Q4 2017 Algonquin Power & Utilities Corp Earnings Call
Mar 02, 2018 PM UTC
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AQN.TO - Algonquin Power & Utilities Corp
Q4 2017 Algonquin Power & Utilities Corp Earnings Call
Mar 02, 2018 / 03:00PM GMT
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Corporate Participants
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* Alison Holditch
* Christopher K. Jarratt
Algonquin Power & Utilities Corp. - Vice Chairman
* David Bronicheski
Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc
* Ian E. Robertson
Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director
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Conference Call Participants
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* Benjamin Pham
BMO Capital Markets Equity Research - Analyst
* David Quezada
Raymond James Ltd., Research Division - Equity Analyst
* Jeremy Rosenfield
Industrial Alliance Securities Inc., Research Division - Equity Research Analyst
* Mark Thomas Jarvi
CIBC Capital Markets, Research Division - Director of Institutional Equity Research
* Nelson Ng
RBC Capital Markets, LLC, Research Division - Analyst
* Robert Hope
Scotiabank Global Banking and Markets, Research Division - Analyst
* Rupert M. Merer
National Bank Financial, Inc., Research Division - MD and Research Analyst
* Sean Steuart
TD Securities Equity Research - Research Analyst
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Presentation
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Operator [1]
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Thank you for standing by. This is the conference operator. Welcome to the Algonquin Power & Utilities Corp.'s Fourth Quarter and Year-end Conference Call. (Operator Instructions) And the conference is being recorded. (Operator Instructions)
I would now like to turn the conference over to Christopher Jarratt, Vice Chair of Algonquin Power & Utilities Corp. Please go ahead, Mr. Jarratt.
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Christopher K. Jarratt, Algonquin Power & Utilities Corp. - Vice Chairman [2]
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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'm the Vice Chair of the company. And as usual, joining me on 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 from our website, algonquinpowerutilities.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 position, 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; David 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'll then open the lines up for questions and I ask you to restrict your questions to 2 and then re-queue if you have additional questions.
And with that, I'm going to turn it over to Ian to start with the 2017 strategic achievements.
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [3]
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Thanks, Chris, and good morning, everyone. Thanks for taking the time to join us for our call. I hope that those on the call would agree that 2017 actually marks another year of strong performance for our organization, and I'd like to start off the call by summarizing the strategic achievements of the year. We've split them up into 3 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 under way.
So firstly, Q4 marked a solid financial finish to the year. We're obviously pleased that we achieved year-over-year growth in our results, which has been very strong. And the contributors to -- from our historic successive growth initiatives and that's most notably our Empire acquisition, which closed at the 1st of January of last year. These are the most material drivers of our achievements. 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 a core component of the APUC total shareholder value proposition. We believe that our strong 2017 financial operational performance has been supportive of the 10% dividend increase last year, which was announced by our Board of Directors, and we're confident in our ability to continue to deliver strong earnings and cash flow 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 the commissioning of the 150-megawatt Deerfield Wind Facility and 10 megawatt Bakersfield II 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'd already noted, our Liberty Utilities Group significantly grew at service base with the addition of over 220,000 new utility customer 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're also particularly proud of the seamlessness at which the integration of Empire into 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 to fund 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 a 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 -- or Abengoa-Algonquin Global Energy Solutions team and the investment in 25% ownership stake in the Atlantica Yield. Collectively, these investments, we believe, position APUC well to pursue new avenues of growth within the global clean energy and water infrastructure developments base.
We continued to make positive strides in our commitment to greening our generation fleet. And in early Q4, we announced a 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 the historically constrained U.S. Northeast.
And lastly, we'll continue to grow our customer base through the completion of accretive acquisition, such as the St. Lawrence Gas and City of Perris water distribution systems that we announced last year.
And with that, I'll turn things over to David for a review of the financial results. David?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc [4]
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Thanks, Ian, and good morning, everyone. I'd like to shorten my remarks today on our financial results in order to allow a bit more time for a 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're recording 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 million, 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, 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 on to 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 one-year measurement period for SEC registrants to complete their analysis, interpretations, assessments and presentation of the changes. While we are still interpreting various aspects of the legislation, as at 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'm happy to say that they are largely in line with the initial expectations we provided at 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 in our EBITDA without disrupting our business plans.
So with that backdrop, let's unpack some of the larger elements of tax reform. To frame the impact of tax reform, it's useful to identify those things that are unique about Algonquin. Firstly, our business mix, which is about 10% nonregulated in Canada, 20% nonregulated 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 nonregulated businesses in the U.S., we like most companies with U.S. operations recorded a onetime noncash accounting charge relating to the remeasurement of deferred income taxes, which, for us, is $22.4 million. In that remeasurement, we assume the excess deferred income tax liabilities from our utility operations will eventually be given back to customers and so have set up 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 30 years. Looking forward, for our regulated businesses, taxes are a passthrough 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 nonregulated, it's actually positive. On the nonreg 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 side for a couple more years, this will be modestly negative to EBITDA in 2018, as we've previously noted, but this is within our expectations in are 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 the 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 financings and believe that they are largely unaffected by U.S. Tax Reform.
Turning our attention to rate base 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've provided a forward view on our future rate base growth of approximately 8.3% CAGR at our utilities. As a result of tax reform, we're 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're 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've 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've 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.
Finally, I'd like to end by saying that while it's maybe only natural to focus first on potential downside risk 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 nonregulated 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'll now turn things back to Ian.
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [5]
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Thanks, David. Appreciate the color. As always, we'll open the lines up for questions in a moment, but first, I want to provide an update on our near- to midterm growth initiatives for 2018. Three of them I'd 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 and producing power. We expect the facility to make a full contribution for earnings starting next month. The project suffered some delays in construction primarily related to the heavy rains that occurred over the course of 2017, which made storm water management challenging and, to be frank, which the contractor had a hard time dealing with. But we are -- we've rectified the problems and, as I said, we're looking forward to commissioning before the end of the month.
With respect to Amherst Island, construction is also continuing at the 75-megawatt wind facility located down near Kingston, Ontario. Site completion is well under way, 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, and 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'd like to point out that we see both Great Bay and Amherst as adding further diversity to our nonregulated power production fleet, both by geography and generating source. The diversity of our generating portfolio remains a key element of our continued delivery of stable long-term financial results.
And the last I'd 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 and LNG project is an opportunity to reduce energy costs for our New Hampshire LDC customers. Granite Bridge consists of a 27-mile underground lateral pipeline and a liquefied natural gas liquefaction, storage and regasification facility. This approximately $350-million investment is expected to result in significant customer savings through new lower cost supply easing the historic source constraints in the Northeast, along with increased tax revenues for the various supportive communities in the region. We're currently advancing the regulatory approval process pursuant to filings, which were made late last year.
Next, I'd 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've remained 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 USD 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 in system improvements is actually we see recoveries of these investments in customer rates. On this front, in 2018, we're planning to prosecute another 8 rate cases totaling approximately USD 45 million in requested incremental revenues.
With respect to our customer-first initiative. As our business has continued to grow, and we're close to 800,000 customers today, we've 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 future-proof, 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're 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 in providing strategic leadership to this initiative.
And lastly, but certainly not least, we continue to be excited about the inaugural steps we've taken into international infrastructure investment through the formation of AAGES and are supporting 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 at hand, with all material conditions present to closing satisfied and the mechanical process of closing to be completed in the next couple of days. Perhaps more strategically, we're pleased to report that AAGES is fully staffed with ex-Abengoa and Algonquin developers who are up and running, with project opportunities being actively pursued in concert with our new partners. Specifically, we're 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 its financial and strategic objectives through these various avenues for growth and deliver our 10% projected annualized earnings growth. Our historic earnings and cash flow growth has supported an industry-leading dividend growth profile, which we're confident we can continue over the coming few years.
With that, operator, I'd like to open it up for questions.
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Questions and Answers
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Operator [1]
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(Operator Instructions) Our first question comes from David Quezada of Raymond James.
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David Quezada, Raymond James Ltd., Research Division - Equity Analyst [2]
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My first question is just on the popular topic of tax reform, but just on kind of the positive elements of it. Wonder if you can provide any color on what the potential is to speed up capital over your, call it, 5-year planning horizon?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [3]
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Sure. And so why don't we focus first on the regulated utilities? And clearly, lowering the amount of customer -- the amount that customers effectively have to pay for the income taxes and [stuff to] pass through to customers, I think you're referring to -- it certainly, if you will, maybe creates notional headroom in customer rates. And so to the extent that we had safety and reliability in other projects that we might, otherwise, have pushed out to another year, it creates an opportunity to invest in those projects. We kind of estimated that as a couple-$300 million a year over the next 4 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 cost they're incurring today, we're all over it. I don't know if that's responsive to your question, David, as to kind of where you were going.
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David Quezada, Raymond James Ltd., Research Division - Equity Analyst [4]
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It is, absolutely. That's helpful. My only other question is just -- I know that the California Public Utility Commission has recently come up with a new planning process that's aimed to support renewables. Wondering what your most recent thoughts are there and if you see any incremental opportunities from that new planning process.
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [5]
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Well, we certainly see California as a target market for 2 things. Our nonregulated generation business. We've been talking over the past quarter or so about our Walker Ridge project that we're pursuing. It's strategically relocated in a market, which, as you kind of point out, is both supportive now and arguably 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'll ultimately get to. But secondly, within our little California Utility, we actually think through initiatives like our battery and solar installation that we've 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're 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're keen on California, just getting keener. I don't know if that's what you're looking for.
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Operator [6]
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Our next question comes from Rupert Merer of National Bank.
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Rupert M. Merer, National Bank Financial, Inc., Research Division - MD and Research Analyst [7]
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Looking at the changes from U.S. taxes, I realized it's early and you work in a number of jurisdictions. So 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 would those changes typically be retroactive?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc [8]
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Right now we're 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, currently, based on what we're seeing, it looks like it's going to be somewhere in this 24- to 36-month period, 36 would be the outside date, I would think. So people should think of it in that sort of time wise.
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [9]
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And I'd offer up, Rupert, just to square that circle that we have to kind of look at net impact. Obviously, we've got ongoing capital investment in all of these utilities, which would -- will -- I guess, will change the outcome of those rate cases while, 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.
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Rupert M. Merer, National Bank Financial, Inc., Research Division - MD and Research Analyst [10]
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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're looking at $1.7 billion. And if so, is there a pushing out of some of the schedules? Is that something you're doing deliberately? Or have you had some moving parts in some of the approvals for some projects? Just your comment on the CapEx plan.
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc [11]
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Sure. First, I think it's important to understand that really it's just a -- think of it as that changes deferral of CapEx into future year, largely next year, and so it doesn't change our 5-year CapEx plan in any way. Following tax reform, we've 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 put -- 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.
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Operator [12]
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Our next question comes from Nelson Ng of RBC Capital Markets.
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Nelson Ng, RBC Capital Markets, LLC, Research Division - Analyst [13]
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Quick one on Amherst Island. So are you -- I'm just wondering how much of the costs have been locked in, given the increase in the range. Do you use a EPC contractor for that -- for the construction of that site?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [14]
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We do. But I'll 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 coal at the beginning of the year and the rain and the thaws that have taken place, those conditions have kind of deviated. And I think that's probably the largest source of where those -- where the increase in costs have come. I will say that as we look forward and forecast those costs, we've tried to reflect the best knowledge we have in terms of the conditions that we're encountering. And so while there's no guarantee on God's will when it comes to weather going forward, we've tried to be as prudent as we possibly can. So I don't want to say just bad luck. I think -- I don't think it's an unreasonable observation that the Ontario permitting and renewable energy environment kind of causes perhaps suboptimality in terms of the timing of construction. They have some very specific dates that you need to comply with. There is little latitude in those dates and maybe that's understandable. But you certainly end up doing things that if you had as much time as you wanted, then you might say, "Well, I'll defer building that road until May instead of doing it in the middle of January." But it is what it is. I think we're -- we continue to be comfortable that the returns in 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, it's certainly something that's manageable.
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Nelson Ng, RBC Capital Markets, LLC, Research Division - Analyst [15]
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And just a follow-up on that. So for Blue Hill Wind, I guess, the expectation is you'll also use an EPC contractor, and there's likely going to be, I guess, 0 moving parts in terms of scheduling.
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [16]
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Well, there's 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. The Chaplin 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're -- we acknowledge the differences, and, yes, we do use an EPC contract, and we expect to have that kind of same level of success we've had historically.
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Nelson Ng, RBC Capital Markets, LLC, Research Division - Analyst [17]
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Okay. And then 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'm just wondering is there a typical period where the board kind of reviews the financials and the payout ratio in more detail?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [18]
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Yes, there is. And historically, if you go back, I'll say, more than last year, maybe the year before, it's always been a Q2 initiative. We have our strategic planning process and, we review with the board our expectations of growth going forward. And so typically, it's been handled -- and you're 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 midyear initiative. I think you'd probably conclude that the results were strong and supportive of our objectives from a dividend increase perspective. But I think we had decided that from the board's perspective we would, I'll 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.
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Operator [19]
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Our next question comes from Ben Pham of BMO Capital Markets.
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Benjamin Pham, BMO Capital Markets Equity Research - Analyst [20]
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I wanted to go back to that -- Nelson's question on the dividend. And I wanted to clarify when you think about your 10%, is that really promising shareholders that you'll raise the dividend 10% sometime during the year? Or you think of it as a calendar year average through late decade?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [21]
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You know what, to be frank, we probably don't get that fine in our math, Ben. I think as we think about it, I'll say, sometime during the year and, generally, it's either been 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've actually cut it that fine with a scalpel to kind of make the increase timed to the quarter. So I guess, arguably maybe to be specifically responsive to your question, we kind of look at it as year-over-year increases in the dividend of 10%.
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Benjamin Pham, BMO Capital Markets Equity Research - Analyst [22]
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Okay. All right. And on tax reform, thanks a lot for doing all the calculations on that. I was wondering on the cash flow impact. Is that -- when you think about qualification of that, is that -- is using the EBITDA range a good proxy for that? Or is there some other factors that drive it up or down to that starting point?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc [23]
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As we look at trying to provide the market with guidance on the impact, we've 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's not a universally acknowledged way of calculating FFO and certainly the rating agencies even make adjustments to 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 use.
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Benjamin Pham, BMO Capital Markets Equity Research - Analyst [24]
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Okay. So it's possible its impact might be a little bit worse than 3% on cash flow then?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc [25]
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It's -- as we said, it's 2% to 3% on EBITDA.
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Benjamin Pham, BMO Capital Markets Equity Research - Analyst [26]
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Okay. And so you're not planning to disclose the cash flow impact then?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc [27]
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No. We don't think that that's necessary.
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Operator [28]
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Our next question comes from Sean Steuart of TD Securities.
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Sean Steuart, TD Securities Equity Research - Research Analyst [29]
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Maybe just following up on Ben's question. Have you guys spoken with the rating agencies on the tax reform fallout? And any indication you can provide on how they're thinking about their calculations and potential impact?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc [30]
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We actually have. We've had discussions both 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'll say, business approach to it. In our discussions with S&P, I think they acknowledged the things that make us unique being in both 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, to 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 that has meant that the impact of tax reform hasn't been perhaps as great on us. But -- so I mean, as the rating agencies look at it, certainly, the ones that we deal with, they 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 and flexibility that we have in higher projections. And the impact that we've seen on our 2018 EBITDA, I think, I can 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 windier year, for instance. 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.
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Sean Steuart, TD Securities Equity Research - Research Analyst [31]
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And, Ian, 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's the landscape changed?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [32]
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Well, I guess, one of the comments that I'll 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 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're pleased that -- or maybe comfortable is the right word that as we have continued our conversation with the historic providers of tax equity, which are generally the large banks and the insurance companies, et cetera, that there is a little bit of a flight to quality 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're looking at, we've 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 to projects over the finish line that they themselves are an investment-grade counter party. These are all important elements, which, I think, are characteristics we have. And as I said, some of the major providers of tax equity have advised us that we remain on their list. So that's an -- that is an important driver of value. I think it is undeniable that the price of renewable energy continues to fall, even arguably maybe not withstanding the DOJ solar panel tariff that is still, and all the wind projects are coming down, rotors are getting bigger, efficiency is continuing to grow. I think that you're 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. (inaudible) from our perspective the wave is continuing. It hasn't hit the beach yet, Sean. And so we remain confident and comfortable that it's a good place for this organization to be with the 30% of our business, which isn't in a regulated utility space. And so I think it's -- we actually sort of see it as an opportunity for us to do well and do good at the same time just given the societal benefits from this. I don't know, as I said, I'm sorry, it was a bit of a rambling answer to your question, Sean. But hopefully, I hit a bunch of the points you were looking for.
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Operator [33]
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Our next question comes from Mark Jarvi of CIBC.
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Mark Thomas Jarvi, CIBC Capital Markets, Research Division - Director of Institutional Equity Research [34]
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I just wanted to go back to the comments on 2% to 3% impact on adjusted EBITDA. I want -- if you can clarify the timing of that. Is that the expectation for 2018? Is that the average over the next couple years? And sort of what -- when can we sort of say that the peak or the largest drag? Is it through 2019, 2020?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc [35]
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The guidance we've 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've only provided guidance to 2018.
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Mark Thomas Jarvi, CIBC Capital Markets, Research Division - Director of Institutional Equity Research [36]
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So there's a potential that it could be a bit more significant in '19 though?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc [37]
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No, no, no. I wouldn't say that at all. I think as we look at it, it certainly wouldn't be any more in 2019 than it would be in 2018.
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Mark Thomas Jarvi, CIBC Capital Markets, Research Division - Director of Institutional Equity Research [38]
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And then my other question would be on the Bill 564, which is going through, I guess, approval in Missouri. Just how that constrained you or changed your outlook for capital deployment, the pace of it, rate base growth in that regulatory environment?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [39]
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Yes. It's obviously a challenging legislative environment in Missouri. I think, in general, we're 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 customers' perspective. It's got a little bit wacky, I have to admit, in terms of the interactions between the state house and the state senate in terms of that Bill. And right now, that Bill, while it's passed the house -- passed the senate, is being debated in the house. So we're 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're actually supportive. Mark, we see it's constructive in terms of its -- in terms of the decoupling; it's constructive in terms of the way we think about investing capital in the utilities. So all in all, we're cheering it on. I've got to tell you though we're just not exactly sure of how all the players are interacting on it.
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Mark Thomas Jarvi, CIBC Capital Markets, Research Division - Director of Institutional Equity Research [40]
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But wouldn't impact your plans for Greening the Fleet initiative.
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [41]
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No, no, no.
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Operator [42]
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Our next question comes from Rob Hope of Scotiabank.
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Robert Hope, Scotiabank Global Banking and Markets, Research Division - Analyst [43]
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Maybe just a follow-up on Mark's question there on 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?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [44]
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Well, I wouldn't say we earn higher returns. I mean, I think, aspirationally, we're 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're actually -- you're absolutely right, you point out that our investment 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, creates potentially opportunity for us to continue to prosecute our investments going forward. And then with the benefit of decoupling in the state, that's a big source of variability. You'll recall that a year ago, maybe not quite a year ago, this time, we were talking about the warmest 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 the utility. And I think one of the big drivers from our point of view is decoupling. So just to kind of repeat my answer to Mark, which is, we don't see the constraints that are in that bill as material, and we see the impact on decoupling as a big positive.
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Robert Hope, Scotiabank Global Banking and Markets, Research Division - Analyst [45]
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All right. That is helpful. And then just following the strong Q4, the kind of indicative 2018 guidance that you had outlined at your Investor Day. Are you seeing more tailwinds or headwinds there? Or how are you tracking -- or how does your outlook -- or has it changed at all?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [46]
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Well, we're in a marathon, as you know, in terms of the year, and we're a couple 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're 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 I said, there's a fair amount of road still to walk over the course of the year. So there's 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're likely to be reverting -- not likely, we're going to be reverting to reporting our results in U.S. dollars. And I think that's -- part of it is intended to help reduce the volatility we see in our Canadian-denominated results as a result of FX. Part of that transition, Rob, will include a publishing of a little investor pack, 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'll 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 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 denominated and presented in U.S. dollars.
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Robert Hope, Scotiabank Global Banking and Markets, Research Division - Analyst [47]
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That sounds great. And then the investor pack would very much be appreciated.
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [48]
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Yes. We're trying to make your life easy, Rob.
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Operator [49]
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Our next question comes from Jeremy Rosenfield of Industrial Alliance Securities.
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Jeremy Rosenfield, Industrial Alliance Securities Inc., Research Division - Equity Research Analyst [50]
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Sounds like you're 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'm 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?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [51]
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Sure. You accurately point that the work that's 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 counter parties. It's an attractive project in that it's located strategically in the power market, which is emphasizing and supportive 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 market in areas. And so we actually think that the Walker Ridge project and the counter parties with whom we're speaking share the view that the Walker Ridge project has strategic value in its positioning in the California market. And so we are working our way through that. It is -- 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 to invest time and effort in it, if we didn't think there was an opportunity. I think the more broad comment on the market is, I guess, I'll refer back to the rambling answer that I gave earlier in terms of how we think about renewable energy and, specifically, California. So we continue to see it as an important part of our business. We're pleased that we have an investment in safe harbor turbines and have locked in 100% PTCs. We're obviously 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 is kind of part of the why are we in business here. And I think the pricing and the prospects of renewable energy are definitely supportive of our, I'll say, why for our company, Jeremy.
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Jeremy Rosenfield, Industrial Alliance Securities Inc., Research Division - Equity Research Analyst [52]
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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 sheets or maybe weaker credit metrics as a result of the impacts 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 in light of just the broader rising interest rate environment having weakened sort of valuations and how you see your own valuation relative to maybe potentially acquisition targets?
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [53]
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It's a great thought. And it's certainly consistent with BD activities that we've been undertaking -- taken. We've run some screens on U.S. utility -- existing U.S. utilities to kind of -- to 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 mixed equity markets, that may be the better solution is to sell a portion some or perhaps all of your business at a P to E ratio, which is better than what you can achieve in the equity markets. We definitely see that as a business development thesis. 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 would be completely speculative. But I think you are -- 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. I know it doesn't exactly fit the [back pattern], but I think we were using a good Canadian simile. We're going to keep our stick on the ice, and I think the puck may be 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.
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Operator [54]
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This concludes the question-and-answer session. I would like to turn the conference back over to the presenters for any closing remarks.
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Ian E. Robertson, Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director [55]
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Appreciate it, operator. And again, thanks, everyone, for taking the time in our call today. Before I turn it over to Alison 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 nonregulated Generation business, is planning to retire from APUC in the coming few months before we're going to get to speak again on a quarterly call. So consequently, I want to publicly thank Mike both on a personal basis and on behalf of the APUC family for the passion and drive he's 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'll be hearing next quarter as well because she'll be off on maternity leave. But take it away, Alison.
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Alison Holditch, [56]
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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 judgment 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 at 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 activity. These non-GAAP measures do not have any standardized meaning under GAAP and may not be comparable with other non-GAAP or non-IFRS financial measures presented by other companies. We refer you to our management commentary for more information about these non-GAAP measures, including a reconciliation of the non-GAAP measures to the corresponding GAAP measures where a comparable GAAP measure exists.
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Operator [57]
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This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.
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