDAR at www.sedar.com and EDGAR at www.sec.gov. We undertake no obligation to update these forward-looking statements unless required by law.
Furthermore, during the course of this conference call, we have referred to certain non-GAAP financial measures including, but not limited to adjusted net earnings, adjusted EBITDA, adjusted funds from operations, per share cash provided by adjusted funds from operations and per share cash provided by operating activities. These non-GAAP measures do not have any standardized meaning under GAAP and may not be comparable with other GAAP or non-GAAP or non-IFRS financial measures presented by other companies. We refer you to our management commentary for more information about the non-GAAP measures, including a reconciliation of the non-GAAP measures to the corresponding GAAP measures where a comparable GAAP measure exists.
Operator
This concludes today’s conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.
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