Algonquin Power & Utilities Corp Analyst and Investor Day - Toronto

Dec 05, 2017 AM EST
AQN.TO - Algonquin Power & Utilities Corp
Algonquin Power & Utilities Corp Analyst and Investor Day - Toronto
Dec 05, 2017 / 01:30PM GMT 

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Corporate Participants
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   *  Armando Zuluaga
   *  Charles Ashman
      Algonquin Power Co. - VP of Technology
   *  Christopher K. Jarratt
      Algonquin Power & Utilities Corp. - Vice Chairman
   *  David Bronicheski
      Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc
   *  David James Pasieka
      Algonquin Power & Utilities Corp. - COO of Liberty Utilities Group
   *  Elizabeth Dumm
   *  Gerald Tremblay
   *  Ian E. Robertson
      Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director
   *  Jeff Norman
   *  Jennifer Sara Tindale
      Algonquin Power & Utilities Corp. - Chief Legal Officer
   *  Joanne Atalay
   *  Peter Eichler
   *  Rahi Nathwani

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Conference Call Participants
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   *  Benjamin Pham
      BMO Capital Markets Equity Research - Analyst
   *  Jeremy Rosenfield
      Industrial Alliance Securities Inc., Research Division - Equity Research Analyst
   *  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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 Christopher K. Jarratt,  Algonquin Power & Utilities Corp. - Vice Chairman   [1]
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 All right. Welcome, everybody. For those of you who are counting, this is our eighth annual Investor Day. My name is Chris Jarratt. I'm the Vice Chair of Algonquin Power. With us on the first panel is Ian Roberts, our Chief Executive Officer -- most people know Ian; and David Bronicheski, our Chief Financial Officer. Before we get started, there's also a couple of board members we have in the audience. And then just -- I might just ask them to stand up as we go. I see Chris Ball in the front row here; Ken Moore, our Chair; and George Steeves is here somewhere. There is George at the back. So I hope you get a chance to meet them and talk to them throughout the break.

 While we're talking anniversaries, this is also our 20th anniversary of being a public company. And when I think back to our IPO, which was just the end of 1997, we raised $80 million to purchase 17 small hydro sites. So you can certainly see that growth is part of our DNA for sure. What's also interesting, there's a couple faces in the audience I've seen who were part of that IPO. So it's nice to see people who have been long-term followers of Algonquin.

 Just the agenda for today. It's -- as usual, it's designed to give you an overview of the organizations broken into sections, and we will be having questions and answers at the end of each section. In addition, and this is primarily for the people who are watching remotely, slido -- if you go into slido.com (sic) [www.sli.do] and enter the event code of 2017aqninvestorday, all one word, you can pose questions and take a short survey online.

 Our plan is to finish by noon, but there will be a lunch and learn by our in-house science Guy, Charlie Ashman, and that's on solar and energy storage. It was quite interesting. So I hope you stick around for that.

 Before we get started, we're going to have a safety moment. And for those of you who have followed us for some time, you'll know what the safety moment is. But for those who don't -- who haven't, I'll just give you a quick overview of what it is. We have 2,300 employees throughout North America, and many of them deal with potentially hazardous materials such as high voltage, natural gas, working from the tops of turbines and around fast-moving water. So appreciate that for us, safety is paramount. And one of the ways that we bring safety to top of mind for everybody is to do what's known as a safety moment. And we always call on someone at every meeting and at random to share some thoughts on safety that are personal to them. So for today, David Williams. No, just kidding.

 Our...

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 Unidentified Company Representative,    [2]
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 (inaudible) on my BlackBerry.

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 Christopher K. Jarratt,  Algonquin Power & Utilities Corp. - Vice Chairman   [3]
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 Don't text and lock. So for this one, we're going to call on Jen Tindale, and I selected Jen, not at random, because Jen is our Chief Legal Officer and she's recently joined us. So hopefully, you get a chance to speak with Jen. So Jen?

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 Jennifer Sara Tindale,  Algonquin Power & Utilities Corp. - Chief Legal Officer   [4]
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 Good morning, everyone. Is this on? Okay. I also got to do the safety moment at my first board meeting when I joined Algonquin. And I didn't have a little preface to warn me of that. I didn't even know what a safety moment was about. So happy to do it this morning, though.

 I think I'll put a little bit of a seasonal theme to the safety moment because I'm reflecting on something that I witnessed this past weekend as I headed out to start my Christmas shopping. I was in a busy shopping mall parking lot walking towards the entrance, and I saw a car backing out of its parking spot. And I admit it was a woman. The woman in the car was jostling with her shopping bags, putting some of them in the back seat, it seemed, as she backed up and backed up and backed up a little more until she backed right into a car that was driving down the aisle. Now it was just a fender bender. Nobody was hurt. But the safety moment in this is something that we actually encourage at all our sites at Algonquin. And that is that when you arrive somewhere, it's actually safer to take a moment to back into your spot at that time so that when you come out at the end of a long workday or, in this case, at the end of a long shopping outing, you are able to drive forward into the aisle at a time where you might be tired or a little bit distracted or in a hurry to get home or a hurry to get to your next holiday party. So just something for you to keep in mind. And wishing everybody a happy and safe holiday season.

 And with that, I'll pass the mic back over to Chris.

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 Christopher K. Jarratt,  Algonquin Power & Utilities Corp. - Vice Chairman   [5]
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 Thanks, Jen. So I'm just going to give you some of the highlight and key messages for the day.

 We always talk about growth, and that's a huge part of our business. But sometimes, it gets forgotten that underlying this growth and underpinning the organization is a pretty large asset base that is -- provides reliable, stable cash and earnings, and we just want to keep that in mind as we've got assets of over $10 billion, which are continuing to kick out cash and earnings for the -- for decades to come. The second is this robust and resilient business model. I mean, everybody talks about disruption and changes to the industry, and we like to think we've been part of that. And sometimes, we've actually been the disruptors. So we understand that. We do it through an entrepreneurial mindset, and we actually embrace these disruptive changes and see them as opportunities.

 The third point we want to leave you with is this industry-leading growth profile. We're going to give you lots of details on that, but we have line of sight on $9.7 billion -- or $7.7 billion of growth. And the key to this is it's not growth for growth's sake, it's always growth which is accretive on many metrics, earnings, cash flow, many, many metrics we use to make sure that whatever we do is accretive. The last point we're going to leave you with is something fairly new, and this is this international strategy that we announced in November. And we want to give you a few more details on that, but the points to this are it's strategic in nature, it's very measured and it, as I said, the last point, it's very accretive to earnings and growth profile right out of the gate. So those are the 4 key messages we'd like to leave with you.

 And with that, I'm going to pass it over to Ian, who is going to talk about some of the macro environmental considerations.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [6]
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 Perfect. Thanks, Chris. So as Chris mentioned, my name is Ian Robertson, Chief Executive Officer of Algonquin Power & Utilities Corp. I've been here for every one of those 8 Investor Days. And in fact, Chris and I were one of the founders of the company back, I guess, close to 30 years ago. Feels like a blink of an eye. But I wanted to spend a couple of minutes talking about the -- some of the macro environments considerations in which our business operates so you can kind of maybe put in context some of the things you're going to hear through the rest of the morning.

 So the first one is -- maybe actually I'm going to talk about something that actually isn't changing, and it is the nature of our business, the fact that what we do from our perspective is really founded in the fabric of society. It's hard to deny the anthropological necessity of reliable water, gas, electric service. It's really baked into something that we're going to -- I'll spend a minute talking about the why. Why are we here? Why do we do what we do?

 But one of the things that is changing is the nature of our customers. We have close to 800,000 utility customers on our regulated utility business, and their demands, desires are definitely changing. They're becoming more technologically savvy. They are demanding insight on the electric side into where their electrons have come from in terms of the source. They are willing to invest in renewable generation, which has its own impacts. But all in all, this demand for flexibility on the part of our customers is actually occasion, an opportunity to invest $300 million over the coming 5 years to create the infrastructure that'll allow us to meet their demands.

 Second thing I want to spend a little bit of time on is environmental stewardship and social engagement. And it feels a little bit right now, to be frank, over the -- certainly over the events of the past week a bit of a story of contradictions. On one hand, you're seeing corporations following the lead of our individual customers out there procuring renewable energy, doing direct purchases of wind and solar energy to meet their energy needs.

 Your -- there's a group here called the RE100, which is -- right now, it's 117 global corporations who have made a public statement: We want to meet 100% of our energy needs through renewable energy. And you're seeing carbon pricing paradigms being put in place globally, in the U.S. But then juxtaposition it, we're seeing tax reform in the U.S., which appears to have -- and maybe it's an unintended consequence. I'm going to talk a little bit about this. It appears to have left renewable energy a little bit by the side. Now the good news on that is I'm not actually sure, the renewable energy, and you're going to hear a story, that it doesn't actually need tax attributes to be competitive, but it does feel like there's a little bit of a schizophrenia going on.

 But I guess -- and the last point is 70% of our business is in the regulated utility space, and so therefore, we attorn to the jurisdictions of our regulators. But one of the things that we are cognizant of is that the regulatory environment is actually not moving with the pace that the technological and, therefore, customer environment is moving. And so we are cautious as we think about whether the regulator is going to be there to protect us going forward.

 If you think of the regulated utility business as operating inside a moat or a fence, our belief is that fence is being breached, and it's being breached by companies that want to come in and disintermediate that relationship we have with our customer. And I think you -- if you believe that the regulator is going to be there to protect you, I think you do so at your peril. And we always quote the example of Uber and yellow cab. I'm sure yellow cab -- there were a lot of discussions within yellow cab where they thought the New York Taxi Commission was going to be -- was established to protect their business model and their business. And frankly, when Uber came along and started to disintermediate that relationship, I'm sure yellow cab felt a little bit abandoned from a regulatory perspective. Acknowledging that from our perspective and, as Chris said, capitalizing on our entrepreneurial spirit, not to kind of rest on that, I think, is part of who we are.

 I talked about these disruptors. There's kind of 3 that I think bear certainly mentioning. One is inexpensive renewable energy is just the norm. You're going to hear the story about it being the cheapest form of generation. The second is energy storage and its potentially disruptive effect. And third is connectivity between our customers, which is really reducing transactional barriers, and I'll talk about what the impacts of that are.

 So first, renewable energy. Bar none, there is no cheaper way of producing that next new kilowatt-hour than from a renewable energy source. And I would argue that is completely independent of whether PTCs, these production tax credits, or ITCs exist. It is just the cheapest form of generation. And that threatens the premise of the investment historically in large coal, even combined cycle natural gas plants.

 The second thing that renewables are doing, they're changing the topology of the grid. They're changing the way people have constructed the grid. Historically, you can imagine large coal plant, big, long transmission line into a distribution into a city. Well, now you start putting solar panels on the tops of people's houses. That generation is happening not only when the load is but where the load is. And it's changing the nature of investment in the grid going forward.

 Energy storage. This one has the potential to strike at the core of the relationship of dependence that a customer has had historically on its utility. You can imagine not -- I guess arguably a few years ago, you walked into your living and flipped the switch on. You counted on the utility to have a spinning reserve, a generator spinning, so when you flipped the switch on, electrons flowed and the light came on. And there was just no other alternative. Cheap energy storage fundamentally changes that relationship of dependence. It decouples the process of generating electricity from that of consuming the electricity. And so all of a sudden, that customer is no longer dependent on the utility to have a spinning reserve.

 And in fact, there's an interesting graph. And this was prepared by Ernst & Young, and what they're showing here is here's the price of electricity, but here's the expected cost of generating your own electricity or generating it locally with battery storage. You can see that there's actually a crossover point, I'll say, within 10 years, and that will bring -- and so what theoretically it could cause to happen, you could actually leave the grid. You could say, thanks, I don't -- I won't take your electricity. I actually don't think that, that's the outcome because I think there's value being connected to the grid. But what it does do is it will introduce competitive pressure to the electric utility, whose costs are doing this and the alternative costs to those customers are doing that. That is something that needs to be recognized.

 And the third disruptor is something as today pedestrian as the Internet. It now, let's say, costs $50 to connect a device to the Internet. And so all of a sudden, this thought of my washing machine being able to communicate with David Williams' Tesla in his garage to borrow energy from it at a time that makes the most economic sense is actually a reality. You don't even -- is this -- we're not telling you flying car stuff. But all of a sudden, that transactional -- that transaction could take place between my washing machine and David Williams' Tesla without the oversight of the utilities. So talking about disintermediation of a relationship. These are kind of some of the disruptors. And as I said, these are on the horizon right now. We see them as opportunities rather than threats.

 A hot topic today is tax reform. And I wanted to kind of -- we're going to talk about tax reform throughout each of the presentations on a nonregulated renewable energy group through Liberty Utilities, David Bronicheski is going to talk about it. But I wanted to give just a summary, an all-in-one place kind of summary of what we think tax reform is likely to bring. And the reason I use likely is at these 10 seconds, we actually don't know. As you -- this is a process. It's kind of a little bit like making sausage. You don't really want to watch it. You don't really know what the outcome is going to be until it's finally done. And so this is, I'll say, speculation on our part.

 The first comment is, it's pretty clear that there's consensus that corporate tax rate's going down. And in general, I -- it'd be hard to imagine you can find businesspeople standing on a stage and saying, oh, we don't like the fact that corporate taxes are going down. So in our case, it's actually probably a greater case of indifference. Our regulated utility business taxes are the responsibility of our customers. And so we're a little bit indifferent to the tax rate. In fact, a lower tax rate probably will occasion an opportunity to invest more capital is one way we look at it. The lower tax rate will certainly cause our rate base to grow faster through slower growth in something called accumulated deferred income taxes, ADIT. So all in all, the lower tax rate's a good thing. I think if there is a cash flow impact, and that's one of the things that we need to talk about, it's likely going to be spread over the -- over a number of years. And so when you look at it in the totality, on any individual year, it's not going to be all that material. And Elizabeth Dumm is going to speak to -- talk a little bit about that process.

 The second thing, and this is the big news that you hear about, is, what's the impact on renewable energy? Well, I guess the short answer is, it's obviously not a great thing from our perspective that the PTCs appear to be -- and I don't know if it's an unintended or collateral damage, but the PTCs could -- the availability of tax equity could be threatened by this. The good news -- a couple of, I'm going to say, pieces of good news from our perspective, there's another monetization strategy called an investment tax credit, which, from our perspective, and it depends on the wind regime, is actually a very viable alternative to financing our projects. But most importantly, and I guess from our perspective, you have heard us speak of this greening the fleet initiative, this idea of replacing oxymoronically a perfectly good coal plant with 800 megawatts worth of new wind. The thesis for that investment remains on track irrespective of tax reform. And I think that's obviously an important part. It's $1.5 billion of that $7.7 billion that Chris mentioned. So it's a significant investment opportunity. We're pleased that it remains feasible and viable notwithstanding those changes.

 And the last one and I don't want to say if it's all bad. These tax revisions, as you -- most of you are aware, we don't pay cash taxes today. Our horizon is kind of 2022 right now. Depending on how these alternative minimum tax and these BEAT tax provisions come in, that could advance the taxability horizon by a year or 2. I think the silver lining to that is that all of a sudden, we could follow the lead of somebody like Warren Buffett in his MidAmerican company, where they are their own tax equity. So they invest in renewable energy projects to shelter their own taxes. And so first prize from our perspective is to be sufficiently taxable to be able to shelter our own taxable income and earn the returns that tax equity are earning ourselves. So obviously, this is just a quick overview. We're going to dig into tax reform a little bit deeper.

 So kind of to sum up, what are the opportunities that we see in this environment of disruption? Well, first, I'll say we start by seeing disruption as changed and change playing to the strengths of Algonquin. We see ourselves fundamentally as an entrepreneurial organization. And as I said, we see opportunities where others see threats. The second thing is the falling price of renewable energy cannot help but result in greater penetration. And the expectation is that renewables will continue to grow in their presence. Why? Not because they're being encouraged by state or federal policies in the U.S., because they're just the cheapest form of generation bar none. And so that will continue to happen. I think that energy storage that we talked about will occasion more the ability of the grid to accommodate more renewables, and that'll be -- that is certainly an opportunity.

 From our perspective that we sort of look at ourselves and we ask, do we have the characteristics that are needed to be successful in that environment. And I'd argue that there are kind of 3 things that a utility company needs to demonstrate in order to be successful in this environment. First, and this feels easy for us, but I can imagine it's hard if you've been in the utility business for 100 years, you've got to start to look at the world from your customers' perspective rather than your own. Historically, the utility compact was, I invest in public assets and I get to earn a return on them. And I am -- and I get to make that decision as to whether it's a prudent or an imprudent investment decision with the oversight of a regulator. Well, today, with that fence, that moat around our utility business having been breached, you now have to think that there is somebody phoning your customer right now, trying to disintermediate that relationship, offering that storage, that renewable energy, in a way that will, I guess, stand in the way of the relationship that we historically had. And so customer centricity is going to be an important part of the success of a business.

 The second one is being willing to acknowledge the fact that, you know what, the world is changing and you're going to have to embrace new business models. And lastly, and this feels antithetical to a utility business, is cost competitiveness. Historically, people -- utilities would say, we're in a safe, reliable, affordable business in terms of provision of utility services. I would say it's as safe, reliable and competitive now. And that's kind of a hard mindset to make the shift. So part of, I guess, my role, spend a little bit of time on our mission and vision. I think it helps put in context everything we're doing.

 But actually, before I started that, I do want to talk a little bit about a personal epiphany that I had in reading a researcher by the name of Simon Sinek. He postulated that many organizations actually made a mistake and have -- they spend a lot of time talking about what they do, maybe even how they're distinguished. But what they missed was the why. And the why of why an organization exists is the way that you actually touch people. It resonates with them. He quoted an example -- I'll just quickly -- Martin Luther King. Martin Luther King certainly was -- he was not the only African-American who suffered as a result of social injustice. He wasn't the best orator of the day. But what he did, he didn't start with the, let me tell you my 12-point plan for fixing social injustice in the U.S. He actually started with something that actually resonated and touched people with his obviously I Have a Dream. And clearly, that why allowed him to be successful where others were not.

 And so I wanted to spend a little bit of time about our why. Our why relates back to that very first comment that I made about what we do and its role in society today. We fundamentally believe that the water, gas, electric services we provide are fundamental to the fabric of modern society, what we consider modern life. And I think we are pleased as a group that the way we're doing it, our focus on renewable energy, is helping to contribute to sustainable energy and water future. And just to put that in context for those of -- you don't have to look back very far. Two, 3 months, we watched Hurricane Irma kind of go up Florida, deal a pretty devastating blow. And I was watching CNN, and there was a story about a guy who was sitting on his front porch through the night with a machete, defending his family from looters, et cetera. And that was 2 days after the loss of electric service. And so it's hard not to acknowledge like, oh my gosh, what you really do -- what you do is important to the fabric of society.

 And so I think as we sit here in building the safest, the cleanest, the most reliable utility company, I'd like to speak on behalf of everybody at Algonquin, saying is that we actually feel that we're doing something special, that we're actually creating something that really can make a difference. So there's our why. But perhaps -- and actually, you know what? I'm going to go back here. And just as a why, this is a picture here. 4:30 in the morning, 3 day -- 2 days after Hurricane Irma went through, guys from New Hampshire loaded up the trucks and drove down to Florida to participate in the largest energy restoration project that the U.S. has seen. And so these are our guys demonstrating our why.

 The how, and this is just how we think we do it different and perhaps better than everyone else, distinguishing characteristics for ourselves, you can see this is our vision statement. You've seen it on the screen before. The differentiating part that we always like to point out is this is not about making the most money possible, it's about gaining admiration. And gaining admiration, again perhaps antithetical to a utility customer who acknowledges -- or a utility company who acknowledges their customers can't not be their customers unless they sell their houses, we want to actually gain the admiration of our communities and our customers for our people, passion and performance.

 And then lastly, perhaps most pedestrianly, here's our what. What do we want to do? We want to be a top-quartile, diversified North American -- well, actually now we can maybe add international to it -- utility company, that we're not going to be the biggest by far, but we certainly want to be the best. We want to be the best from a safety, from a customer experience, the engagement of our employees, our financial performance and, right back to the why, for our commitment to renewable energy. So there's a little bit of background on our kind of mission and vision.

 I did want to talk about 2017, the year that was from our perspective. I stood here a year ago now kind of making a number of statements. I hope the conclusion is they were promises made, promises kept from the business perspective. 2017, if you -- the top line is really what we did on our regulated utility business, obviously a phenomenally busy year with the acquisition of Empire, the 1st of the year. It worked well from our customers' and regulators' perspective. It was seamless as we expected and want it to be. I will say that, that is -- that it doesn't just happen without a lot of work, hard work on behalf of everybody who was involved. And not just Liberty Utilities people, but the Empire people really jumped in.

 The second thing that we did was we have completed our first solar project own within rate base in California. For those of you who are familiar with the California regulatory regime, you'll know that that's no small feat. California is very committed to separation of church and state when it comes to generation from distribution. We were able to convince the California Public Utilities Commission that the best thing for their customers is to allow us to invest in $120 million worth of solar projects, which they allowed. And then lastly, we have continued our process of, I'll say, tuck-in, roll-up acquisitions with the acquisition of 20,000 more customers: 16,000 in upstate New York, which we're working our way through the regulatory approval process, from Enbridge; and the acquisition of 4,000 customers in State of California near our Park Water utility.

 And then lastly, part of the premise on which we spent $3 billion of your money acquiring The Empire District Electric Company was this thesis of shutting down a coal plant and replacing it with wind. When we actually presented this to you last year, we actually talked about 400 megawatts worth of wind. Well, that falling price of renewable energy that I articulated has changed the model to say, oh, just a second, the most effective opportunity, the most effective mix to reduce cost to our customers is now 800 megawatts worth of wind. So you can actually see the impact of falling renewable energy prices actually just in the course of the past year from the time we presented this greening the fleet.

 On the Liberty Power side, active year as well. 160 megawatts worth of new wind and solar commissioned. That's about a 10% growth in our total installed capacity. And as we're -- that's not over yet. We got another 150 megawatts of generation in construction, our Great Bay Solar project down in Maryland. And the project which has become a career, Amherst Island, that you have -- hey, I'm hoping next year, well, we won't be talking about that one anymore. The first turbines are being delivered this week. So if there's wood around, I'd knock it to say that we won't be talking about Amherst Island.

 How does it all sum up? It sums up with, as Chris had highlighted, $7.7 billion worth of stuff to do over the coming 5 years. And I will just point out that we think that compares favorably to the $6.3 billion on an apples-to-apples basis last year that we talked about because we had obviously included Empire in the mix last year. So it has continued to -- we've continued -- not only did we do what we said in 2017, but we have surfaced additional investment opportunities. You're going to hear about one of them in the international space as we look forward to the next 5 years.

 So with that, I'm going to turn things over to David Bronicheski to talk a little bit about the financial aspects of our business. David?

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 David Bronicheski,  Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc   [7]
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 Thanks, Ian. Morning, everybody. It's nice to see familiar faces in the crowd from our last Investor Day, and it's also actually very nice to see new faces as well.

 One thing, I think, for analysts who have been covering us for a long time and investors that have been invested in Algonquin for a long time that they've really come to know, that when it comes to growth, we're pretty serious about growth, and it really has, as Chris said, been part of our DNA. Chris mentioned we IPO-ed back in '97 at $80 million. I joined 10 years later as CFO, and there were $780 million of assets. Ten years hence, we're going to close this year with just over $10 billion of assets. And you can see here by 2022, once we're through our $7.7 billion growth plan, we're going to be cresting $16 billion of assets. So you can really see that growth is really what we do.

 And new investors have often said, okay, that's fine, you've got all that growth. But please tell me that, that growth is accretive. And I can absolutely say that all of that growth has been accretive on virtually any metric that you can think of. So EBITDA per share, FFO per share, earnings per share. All of the investments that we've made over the years, and you can take it back further than that, have been accretive. And as we look forward to 2022, you can see that it continues to add accretive investments to our operation.

 So that leads me to saying, well, financing all of this growth is pretty important to us. And so it has to be financed efficiently in order to make our investments accretive. So how do we do that? First, we like to think that we have a very strong equity brand in the capital markets, and I think we're very grateful to the reception that we do get in the market. Every time we bring a good, accretive idea to market, the capital markets here in Canada have not let us down, and we've been able to finance all of that growth.

 I've been really focused on making sure that we've got a very, very strong balance sheet and that we're working really hard to continue to lower our cost of capital. And having a strong balance sheet is important for us. And we've looked at different amounts of leverage that we could put into our balance sheet, and we've said, well, what if we delevered and moved up to BBB high? What would that do? Or what if we took on more leverage and went down to BBB low? And every time we do that analysis, we come back to BBB flat. Stable is the sweet spot where our cost of capital is optimized.

 Now you can see here kind of where we're targeting from an overall senior debt-to-total cap basis. There's no doubt that coming and closing the Empire acquisition, we kind of stretched the balance sheet to make that happen. Still stayed within our target zone but definitely at the higher end. So as you'll see throughout the morning, we're going to have a plan to naturally delever our balance sheet over the next couple of years and get back to within the target zone that you see there so that we're able to continue to capitalize on the growth that we have before us.

 One of the thing that's certainly in our toolbox as far as equity goes is tapping into the U.S. tax equity market. Now we believe, because of U.S. tax reform, that the amount of availability of tax equity might shrink. It's logical. If the tax rates are going down, there's not as much need to shelter as much tax. But we'll, as you'll see, have the ability to self-shelter a lot of that tax equity ourselves in any event.

 But we're – we've brought over $1 billion of tax equity into play certainly in our business over the last few years. We -- I'm proud to say we're one of the first Canadian companies to introduce the concept of tax equity to the Canadian market. We did spend some time with analysts and investors, kind of walking them through exactly what that means. We've placed $1 billion with 6 different tax equity providers and over 9 projects. And I think it's safe to say that we're a proven player when it comes to the tax equity market, and that will actually serve us well in the years ahead because certainly, we believe that when there's less availability of tax equity, the tax equity that will get placed is going to be placed with people that have a proven track record of bringing good projects to market on time, on budget, and we can certainly say that we do that.

 Another part of our toolbox is our debt platforms. We have 2 different debt platforms within our company. They're completely separate. There is no cross-collateralization, cross-defaults at all. On the power side of the business, we have a senior unsecured bond platform that we execute. It's a public style execution but exercised on a private placement basis here in Canada. Almost $800 million has been issued on that platform. Just this year, a very successful outing, $300 million of bonds were issued with a 10-year term and a coupon of 4%. So we were very pleased with that outing. On the U.S. side for our utilities group, we've been financing our utilities on the debt platform in the U.S. private placement market. $1.3 billion of debt has been issued on that platform. Just this year, $750 million of debt was placed. A weighted average tenure of 15 years and a coupon of 3.6%. Again, very pleased with that outing.

 And we really believe that these debt platforms provide us with a strategic advantage. First of all, you'll be hearing later this morning from Jeff Norman that over the next 5 to 10 years, it's going to be increasingly hard to get those traditional, long-term power purchase agreements with utilities. And so what that means is IPP developers are going to have to look for other ways to get revenue certainty, and those ways will include proxy revenue swaps or corporate PPAs. And the nature of those are they tend not to be for the full duration of the life of the assets. So it's going to be hard to arrange for project finance. So our senior unsecured bond platform is very well suited for playing in that market. It's supported by a full 39 projects today. It'll be certainly into the low 40s by the end of next year. And so that will give us a strategic advantage.

 On the utilities side, our senior unsecured bond platform has actually served our utilities very well. Our utilities are -- they're not all the size of Empire. We've got some that are in the $100 million, $200 million, $300 million range. And what this bond platform does, it gives those utilities access to the bond markets in the United States on a scale that allows them to really benefit from the low rates that you see there.

 One thing I'd also like to touch on is a relatively underutilized aspect of our balance sheet to date has been either preferred shares or hybrid debt. And we have room right now for $1 billion of either preferred shares or hybrid debt on our balance sheet. And so that is definitely going to be something in our toolbox going forward over the next 5 years to finance our growth.

 So let's talk a little bit about our operations. We are based in Canada. But beneath that AQN on the TSX is really a U.S. company. 93% of our cash flows are in the U.S. As we look to next year, even though we're adding on a small piece of international to the mix, we're still going to be largely U.S. dominant. And even looking forward to 2022, you can see that we're still going to be largely a U.S. company.

 We're now listed on both the NYSE as well as the TSX, so that does give us access to the largest, most liquid equity capital markets in the world down there. And a few years ago, we even changed our dividend to U.S. dollars. So for all intents and purposes, although we're based here in Canada, as I said, we're a U.S. company, which then raises the question in many people's minds, okay, well, how do you hedge that currency exposure? Well, we really take a very simple approach, and we just raise U.S. dollar debt and match that up against our U.S. dollar assets. And you can see, again, 2018, the same thing, and even as we continue to add the international to our business mix, we'll continue that same approach.

 One thing that I will spend a bit of time talking about is a number of investors, and not just in the United States but also here in Canada, have been saying, well, if you're that much in the U.S., then why aren't you switching to U.S. dollar reporting? And I will say that, that is something that we're very much considering. Our Board of Directors hasn't made any decision on it at that point in time. But it certainly is something that logically would make sense just given the dominance of the U.S. in our business mix. So that is something that is definitely under consideration.

 As far as sources and uses of capital goes, you can see it's a $7.7 billion pipeline largely split along the lines. So a relatively heavy investment on the Liberty Utilities side; but also, you can see the wedge coming in now for international. So starting on the sources of capital, we always like to point out a relatively low payout organization. And so underpinning our sources of capital is really our free cash flow that we're reinvesting in the business. And it really is almost 1/3 of the capital that we need, we're self-generating. Then as you see in the right-hand side of the pie there, our investment-grade debt platforms make up a good chunk of that, as will preferred shares or hybrid debt that you see there.

 Then turning the attention over to the equity side. Tax equity, that's the lightest wedge that you see there in green. We have a very successful dividend reinvestment program that provides a good source of capital. And yes, you can't build out $7.7 billion and maintain a strong balance sheet without raising some additional equity. And so you definitely see that in there. But now, well, the question becomes, if tax equity is shrinking, are you really going to be able to raise that much tax equity over the next 3 to 5 years? And what would that pie look like if you weren't able to do that? And so we overlay the next slide. So you can see here that tax equity shrinks, but what we do is raise a little bit more equity, a little bit more debt and we're there. And the 2 pie charts you can see are almost indistinguishable. It doesn't really change our basic approach and certainly doesn't derail any of our growth plans going forward.

 So let's spend just a couple of words on U.S. tax reform. We've got our Senior Director of Government Affairs, Elizabeth Dumm, with us this morning. She'll be on the Liberty Utilities panel and the Liberty Power panel. And she'll be sharing a little bit more as far as details go on U.S. tax reform, but I'd just like to kind of set the stage for that. As we think of our business, I kind of like to think of our business in 3 wedges. We've got about 10% of our business in Canada, we've got 20% of our business in the U.S. in the nonreg sector and we've got 70% of our business in the regulated sector. Obviously, the 10% that we have here in Canada is not affected by U.S. tax reform. So now we're kind of talking about the other 90% that you see there.

 As you'll hear from Elizabeth, the utility industry was very successful in the lead-up to tax reform to really work with the House, work with the Senate to make sure that they had a successful outcome. So we are expecting grandfathering of the existing debt arrangements. We're expecting continued deductibility of interest, makers remaining as the depreciation method and state and local tax deductions retained. And so it's not a lot changing on the utility side. Yes, the tax rate is going down. So what we expect, it'll be neutral from an EPS point of view because taxes are a pass-through to the customers. So revenues will be going down, tax expense will be going down, EPS will remain unaffected.

 If you look at the nonregulated side of the business, well, tax reform is supposed to be a good thing. So as we look at it, it actually is a good thing on the nonreg sector that we have. But we've kind of modeled 2 effects that are going to be taking place within that. Certainly, the amount of interest deductibility will be constrained, and so we will be impacted by that. But that impact will be more than offset by the lower tax rate when they lower the tax rate from, basically with state and local taxes included, 40% down to about 25%. And so that will more than offset kind of the constraint that we would see here on interest deductibility. But as I said, Elizabeth Dumm will have much more to say on tax reform as we move through the panels.

 So with that, I'll turn things back over to Ian to talk about our life going forward.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [8]
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 Thanks, David. So did want to put that $7.7 billion a little bit in context to give you a little bit more granularity.

 First, and this will be obviously a new item on the slide for us, is this International Expansion Initiative, which was announced on November 1 of this year and was really comprised of 2 things: One was the acquisition of a 25% interest in a company called Atlantica, which you're going to hear a little bit more about. But I'll say the more strategic part of that initiative was the announcement of a joint venture, together with a company called Abengoa, to continue to pursue development of water and energy infrastructure projects outside the borders of Canada and the U.S. We believe that there are near-term identified and specified initiatives, which will generate another $800 million of investment potential that between -- that under the preemptive right that Algonquin has negotiated with Atlantica, provide them the capital, will bring the total today at this 10 seconds investment potential over the coming 5 years to $1.5 billion. It could certainly be more, but based on the things that we have identified, we certainly don't think it would be less.

 The other thing that to talk a little bit about is our investment in rate base generation. This is predominantly that 800 megawatts worth of new wind generation which is slated to go into our Midwest electric utility. As I mentioned, it's up from 400 megawatts last year, just due to a falling prices in renewable energy. And just to kind of reiterate the point that we are comfortable that even under the tax regime in the U.S. as it has been advanced so far, and as I said, we're not all the way through it, the project continues to make economic sense for customers with over $300 million of customer savings arising as a result of us investing that capital into the utility over the investment life of those assets.

 And the last one, it wouldn't be an Algonquin Investor Day if we didn't have a little something that we had issued a press release on. For those of you who have a Google Alert, you saw that we issued a press release on a pipeline project and an LNG -- associated LNG project in New Hampshire. About $400 million worth of rate base investment, intended to reinforce the gas supply infrastructure for our regulated gas customers in the state of New Hampshire. And so we're pleased that, that project makes economic sense. Again, you'll hear more about it in the Liberty Utilities section. But the punchline is, if this project had existed in 2014, we would have saved $60 million for customers. And so it is really a very powerful thesis behind that project.

 The other thing that I did want to touch on is the business mix. We are spending $7.7 billion moving the business ahead. And you can see here from the chart, first of all, I think the growth in the business is going to be profound. I mean $6.2 billion closed last year, $16 billion, 2022. But I think what we are most comfortable with is that the business mix, this split between regulated utility business and nonregulated independent power, maybe water infrastructure business isn't fundamentally changing notwithstanding the fact that we are deploying $1.5 billion outside of Canada and the U.S. And I think that's an important consideration as you think about the stability and predictability of the earnings and cash flows on the portfolio. And so we like to think that, that $7.7 billion is basically staying right in the middle of the fairway from a strategic perspective.

 Growth in assets and -- is obviously a good thing in the infrastructure business because it ultimately drives EBITDA. There are -- they -- it's not like we can make more running shoes out of the same factory. Clearly, if you want to earn more, you have to invest more capital. And so not surprisingly, the growth in our assets delivers a commensurate growth in our EBITDA. And over the coming 5 years, it's 20%.

 But growth in assets onto itself, as David had mentioned, as a management team, we are well aligned with shareholders through our own personal holdings of it. And so my focus, and I would say the focus of management team is, as we think about growth, what's it doing on a per share basis going forward. And so we are pleased that as we look at that $7.7 billion, the growth in EPS over that horizon is supportive and consistent with the thesis that we have advanced for growth in our dividend per share, which is 10%.

 Which kind of, I'll talk a little bit about the dividend, but before we do, I just wanted to touch on post 2022, and I know that's a long time away. But where I think it's valuable and important is it kind of gives some insight as we think about 2 things: One is this portfolio of assets we have today, Chris had kind of alluded that we think about this with multiple decades of long view in terms of the ability of these assets to produce cash flows. And so the first question you ask yourself is are there cliffs? Are there overpriced PPAs that are going to come to an end in the near term? And then the second, and I guess it's a corollary to that is, as we spend that $7.7 billion, is that just going to generate near-term growth? Or are they going to be consistent in terms of delivering long term?

 So when we look out beyond 2022, and we take a relative conservative scenario here, so we're not going to invest in any more IPP assets, we're only going to invest kind of continuing capital in our Liberty Utilities business to maintain the system, no further M&A. It feels like we can let Jeff Norman and the BD group go, which will save us a lot of money that -- in that scenario. But the impact, and then depending on what you do with that cash, because Algonquin, you can imagine, becomes a cash machine. It's not reinvesting, it's generating a lot of cash. So depending on what you do with the cash, and you have a bunch of different scenarios, the good news is the models today, and we look at it, show continued growth in the 4% to 6% on an FFO per share basis. But obviously, we're not going to let Jeff go. And so our expectation, if we continue on growing the business, doing the type of business that we are doing from 2022 to 2027, will show continued growth, which is consistent with what we've had historically, and that there is no hidden cliff or latent shortfall in the cash flows even on this extended horizon. And that's not surprising. I'm sure we are -- for God's sake, we're an infrastructure company and these assets have lives which extend far beyond the coming 5 years.

 But let's talk a little bit about the dividend. We -- that is one of the reasons people own these shares. I mentioned that we're -- maybe we should be searching for the cure for cancer, but as an organization, that's not our mission. And so -- but we are in the business of investing your capital in businesses that generate a continued cash flow stream going forward and we pay it out as dividends. As David had mentioned, 2014 saw a shift in the denomination of that to U.S. dollars. And we're pleased that this is, I think, the seventh year of continue increases in the dividend of double digits. And I think it's averaged 15% over the past 7 years. But the most -- and that's allowed us to be included in something called the S&P Canadian Dividend Aristocrats Index. But the most important part from our perspective is that growth in the dividend is not just us giving you your own money back. But if you look at our EPS, we have consistently outpaced the growth in our DPS, and that's an important part of securing the story going forward.

 And so one of the issues that, as we think about the coming 5 years, is we think about our payout ratio. If -- for those of you who have followed this organization for a long time, we obviously started life as an independent power producer. And the concept of an EPS-based payout ratio was almost nonsensical. I'm not even sure guys like Northland even quote their GAAP earnings because that's not how people think about that organization. But as we have made the shift to be over 70% in the renewable -- in the regulated utility space, we would say our aspirational peers today are guys like Emera, Fortis, Avangrid, a NextEra. And earnings per share very much is a metric by which their businesses are evaluated, both from internally from a management point of view and externally as well.

 So one of the things that we think about now is our payout ratio on an EPS perspective. You heard me last year stand up and reaffirm our 5-year guidance for 10% growth in our dividend through 2021. As we sit here at these 10 seconds, we actually ask ourself the question, is that the value maximizing thesis to do that again for 2022? I hope your conclusion is as you -- we certainly believe that the growth in our earnings per share, our cash flows, our assets, our EBITDA could definitely support it, and I could stand here and reaffirm that 10% growth for 2022. But you actually know the questions we're actually asking, is that the right thing for shareholders? And so if I had a wish for your takeaway for your notes, it would be that the organization has the capacity and capability to grow that dividend by another 10% in 2022. But it's asking itself the question is, does that maximize value for shareholders? Would the shareholders be better with a lower EPS payout ratio? Just to put that in context, we think about our peers Emera, Fortis, those large U.S. utilities, 70% kind of feels like a comfortable payout zone. Is that a better thing? So I think we're going to take the next year to kind of think about that to decide is that the right thing for shareholders? But as I said, I hope that the takeaway from your notes perspective is that the investment thesis would support it, the question is, is it maximizing from a value perspective? So that's something we're going to spend the next year thinking about.

 So before we get going, just want to kind of reiterate Chris' messages of the day. As I said, we spend so much time talking about growth. We don't spend a much time -- as much time talking about this portfolio of $10 billion of predictable cash flow generating assets. It's obviously, I think, it's the foundation on which this organization is based and it gives us the flexibility to go out and do interesting and entrepreneurial things from a growth perspective. I think our entrepreneurial spirit does position us well in the face of the uncertainty that exists and the changing environment in which we are doing business going forward. $7.7 billion, we are pleased that we have continued to find opportunities to grow the business in a manner that we certainly think will be accretive going forward.

 And last, you're going to hear the story about the culmination of, I guess, it's a couple of years now, you've heard us intimating on our earnings calls about trying to find the right strategy for Algonquin to step outside of the Canada and U.S. borders, in which we have existed since our foundation. And we think we've cottoned on to it, and that you're going to hear the story about a measured investment, which has significant investment potential, but interestingly and attractively as accretive today, so it gives us a great investment opportunity that's here and now, and it isn't all on the come, if you will, in terms of that growth going forward.

 So with that, we're going to turn things over to bring the Liberty Power guys, the renewable energy people to stage. And so while they're just coming up, I'll do some quick introductions to that. Jeff Norman, who you've heard from before, has been with the organization for a long time as our Chief Development Officer. Joanne Atalay, new face to at least this gathering, heads up our asset management group in the wind area, got a British accent, so she sounds really smart. That -- Elizabeth Dumm is -- actually joined us from Empire District, and so this represents, if you will, harvesting the best, from our perspective. Elizabeth has moved from Joplin, Missouri to Toronto, I don't know if that's a step-up or a step-down, but -- and is managing our overall government affairs function across the organization. And Rahi Nathwani heads up our financial planning and capital planning function.

 And so with all of that, I'm going to turn it over to Jeff. Jeff?

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 Jeff Norman,    [9]
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 Great. Thanks, Ian. And as the Chief Development Officer, my job is to work with our management teams on the utility side and the power side to take and secure new growth opportunities. And I'm here today with my colleagues on the power side. We're going to talk about the things that are key to the power business, which is our high-quality, diversified portfolio of generating assets and how we work with that portfolio to ensure reliable returns year-after-year.

 We're going to talk about some of the specific additions that we see to that portfolio over the next 3 to 5 years and how they'll enhance the diversification and improve the returns from where they are today where they're already strong. And then we're going to take a look at the industry trends over the next 5 to 10 years and how we see a lot of change taking place and that's creating opportunities in terms of new customers and how our proven and reliable team, management team with Liberty Power is going to convert that change into the new opportunity and the new round of growth to enhance our portfolio further.

 But I'll turn things over to Joanne, who's going to start off with an overview of our existing portfolio.

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 Joanne Atalay,    [10]
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 Okay. So just to recap, I am Joanne Atalay, and I am the British one. So Director of the wind portfolio. So it's nice to be here today.

 So I'll start by giving you an update on the North American wind portfolio. Today, we're at 1,500 megawatts with 38 facilities over the 4 technology groups of wind, solar, hydro and gas. It's a diverse portfolio, not only by technology, geography, modality, but also that we operate in 12 electrical jurisdictions across the North America. We have a strong stable base there, supported by an average PPA length of 16 years.

 So Ian has already talked about our journey in 2017. But this year, we reached the milestone of 1 gigawatt in wind with the completion of our Deerfield facility, which takes our wind portfolio to 75% of that of Liberty Power's generated capacity. We currently work with 5 different turbine suppliers, and we have geared in direct drive technology there. And we're operating a new range of machines which have high efficiencies and high-capacity factors. And on some days in our Saskatchewan facility, you can see capacity factors in excess of 50%, which is equivalent to a European offshore wind facility. We've also seen growth in our solar portfolio, rising to 115 megawatts in the last 3 short years. And geographically there, we're in Ontario and both on the East and West Coast of the U.S. And we see that, that solar generation profile is a nice complement to that of wind.

 So we'll move on to talk a little bit about what we are seeing in relation to costs, and how attractive the economics are for us at this time. And if you take a look on the top right-hand corner of the chart there, you'll see we're comparing conventional forms of power generation to that of utility, solar and wind. And on the green bars there, we're showing you a bit of a range, and that sometime is accounting for geographical or capacity factors associated with those technologies. But what you'll see is that today, we see utility scale wind as being the lowest cost form of generation. And that's not just in the U.S. We're seeing that globally as well with our partners in Europe. And that's driven by changes in technology, reduced costs, increases in rotor diameters, operating efficiencies and capacity factors.

 And I'll just take you on a little diversion to the bottom right-hand corner there. And we talk a little about where we were in 2005 when we installed a V-82 machine with an 82-meter rotor diameter and the types of equipment that Jeff is looking at today with 2017 technology, and that's a V-136. That increasing rotor diameter gives us an increase in swept area of 270% from the generation technologies we installed in 2005. And some of the machines that Vestas is currently proposing with the 150 diameter rotor takes that from the 2005 figure to a 330% increase in swept area.

 So we see that the cost of solar is falling rapidly, and we expect that to decrease by 32% through to 2022. For wind, wind saw a rapid fall in cost between 2010 and 2017, dropping 30%, and we anticipate that there is some room there for that to decline even further by 13%. So you'll see that the low-cost renewable generation has the opportunity to disrupt markets and it's placing itself to replace some conventional forms of generation.

 Moving on, we'll talk about what we see in terms of growth. So we are seeing some near-term build-out in wind and solar. But with those competitive economics of solar, we see that, that footprint is going to increase beyond 2021 and anticipate in the post-ITC period that, that will continue to rise in about 130 gigawatts of solar installed in North America. Wind keeps pace and in the post-PTC period, we see about 45 gigawatts being added there. Again, both of those technologies moving to replace conventional forms of generation.

 But as we talk about the economics and the growth, then we have to think about can the grid keep up? This is an infrastructure that we are bound by. So I'll start a little bit by talking to you about some of these systems in the U.S. that already have a high penetration of wind. And in the southern power pool, we see that, that wind currently represents 18% of capacity, and they've looked into seeing whether they can take that up to 75%. In ERCOT, which is in Texas, we see that wind represents 15% of capacity. And some days, you'll see a 50% penetration of renewables in the market there.

 So if you look on the chart, we're showing you the amount of the Eastern Interconnection System, which is a large interconnected system that has cross-border interties between Canada and the U.S. And the National Renewable Energy Laboratory has modeled a 30% penetration of wind and solar into this area by 2026. And what they did was they took the existing installed base of 75 gigawatts, and they scaled that up to 400 gigawatts. And they looked to see what that would do to the intermittency there. And what they concluded was with some minor transmission improvement and some storage capability, that the interconnect there could actually cope with that 30% growth in renewables. Natural gas and hydro were displaced somewhat and cost of generation fell by about 30%. So the grid is able to accommodate the growth that we're anticipating.

 But what's next? And Ian has already talked about some of the disrupters that we anticipate. And we've already talked that we see wind and solar currently at grid parity now through our own portfolio as experiences. Ernst & Young have looked at what may be tipping points and key distributors going forward. One of those being the retail cost parity, and that's where the cost of locally generated installed electricity will equal that of grid-delivered energy. And we see this is the age of the prosumer, to coin a phrase, where they have the choices on storage and even generating behind the meter. And we see that as an opportunity for the grid. It becomes an additional storage capability, allowing some compensation for the intermittency that renewables will bring. And then renewables comes up as the low cost form of generation and helps balance that distributed energy resource going forward. And we feel that we are part of that, and that's in the next 10 years.

 We'll talk as well about how our own experiences are playing into that. We have our existing generation portfolio, and Jeff will talk to our future aspirations and Peter, in the Utilities section later, will talk about our own DER applications going forward, and how we feel that we are well positioned to be part of that evolving market, serving both our residential and commercial customers.

 And lastly, we'll just touch on the electric vehicle parity. And why do we care? Why do we care about the parity of the battery electric vehicle versus that of the combustion vehicle? And that's another thing where we see that this is another storage opportunity and another opportunity for the grid, but I don't think any of us are really ready to go completely off grid yet, so there's still a place for those low-cost renewables in the market and helping balance that evolving DER model while letting people have the choice to take low-cost green power.

 And with that, I will take you back to Jeff, who will talk about our development activities.

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 Jeff Norman,    [11]
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 Great. Thank you, Joanne. Joanne has done a great job of providing us with some of the trends over the next 5 to 10 years that we see changing the industry. What I want to do is drill down a little bit into how we're seeing those impact us and our development team on the ground this year in 2017. And the best way to think of that or how I like to frame it is to think of the U.S. market, which is very different than the Canadian market. And then also talk about the economic drivers, which obviously, transcend the border.

 And in the U.S., we're seeing a lot of activity, and we're quite excited about this, because it's driving new customers and creating a new class of customers. So the first one is corporations are signing more PPAs than ever. We're seeing a big uptick in 2017, which is an ongoing trend in the number of corporations signing long-term power purchase agreements. We're also seeing legislation in the U.S. that's been on the books in many states for a decade or 2 but starting to get adopted because of the price point coming down on renewables, and community choice aggregators are becoming popular and this is creating yet another class of customers for us to pursue.

 And then, of course, the renewable portfolio standard has been responsible for driving a lot of the growth in renewables over the last decade, and we'll debate and discuss a little bit whether it's still relevant to us or not, as we make development decisions on where to deploy our assets. And then there's the Trump factor which Elizabeth Dumm is going to speak to, which is the impact on the investment tax credits, the production tax credits and the potential import tariff on solar panels, and how that's impacting the U.S. market.

 So in the U.S., lots of stuff happening. In Canada, it's actually a lot quieter. In Canada, most of the policies are -- in terms of energy, are mandated by the provinces. There are some sweeping rules across put in place by the federal government, but it's really what's happening in the provinces, and there's a lot of excitement in Alberta and Saskatchewan. In Alberta, it's getting rid of the coal or starting to replace coal generation and taking advantage of the strong wind resource. In the same theme, in Saskatchewan, in terms of taking advantage of that strong wind resource.

 If we then step back and say, what are the big economic drivers that we need to watch out for? And clearly, economic drivers are powerful. And as an example of that, I would just point to Liberty Utilities. There's no debate on whether it makes sense to put new wind into the Empire fleet, because it's just the cheapest form of energy for our customers. We don't have any subjective decisions with respect to whether it fits into the RPS, or when the RPS is going to take place. So I love economic drivers, because they give instant results. And the biggest economic driver that we always have to watch in the power industry is the pricing of power, which is driven by natural gas. And we fully expect that there will be abundant sources of natural gas in North America for the next 5 to 10 years and longer. And that we expect it to be relatively low pricing and therefore, we're going to have low energy prices.

 And what's important then is in that backdrop, can renewables compete? And as we've heard from Ian and from Joanne, renewables are continuing to decline in their price point and they can compete in this market. And to drive that home a little bit, as we take in and look at new turbine options, and Joanne mentioned the increase in rotor size, well each of vendor continues to introduce new models every year, and the first thing we do is get the power curves for those models. And so Vestas now has a V-150 turbine, which has 150-meter rotor, and we're running the power curves on that for sites with low wind, and it's amazing what that's doing to the economics. And so we are excited about that new trend, and how it continues to push the price down.

 And the solar side is no different. As we reach out for indicative pricing on solar panels, and as we just -- we're completing the construction of Great Bay Solar, so we just procured a bunch of solar panels. We're seeing pricing at phenomenal levels. We're seeing pricing in -- approaching $0.30 a watt, and we actually believe it can dip below $0.30 a watt, ignoring the import tariff. So you can see there's a lot of momentum behind renewables. And that momentum is really what's driving us, as we go forward and look at corporate offtakers.

 And the -- in 2013, 96% of the PPAs were being signed by utilities. Now you fast forward to 2017, and almost 1/3 is actually corporate PPAs. And what's motivating them? Well, as you can see from the logos on the backdrop of the slide, those are the companies or subset of the companies that have signed up and declared that they want 100% renewables. And they are doing that for 2 big reasons: They're doing that, one, because it helps their brand. Renewables give them a marketing advantage. And two, renewables can be procured at a reasonable price. And so that's driving them forward. And it introduces a whole new customer class for us.

 Now as David mentioned, one of the challenges is the PPAs that most corporates are looking to sign are more in the 10- to 15-year range, based on our discussions with them, than the typical 20- to 25-year range. And so a lot of our competition using nonrecourse project financing have a challenge because there is a mismatch in duration between a 35- to 40-year asset and a 10- to 15-year PPA. But our balance sheet financing, which is conservative at about 50% with thick equity is perfectly suited for pursuing this new class of customers. And this class of customers is signing, as you can see, sizable PPAs. And so Amazon at 189 megawatts, Johnson & Johnson at 100 megawatts, these are real projects and things that we're excited about.

 But if you think of those 2 themes, the desire for renewables and the low price point, and you bring that theme across to community choice aggregators, and the most excitement in this market is in California. Currently, there's 345,000 customers -- 370,000 customers, sorry, that are being served through community choice aggregators in California. But there is belief that they could actually take 60% of the retail and small commercial market in the -- or in California.

 And so what's a community choice aggregator? It's actually quite simple. You take as a municipality or a county or a group of counties and form a CCA, a Community Choice Aggregation group, which is 100% owned nonprofit, and it's there to give the customers a choice for where they procure their rate or their energy. And because of the strong demand for renewables, most of the CCAs are going on procuring a lot of renewables and they're doing it at a price point that's very attractive to their customers. And the legislation is very powerful in that when you form a community choice aggregator as a municipality, the customers automatically leave the utility and go to the CCA. And the customers need to opt out to go back to the utility. And why would they if they're getting exactly what they want, which is more renewables at a price point that's attractive. Now it's not the end of the world for the utilities because they still are critical in terms of their distribution and transmission systems, but it's a great new customer class for us to chase.

 So then moving to renewable portfolio standards. And, of course, if we were to go back 10 years, you would look to the renewable portfolio standards on where you're going to place your next development asset. But -- and there's no denying that it's been extremely influential. 60% of the renewables built since 2000 were actually built because of the RPS. And 95% of that RPS target has now been met. But the targets are going up by 2030 and there's another 60 gigawatts to be built. But as the theme today is renewables are coming down in price, the RPS was established to essentially bridge the difference between the alternative, conventional power and renewables. Is that bridge required anymore? And I would say it's still important for 3 reasons: The first one is, it gives us a good indication of the momentum behind renewables from a public reception.

 If you think of it when the legislation was originally introduced in 29 states, the politicians hadn't have enough courage and confidence that the public wanted renewables, that they pay a premium and they'd keep them in office after they put their renewable portfolio standard into place, that's pretty powerful. And then they actually have the courage as politicians to step up and say, in 50% of those states, we're going to increase our requirement for renewables. And so I think there is no denying that the public are behind the momentum for renewables and it just gets easier when the price point comes down.

 Secondly, the renewable portfolio standards give a strong voice to the states to take and counter anything that's happening at the federal level and support renewables. And then finally, that bridge between the price of alternative power and the price of renewables is still relevant in some regions. Some regions have relatively weak wind resource and relatively poor solar resource and so they still need the RPS to bridge that difference. And so that is why we feel the RPS is still relevant, but nowhere near as powerful as it once was.

 So now I'm going to switch gears and talk about what you guys probably really want to hear about, which is hopefully our development portfolio. And as you can see, it's strong at $3.1 billion and it's diversified between where we are seeing a lot of growth in Liberty Power at $1.5 billion; the acquisition of the share of Atlantica, which is $800 million of that growth. And I'd like to point out, diversification is obviously important. And so when we look at potential acquisitions and we saw the Atlantica portfolio, what we really liked was we have 1,100 megawatts of wind, as Joanne has pointed out. They have 1,100 megawatts of solar. 560 megawatts of that solar is in the U.S. with long-term PPAs at an average contract life of 21 years. So it was a great mix to bring into our portfolio.

 In addition, we had the opportunity to work with Abengoa to form a new partnership to pursue and use their deep roots in many international markets to pursue an international development. And we saw this as the perfect opportunity for us to make that step. And there will be a separate presentation on that, and I'm not allowed to steal the thunder, so I've just got a blank there on what's in that international growth. But we will or others will go into that.

 I'm going to talk a bit more about Liberty Power. So Great Bay Solar, which Ian mentioned, it's not on the previous slide because it's going to come in and be completed in 2017. It's a 75-megawatt solar facility in Maryland. It's obviously deep into construction, as you can see from the photos, with panels installed. And we expect it to achieve COD this year and be delivering a full year of earnings and cash flow into 2018. It is our fifth project within the APUC family, fifth solar project within the APUC family, bringing us to 165 megawatts and our fourth within Liberty Power.

 And then Amherst Island, a 75-megawatt wind facility, and so this will be our first project to come online in 2018. The project is located here in Ontario, on an island in Lake Ontario called Amherst Island. That island is located about 2 miles off the Mainland and is not very far from Kingston, Ontario. The project has a 20-year power purchase agreement with the Independent Electricity System Operator, which is under the fit regime. And as people will remember, that's $135 megawatt hour base price but it escalates with full inflation during construction and development. And so we are expecting this to have about $145 per megawatt hour when we COD and then continuing thereafter. As you can see, the project is well into construction. I just point out, on your left is a tower section being delivered to site. That tower section and the truck will drive off a Mainland dock onto a barge, be taken across the 2 miles to the island and then there's a similar dock on the island, and so that's how the turbine components and major pieces of equipment will get out to the island. And you can see on the center picture that our substation is well under construction. We expect this project to be done by the end of the second quarter this year.

 And then we've got late-stage projects, and I'd just point out up on the top right, so people can keep track of that $1.5 billion we are highlighting the projects that I'm talking about up in the corner. And so these are 3 projects that are next in terms of their advancement, and I'll start with the most advanced being Val Eo. Val Eo is a 24-megawatt wind facility located about a 2-hour drive north of Québec City. It's got a 20-year PPA with Hydro-Québec, and it's virtually done development in the -- all the permitting is done, all the major permits are in place, our partnership agreements are in place with our local community partner, and we're waiting for spring weather to commence construction. We expect it to be done by December 31. And therefore, it'll be contributing fully in 2019.

 The next project up is our 177-megawatt project in Saskatchewan. And as you can see from the map, it's in the southwest side of Saskatchewan. And those of you that are familiar and have driven the TransCanada there, just a little bit past Moose Jaw, and the project is located just off the TransCanada Highway. It's got a 25-year power purchase agreement with SaskPower, and it's in the permitting phase. We've completed all our baseline environmental studies and we're in the process of compiling our environmental impact report, which will be submitted to the Ministry of the Environment in Saskatchewan for -- to go through their approval process. We are pleased with the site. We've done a lot of consultation with the Ministry of the Environment, the local municipalities that are -- will be hosting the site and benefiting from the tax revenue and local stakeholders and the site has gotten widespread acceptance. As you can see, we expect starting construction in '19 and COD in 2020.

 And then the next site is we're moving a little further west and down into the U.S. into California, it's a site we call Walker Ridge. It's a 135-megawatt site, located not far outside of San Francisco. And we're excited about this one because that's obviously a great load pocket to be in. In California, wind is a bit rare, most of the projects in California are solar. And they've got this thing called the duck curve, where when the sun starts setting, the generation from renewable starts dropping off fairly dramatically. What's nice about the wind profile is this is an afternoon wind profile that picks up because of the exact same dropping of the sun, cooling of the temperature in the desert, so you get thermal winds coming across, driving a profile that matches perfectly with the solar resources that are strong in California.

 We are pleased that our safe harbor turbine components allowed us to procure the site, because obviously you need those for the economics to work, whether it be investment tax credit or production tax credit. And this site wasn't advanced enough in December of 2016 for them to commence work of a physical nature, so this is where the components come in to help us continue to build out our pipeline. And as you see, we are negotiating with the community choice aggregators, which are really growing in California and we've had discussions with corporate offtakers as well as received very favorable hedge pricing because of the nature of that energy profile in the latter part of the day and early evening.

 So now we talk about the safe harbor projects, we've got 2 projects here where we're going to use the safe harbor components that we secured with Vestas and Siemens Gamesa, which have now merged. And we see 2 types of projects. We see projects like Walker Ridge, where the sites are attractive, they've got a good wind resource, they're in a nice market, but they hadn't been able to achieve safe harbor because their permitting wasn't advanced enough. And we've got another one of those in our portfolio that is not as advance called Jeffers in Minnesota, and we see a fairly significant inventory of those across the U.S. which will use the safe harbor components to secure.

 We also are excited about the repowering opportunities. And when you think back to the RPS slide, we -- a lot of renewables have been built since 2000. That means a lot of wind sites are hitting the end of their 10 years and their PTC qualifications. And they were built with the old generation technology, small rotors. What you can do is utilize a lot of the existing infrastructure, the substation, the collection system, the foundations, the towers and you can replace then the cell and the rotors with a larger rotor. You get a couple of benefits, you pick up energy kilowatt hours because you've got that bigger swept area than Joanne referred to and you re-up for one of the tax benefits, either the investment tax credit or the production tax credits. And Vestas is -- has actually worked and adopted tower sections for the top of other -- their competitors' towers so you can take then the cell off from another manufacturer, put a Vestas tower hub on top of it and then use then the cells that we've secured as our safe harbor components to sit on top and take advantage of all that existing equipment in terms of towers. So those are the 2 areas where we see using the safe harbor components.

 The final slide is where we're planting seeds for the future. And we kind of view ourselves as farmers and needing to always be looking forward and saying what's next? And as I mentioned earlier, we're focused in Canada, on Alberta and Saskatchewan. And to just give you a quick preview, in Alberta, we are currently being considered in the solar only in partnership with 2 solar sites. We've secured a -- for a long term, a fairly large solar site in Alberta, which we think will eventually become competitive, but not in the next couple of rounds. And we also have a wind site at 150 megawatts with a very competitive wind resource that we expect to enter into the next round in Alberta. And so we've got a good inventory of sites working there.

 Saskatchewan's the same. Saskatchewan, once Blue Hills is completed, we will be the largest owner/operator of wind in the province of Saskatchewan, so we're taking advantage of that knowledge. We've procured or we've secured additional sites. We're one of the qualified bidders for the upcoming RFP and we're pretty excited about Saskatchewan.

 Longer term, we have learned over time that if you wait until an RFP is announced or a customer shows up and you try to secure a site, you can get the most competitive site and you can maintain sites relatively cheaply. So we're cherry picking and collecting good sites here and there. And you can see the split between wind and solar in the regions where we've done that. And so that's kind of our longer-term focus. And then finally, short term, in the U.S., we actually have a 200-megawatt solar site in Colorado that we're pushing forward. And Maryland, as Ian pointed out, we've got another 75 megawatts of interconnection, 75 megawatts permitted and 75 megawatts of land and so we're working with -- to secure an offtaker for an expansion on our grid base site.

 So that's where we're moving. Now I'm going to turn things over to Elizabeth Dumm, to talk a little bit about the Trump impact issues.

------------------------------
 Elizabeth Dumm,    [12]
------------------------------
 Okay. Thank you, Jeff. Good morning. I'm Elizabeth Dumm and I lead governmental affairs for Algonquin & Liberty Utilities.

 So as you probably know, the industry agreed to a phase-out of the production tax credit by 2020 during the 2015 PACT Act. As discussions began with the tax reform changes, lawmakers assured the industry that the PACT Act would not be impacted, that this agreement would remain in place. So needless to say, the changes that have occurred have been a surprise. The American Wind Energy Association has been very engaged to influence outcomes of the legislation, and we have joined them in those efforts on The Hill. We have seen some improvements. As you know, the House bill eliminates the production tax credit. However, through report language, they suggest that the safe harbor 5% provision has been preserved. Better yet, the Senate bill does not change anything to do with that agreement from 2015.

 That being said, there is the BEAT tax, and that causes us concern. We are working with AWEA on The Hill to educate lawmakers to the impact of that, and we have requested that the BEAT continue the orderly phase-out of the protection -- the production tax credit over the next 2 years. So we are working with the conference committee members that have been assigned and will have more of this assigned today in the Senate to impact and create change. So I will talk in more detail about tax reform during the Liberty Utilities section.

 We also wanted to provide you an update on the U.S. solar tariff issue. As you know, the International Trade Commission delivered recommendations to the President on how to handle issues within the solar tariff and the low cost of panels. That decision, the President must make his decision by the middle of January. Should he agree with the recommendations from the International Trade Commission, solar tariffs will immediately be put in place and fines will be assessed. That being said, we believe if that is the decision, that it will be appealed to the World Trade Organization. And they will go through the exact same process that the International Trade Commission conducted to determine whether there was harm. Should they disagree, then those fines will be returned to those manufacturers.

 And I need to state that this does not impact our Great Bay Solar project. But as we look at the issue in total, we see it as temporary. But we also see it as an opportunity, and that's because of our broadened interest in the international market space. Those low-cost solar panels will be available to markets outside of the United States now where renewable energy growth continues and demand continues to grow.

 So I will turn it over to Rahi, who will be providing you with the financial summary.

------------------------------
 Rahi Nathwani,    [13]
------------------------------
 Thanks, Elizabeth. Good morning, everyone. My name is Rahi Nathwani. And as Ian mentioned, I'm accountable for the financial planning and analysis and capital planning at Algonquin Power & Utilities.

 Before I walk you through the financial aspects of the Liberty Power story, I want to take a moment to provide quantum on the -- context of -- sorry, to provide some context on the quantum of the renewables energy market in Canada and U.S. Over the next 22 years, we expect $700 billion of investments in U.S. and Canadian renewable energy market. The next 5 years, we'll see $150 billion of investments.

 APUC's capital expenditure plan is very focused and clearly aligned with this trend. As you can see on the slide, APUC's nonregulated generation business has a solid growth pipeline of $3.1 billion. This includes wind and solar projects mentioned by Jeff earlier. It also includes wind projects that will benefit from our use of our own safe harbor turbine components. With an investment pipeline of this magnitude, it is only natural to expect increased earnings, and that is what we deliver.

 APUC's accretive growth pipeline provides increased operating profit, net earnings and cash flows, all of it contribute to our dividend growth target. As Joanne mentioned earlier, the North American Legacy generation fleet is being upgraded largely with low-cost renewables. APUC's development and operating competencies in wind and solar give us a clear competitive advantage for accretive growth. That accretive growth is clearly evidenced by APUC's generation operating profit, which doubles by year 2022 and will grow at a compound annual rate of 17%.

 To recap, as Warren Buffett quoted, "The investor of today does not benefit from yesterday's growth." APUC, with its accretive growth pipeline, is very well positioned to succeed in the American and international marketplace.

 And with that, I'll turn it over to Jeff for wrap up messages for our Generation Business.

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 Jeff Norman,    [14]
------------------------------
 Thanks, Rahi. So in summary, I just like to bring us back to the core, which is our high quality, diversified portfolio of generating assets. And really everything we do is about improving and expanding the quality of that portfolio. And our core strengths are 2 in that, one, we're entrepreneurial. So when you see change in the industry, it doesn't frighten us at all. We see opportunity. And we think there's great change happening at this point in time. And we're also we're resilient in that if there's change that comes unexpectedly, it doesn't slow us down. We have to just pick ourselves up and keep going. And we've demonstrated our ability to do that time after time. We're also extremely well positioned. And as David pointed out, are we at the top of our growth? We're absolutely not. We're just building momentum. And the momentum comes through the strength of the balance sheet. It comes through the contacts we have in the industry. Joanne mentioned we've got 12 electric jurisdictions where we've got expertise in. We've got an international growth pipeline now that we can secure. And we've got a growing development team that is proven and able to take and deliver on this growth. But if none of that convinces you, we have a $3.1 billion pipeline in front of us, and I think that's pretty convincing on its own.

 With that, I'll turn things over for questions.

==============================
Questions and Answers
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 David Bronicheski,  Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc   [1]
------------------------------
 There are 2 ways for people to get questions over to us. We're trying -- this is a new way. We've found it very, very successful when we have our employee town halls to generate questions, so for people here and we are broadcasting live over the Internet. So people can login to www.sli.do.com and when that comes up, just type in 2017 AQN Investor Day. And then you can type in your question. It'll appear right here on my iPad, and I'll be able to then pose that question to the appropriate person here. And we also have the old-fashioned way. We're going to have...

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [2]
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 Where you get to ask the question, right?

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 David Bronicheski,  Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc   [3]
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 In person, live, and we're going to have some people walking around with microphones to facilitate that.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [4]
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 Nelson? He had -- he's had his hand up for the last half hour, but go ahead, Nelson.

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 David Bronicheski,  Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc   [5]
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 Oh, do we have the microphones to pass around?

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 Nelson Ng,  RBC Capital Markets, LLC, Research Division - Analyst   [6]
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 (inaudible)

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [7]
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 Yes, sure. Go ahead I'll repeat the question.

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 Nelson Ng,  RBC Capital Markets, LLC, Research Division - Analyst   [8]
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 So just to clarify in terms of the dividend.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [9]
------------------------------
 Yes.

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 Nelson Ng,  RBC Capital Markets, LLC, Research Division - Analyst   [10]
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 Is the focus shifting to payout ratio versus the earnings per share? And on that, you mentioned that you'll be reviewing the dividend profile in 2018. So does that mean there'll be no change in '18 but any decision you make will be implemented in '19?

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [11]
------------------------------
 Yes. No, let me be crystal clear. The guidance we gave last year focusing on 10% CAGR DPS is unchanged through 2021. So we're not revisiting that in any way and in 2018. The question that sits in front of us is now in 2022. Today, should we be reaffirming a 5-year dividend guidance of 10%? And we are certainly in no way retrading the guidance through 2021 of that 10% DPS growth in any way. So I want to make sure that's crystal clear. The question that sits in front of the organization, is it in shareholders' best interest to confirm 10% growth in 2022, from 2021 to 2022? We at least raised the question that I think we need to kind of understand how the capital markets think of this. Is that growth better than our reduced payout ratio in that year? So and that second of all, we are not thinking of changing the payout, as I said certainly for the next 4 years, and tying it to EPS as an EPS payout ratio. We just recognize that an EPS payout ratio is a metric that investors will think about as they think about our dividend in the context of our peers. So as I said, when we think about Avangrid or we think of NextEra, clearly aspirational peers. But how does our payout ratio set us in that stead? But it's not changing in any way the guidance that we've given over the past -- certainly out to 2021 -- and as I said, I think over the next year, we're going to try to get a sense from investors as would they like to hear about a reaffirmation? Because we certainly have the forecast earnings and cash flows to be able to make that statement. Is it just in the best interest of shareholders? So that's -- I just want to be crystal clear on that.

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 Nelson Ng,  RBC Capital Markets, LLC, Research Division - Analyst   [12]
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 Last, 1 more question.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [13]
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 Yes, you got 2.

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 Nelson Ng,  RBC Capital Markets, LLC, Research Division - Analyst   [14]
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 Just in terms of the capital structure, currently preferred shares are about 3%. Could you talk about, like, why haven't preferred shares been used in a more meaningful way? And also, I guess all of your preferred shares are in Canadian dollars, I presume. So is it partly because there's not enough Canadian assets to utilize more preferred shares? And can you also talk about the hybrid debt?

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [15]
------------------------------
 Sure. David, do you want to speak to that?

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 David Bronicheski,  Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc   [16]
------------------------------
 Sure. Our balance sheet can, as I said, take about another $1 billion worth of -- it's either hybrids or preferred shares. And that's based on weaving in about 15% at your permanent capital structure with those securities. And from a credit metrics or credit rating agency point of view, both of those securities, preferred shares and the hybrid debt, certainly the hybrid debt, if it's structured correctly, will also give you equity credit. So one is think of it as a share, they then attribute some that debt to it. The other is debt that they attribute some equity to it from a rating agency perspective. We haven't been using preferred shares that much in our capital structure largely due to something called the Part VI. 1 tax. Now when you're cash taxable in Canada, the Part VI.1 tax is immediately credited against your Part 1 corporate income tax. And so you're largely indifferent at that point as to whether you're paying the VI.1 tax or a regular corporate tax. But what you're not cash taxable, then you're in effect paying the VI.1 tax. Ultimately, it's refundable, but it just basically sits on your balance sheet until that point in time when you are cash taxable. So that has tended to be a little bit of a grind to the effectiveness of preferred shares in our capital structure. But now increasingly, and particularly because rates have been so low and some of the hybrid debt is being priced at pretty aggressive levels, that's causing us now to think maybe our hybrid -- I'd call it hybrid security, should be the hybrid debt, where we will get equity credit just like we would with preferred shares, but it doesn't have the drag of the VI.1 tax associated with it. And so it would be certainly less dilutive for us. So that's basically the reason.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [17]
------------------------------
 Sean?

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 Sean Steuart,  TD Securities Equity Research - Research Analyst   [18]
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 A couple of questions. When we look at potential changes to the financing structure with less tax equity higher debt or hybrids, we used to think about your unregulated development returns at 8.5% unlevered return target. Is that still the bogey we should be thinking about? Does the change in financial structure potentially impact that?

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [19]
------------------------------
 Well, it's interesting. I mean, the reason we would make that shift, Sean, is to replace tax equity. The coupon, if you will, the all-in cost of tax equity is generally in that strike zone, call it, 8%, 8.5%. So I think it is an interchangeable investment from our perspective from a -- an after-tax unlevered perspective. Obviously, we need to think about perhaps the GAAP earnings implications of that. But from a value perspective, remember our corporate value perspective, I think actually, it would probably be accretive if you want to think of it that way to value to fund some of the tax equity internally ourselves.

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 Sean Steuart,  TD Securities Equity Research - Research Analyst   [20]
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 Okay. And a question for Jeff, the perspective pipeline at this time last year, there was a project in Texas on the wind side you guys had talked about. What happened to that project that it's fallen off the list?

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 Jeff Norman,    [21]
------------------------------
 Sure. Yes, the -- well, Texas is a very interesting market and we're still watching it closely. We still have opportunity to move forward on the Texas project. We're really waiting to see because the way the ITC versus PTC balance works is in a high wind regime, the PTC is clearly more valuable. In an ITC world, they're almost neutral. And so depending on how things shape up in terms of the values will impact the Texas market. And so it's still an interesting market but we want to see a little bit more evolution in terms of Elizabeth's work before making a decision.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [22]
------------------------------
 Okay. So in short answer, it's still there, Sean. But given the economics of ITC versus PTC, the focus has been -- we want -- for the focus on Walker Ridge. Sylvia? You have a question?

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 Unidentified Participant,    [23]
------------------------------
 Okay. Mine was just on the corporate value, how you talked about the value of the business and whether you focus more on EPS or FFO. Because there's, I guess some nuances on what the breakup of your business that's hard, and I know, so FFO per share has gone off the targets now.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [24]
------------------------------
 Yes, I think it's probably more aspirational than practical. Clearly, FFO share per growth continues to be strong in sort of in the, I'll call it, 9% to 11% range over that same time frame. I think as we think about the business though and we think about 70% of it being in the regulated space, most of the organizations with whom we would be consider ourselves peers in that space, their focus isn't been on a cash flow per share basis because they don't look at it on the cash available for distribution from a dividend point of view, they're really focused on their EPS. So I don't think it's -- it doesn't represent any focus that we're less interested or less focused on cash flow from an accretion perspective. Every project that we look at needs to be accretive on an earnings and cash flow, a credit metric's perspective. We just -- I think, as I said, the business crested more than 70% of its business in the regulated space with the acquisition of Empire. We thought that the real focus of investors would be on our earnings per share rather than on a cash flow per share basis. So that was really the basis.

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 Unidentified Participant,    [25]
------------------------------
 Okay. And just on -- what determines whether you can green projects in your rate base or not? Do you have to own the utility that's in that jurisdiction?

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [26]
------------------------------
 Yes. So the question is as we think about "greening the fleet", it really is about our customers in our regulated utilities. So that investment in 800 megawatts worth of wind is within the rate base of our electric utility in the Midwest. And so -- but really what drives it, the underlying thesis that one has to convince the regulators on is does this save our customers money? Is this the optimal mix of generation that reduces or minimizes the expected cost to customers over the next 30 years? And so we are in the process right now in front of our regulators, if you will, reinforcing that argument. The argument was made in the context of that IRP that was submitted to the Missouri commission about a month ago or 3 weeks ago. And so we are in the process of prosecuting that docket to convince them of that $300 million worth of savings that you'll hear more about from the Liberty Utilities side. But you really do have to own the regulated utility in order to be the person who gets to enjoy the benefits of integrating that renewable energy into the rate base of the utility. Jeremy, did you have a thought?

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 David Bronicheski,  Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc   [27]
------------------------------
 And just to keep things on track, we've got time for 1 or 2 more questions and then we'll move to a break and...

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [28]
------------------------------
 Yes, yes, we don't want to stand between Bill Cable and a muffin. And so that would be a very dangerous thing, so.

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 David Bronicheski,  Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc   [29]
------------------------------
 So 1 or 2 more questions. Jeremy, go ahead.

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 Jeremy Rosenfield,  Industrial Alliance Securities Inc., Research Division - Equity Research Analyst   [30]
------------------------------
 Recognizing Bill's need for the muffin. I'll just keep it to one. Just to follow on what Sylvia was saying, just some more question on how you think of valuation and the valuation that's attributed to Algonquin in the market. If you focus investors more on earnings per share, for example, rather than the cash flow metric, do you believe that to a certain degree investors may discount the value of the cash being generated by the nonregulated part of the business? And therefore, is that really the most efficient use of capital in that respect? And then -- so the corollary over the longer term, and this is the follow-up question is, at some point, does that inevitably lead you to spin off that division because it's being undervalued in the market? And it's more of a philosophical question, not a, yes, we're going to do it or not going to do it, but just curious.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [31]
------------------------------
 Well, I think it's a great philosophic question and it's certainly one that I think the acquisition of Atlantica gives us some optionality that we talked about. If -- imagine if we had a project that was cash-rich, but earnings-poor. Clearly the most appropriate vehicle to hold that would be in a vehicle whose valuation is driven by cash flows. And so having this effective control interest in Atlantica, I think -- and the opportunity to preemptively take -- invest capital in it creates an opportunity that we might come to the conclusion and someone asked me, "Well, how many projects have you evaluated that would be candidates to be drop dead Atlantica?" Well, exactly 0 so far because I'm not sure we've actually gone through our portfolio to say, "Are there assets we would prefer to be valued in the vehicle like Atlantica rather than Algonquin proper?" I think we're pretty comfortable as we look at the growth on an earnings per share basis even contributed by those assets, which maybe that isn't the most effective valuation methodology on an earnings per share basis. We're pretty convinced that the growth in the earnings per share is robust enough to support that 10% dividend growth which is the guidance we've given. Clearly, if there is an optimization, and that's the way we think of it, to move some assets around, we'll certainly undertake to look at that. But certainly, that isn't the working hypothesis right now. So but it's a great suggestion. One more question and we're -- as I said, don't want to get in the way of those muffins.

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 Unidentified Participant,    [32]
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 It's [Dean Highmoor] from McKenzie Investments. I liked your comments early on about disruption and technology. My questions are just overall, how many customers do you see ultimately leaving the grid, say by like 2030 or 2050? And then you also talked about utilities aren't going to save you anymore. So how do you see them being forced to respond to this world that you see, and maybe if you could expand upon how you see them responding?

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [33]
------------------------------
 Sure. I'll start by saying is I think actually leaving the grid, the actual process of cutting the wire certainly doesn't apply to most customers. It doesn't apply to this building. It doesn't apply to anybody who lives in a condo. It doesn't apply to anybody who lives in a forested area. I mean, these are issues. There are some practical issues in terms of leaving the grid. But I'd go further to say, it's kind of, like, your laptop computer. Your laptop computer is very powerful tool. But it becomes really powerful when it's hooked to the internet and you can basically, if you will, transact with other individuals. I think the same theory applies to the grid. So the thought of having solar energy, community solar in which I might own an interest, it doesn't actually have to be physically be on my house. That's occasioned by the fact that there is a wire connecting my house to that grid. I think the challenge to the utility going forward is to recognize the change in value proposition. No longer are we the purveyors of every electron. We are the facilitators of transactions potentially between peer to peer of which our -- how do we kind of manage and facilitate that. And I think if you -- if the utility tries to stand in the way of that, it's like kind of keeping the waves from hitting the beach. It's a very difficult proposition. But if you can recognize there's a different value proposition associated with your wires, I think there is the opportunity going forward. So I actually don't see wholesale leaving the grid. That slide that showed where the price of a locally generated and stored electricity is competitive with the grid. I think that will bring into focus for utility owners that you need to think about what your customer has an alternative to do and how much value your wires really generate and need to manage their business in that context. So I actually don't see and certainly in our business, I mean, I'll get back to -- do people have enough solar roof space in our service territories to actually pack up and leave? And the short answer is actually not. Tahoe, very forested, same thing in the New England area, very forested. That's not the likely outcome. But it will influence the competitive offering that we do provide to customers because there's going to be other people in there trying to disintermediate that relationship. I don't know if that's responsive to what you're looking for.

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 Unidentified Participant,    [34]
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 No, that's helpful. I guess it sounds like it's maybe more on the generation side that would be disruptive rather than distribution transmission.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [35]
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 I think if you -- yes, we are very pleased that part of our thesis for Empire shows us actually shutting down these coal -- this, Asbury as an example, and building wind that has, as you know, a very low marginal cost of production. That is in the right thesis. I think the utility that is populated with large scale coal nuclear combined cycle gas plants, I think that's a challenge over the coming 10 years. I mean, I -- that competitive environment I think is going to be a greater threat from those disruptors then if you are populate with low-cost renewables. And you've engineered a system that's flexible enough to allow customers to manage their, I'll say, peer-to-peer transactions in a way that satisfies their objectives, i.e. community solar. These are all words that are kind of consistent with the theme you're going to hear this -- after the break from Liberty Utilities.

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 David Bronicheski,  Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc   [36]
------------------------------
 All right. So let's take a 10-minute break. We have scheduled 15, but we'll compress it a little bit to try to stay on track. So if people can come back here at 25 to 11, and we'll resume our presentations.

 (Break)

==============================
Presentation
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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [1]
------------------------------
 Okay. We're going to pick it back up here as, I will say, as promised. So we're going to jump into a discussion on the regulated utility business. And in terms of that panel we have David Pasieka, who's headed up our regulated utility efforts. Gosh, that's got to be for 7 years now. Pete Eichler, who in addition to kind of managing, I'll call it centralized operations, really, it's about regulatory strategy, so feel free to ask a question that's on that. Elizabeth Dumm is back to talk about tax reform as it -- with its implications on the regulated utility business. And lastly, Gerald Tremblay, who is our SVP in charge of field operations. So without any further ado, I'm going to turn it to David. Why don't you take it away?

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 David James Pasieka,  Algonquin Power & Utilities Corp. - COO of Liberty Utilities Group   [2]
------------------------------
 Okay. Thank you very much, Ian. It's a pleasure to be here. This is my eighth Investor Day. And as I think back 7 years ago almost to the day, I was flipping through the notes of the presentation that I did 7 years ago for a much smaller group, I think, at that time. And when you look at it, it was really about the Liberty Water story. So we had a handful of little utilities in Texas, we had a couple of water and wastewater utilities in Arizona, and we had a couple up in Missouri. And all in all, those things accounted for about USD 140 million in rate base. Now you fast forward to 2017 and you'll see from our charts, we're currently at USD 3 billion in rate base and on track to hit 7 -- $6.5 billion by the end of 2022.

 So as we think about the next 40 minutes, myself and our panel here are going to spend some time, and I wanted to highlight a couple of key themes that you should be aware of as the group is going through the presentation. First and foremost, a very diversified utility portfolio. We're operating coast to coast. We're in gas, we're in water, we're in electricity and we're also in generation, transmission and distribution. We have very predictable returns, and the predictable returns come from the fact that we have 35 unique facilities. And so at any one given point in time we're in front of a regulator in one of the states going through a rate case. So you're getting the predictable increase in returns as we work through those rate cases. You're going to hear a lot about greening the fleet. I think it was already previewed a little bit earlier. We started with a concept a couple years back about introducing tax equity into the utility and be able to pull up a generation facility to provide energy for our CalPeco customers at reduced costs. So this has obviously gone much further afield. And you will hear from Gerald the conversion of our core coal facility into wind in those mid states.

 Ian talked a lot about customers and the importance of being customer-centric. And historically, a utility would have said, "Hey, it's okay. Let me just be efficient at what I do." Well, really, that's quite -- that's changing quite dramatically. And as coined this morning, it's really about going from safe, reliable to competitive service, which is a big shift for our utilities.

 And finally, I think the last key theme is that we've got an entrepreneurial spirit that it actually embraces the utility. And it's very unique for a utility to put entrepreneur in the same sentence. But I think we've demonstrated over the last 7 years our ability to get it done whether that be through prudent CapEx investments or some M&A transactions or our whole portfolio around planting flags and organically growing our utilities. So you should feel very comfortable that what you're going to see on the screen here, we have the ability to execute with a high level of confidence.

 Predictable earnings and growth. If I was standing here last year, the top left-hand corner would have said 560,000 customers. Now with the add of Empire and soon the transaction in New York State with St. Lawrence Gas, we'll be closer to 775,000 customers. And for those who have been with us a while, we always talk about marching to 1 million. So we still have that 1 million customers in our mind, and we will get there.

 We have over 2,000 utility employees deployed in the communities that we're operating in. And we're very focused about doing this to make sure that those employees are engaging locally with customers. And if you think about utilities, sometimes utilities are traditionally, a utility would not use the word customer. They do use the word rate pair. But at Liberty Utilities, we always thought that it's important to think about those customers as if they had a choice. And as you heard from Jeff earlier on, there is an opportunity for those customers to actually have other choices. And so we have to be on top of our game. Recently, we made a very significant change in the payroll stub that we have for all the paychecks in Liberty Utilities and in APUC. And at the bottom, it now says, "Brought to you by your customers," so a constant reminder that the customer is important.

 And operating in 13 states with the New York transaction, we're modeled exactly the same way in each state. We believe that customer service needs to be delivered locally, so customers have the ability to walk in and pay their bill if they choose. Operations are obviously delivered locally. And as Peter will talk about later, the regulatory relation has to be very local and within the state that we operate.

 With over USD 7 billion of assets to be deployed over the coming years, we're diversified by commodity and state. And you'll hear from both Gerald and Peter, about how we're able to successfully close the earned authorized gaps. Local strategies such as plant the flags and doing the tuck-ins will obviously add to that asset growth over time.

 So it's now my pleasure to turn this over to Peter, who is going to talk a little bit about the environmental scan and get a little bit more comfortable or a little bit deeper with our regulators across the states. Peter?

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 Peter Eichler,    [3]
------------------------------
 Thank you, David. Good morning, everyone. I'm going to spend the next couple of minutes telling you a little bit about some of the things going on within the utility space in North America and some of the things that are occasioning our investment portfolio of $3.6 billion over the next 5 years.

 So firstly, you heard Ian talk earlier about these changing customer trends. And what does that really mean? From our perspective, what it means is that customers want better control over how they consume their utility services. And this isn't something that's only impacting the electric space, but certainly also the natural gas and water as well.

 But no matter how much customers' needs change, on an annual basis we do a J.D. Power and Associates survey. And consistently, the one thing customers tell us they want more than anything else is safe, reliable and affordable services. And what that means is continued investment in our natural gas, water and electric infrastructure. Thirdly, you've heard a lot already this morning about this transition to a more agile, more modern utility. I'm going to talk to you a little bit about that in just 1 second what that means to us.

 But all told, these 3 trends are combining for $3.6 billion worth of investment opportunity. And you just heard David tell you that we've invested $7.2 billion in our utilities in the last couple of years. And so naturally, you may be thinking to yourself, "Well, what impact would this have to customer rates?" You could see from the chart here on your right, that we actually generally tend to do fairly well relative to neighboring utilities. But the vast majority of this $3.6 billion portfolio is actually aimed at reducing customer costs, whether that be through replacing brown generation with cheaper renewables or investing in capital that makes us more efficient and reduces that upward pressure on rates.

 So I mentioned this transition to a more modern utility, and what does that really mean? And obviously really easy to envision from an electric utility perspective. You see up here the traditional electric utility. And on the right-hand side, you see the microgrid. And certainly, we can all envision peer-to-peer transactions and Ian buying from David's Tesla and things of that nature in the future. But from our perspective there -- this is also something that has implications for the natural gas and water utilities as well. Think about the water utility, like ours in Arizona for example. One of the largest costs we have is actually electricity. And what we've been able to do is take some of those flow-through costs and replace them with renewables on our wells. We're placed -- similarly from a natural gas perspective, you're going to hear from David about our investment in LNG facilities, again bringing those sources of generation closer to the end use customers. So the key takeaway here is that this modern transition is not something that's just in the electric space, but also occasioning investment in our natural gas and water utilities as well.

 So I'm going to transition and talk a little bit about some regulatory stuff for a couple of minutes here. And this is something that we tend to get asked about fairly regularly, which is, what's happening from an ROE perspective and what's your ability to actually earn it? And last year, I had the pleasure to stand before you here and tell you that what we've seen is a slightly downward trend towards that 9.5% to 10.5% range on ROEs that, that they were leveling out. And over the long run, we see them probably staying level. From a Liberty Utilities perspective, this story's pretty consistent this year, and our average ROE is right there in that 9.6% range.

 But perhaps just as important as ROEs is what's your ability to actually earn it? And if you see the chart here on the right-hand side, you could see that over the last 10 years, the average regulatory lag in the utilities space has been something like 10 months on average. And that's the different in the time between when you deploy your capital and when it goes into rates. And you could imagine that standing here at some of our earlier Investor Days, maybe 2012, 2013 when we were just operating in 1 or 2 states, that becomes pretty tough to manage because you're actually just beholden to 1 or 2 regulatory jurisdictions and their pluses and minuses. But standing here today with 12 going on 13 regulatory jurisdictions, we're better able to manage our capital, time it in accordance with rate cases and take advantage of regulatory mechanisms. And we're proud that that's resulted in an average regulatory lag of less than 6 months from a Liberty Utilities perspective.

 So in addition to the allocation of capital, one of the other areas we continue to focus on is regulatory mechanisms. And this chart is another one where I've had the pleasure of presenting it to you for the last couple of years. And each year, I'm always glad to be able to tell you about different and new mechanisms that we've been able to accomplish in different states. These don't happen overnight. Some of them take a year or 2 years, 3 years but we're continuing to see progression and improvement in our regulatory jurisdictions. So take, for example, New Hampshire where historically they've been fairly opposed to decoupling. Well, just last year, the commission actually asked all the utilities to put in decoupling mechanisms into their next rate case, just like the one we have in our current EnergyNorth case.

 But before I leave this chart, perhaps I'll take a minute or 2 and spend some time on Missouri, because that's a question that we get asked about a lot, and obviously with its prevalence in our portfolio, probably something that's at the top of your mind. From our perspective, we've been operating in Missouri, of course, since about 2013 from a gas perspective. And we've always found there to be fairly constructive mechanisms available to us. We have our infrastructure system replacement surcharge, which has led us deploy capital in between test years. And generally, we've had a higher proportion of our rates in the fixed charge. But even if you think historically from an electric perspective, in Empire's last rate case prior to our acquisition, they were able to utilize a stub period 9 months after the end of their test year. So that means they were able to update their capital expenditures 9 months beyond their test year and again, reduce that regulatory lag.

 There's always room for improvement and as I mentioned, some of these things take a little bit of time. But if you followed the legislative story in Missouri over the last couple of years, there's been bills put forward with decoupling, bills put forward with economic development trackers. And for one reason or another, they haven't quite gotten there. But what I am pleased to see is it's continually a recurring theme year after year in Missouri. And this year again, we'll see bills with decoupling and economic trackers. And from our perspective, there's reason for optimism that maybe it will be this year, maybe it will be next year. But this recurring theme will result in continued improvement in the Missouri regulatory environment.

 So maybe let's switch gears for a second, just spend a minute on mergers and acquisitions. And obviously, this has been a key part of the Liberty Utilities story to date. And we've obviously been able to transact at both the larger end of the market and the lower end of the market. And if you think about a company's ability to transact at maybe about 1/3 of its size, this bodes well for Liberty Utilities because if you look at the universe of companies in North America publicly traded, the market cap tends to be in and around that space where we're comfortable transacting.

 But we're also looking at the smaller end of the market. And just this past year, as you know, we've the St. Lawrence Gas in the City of Perris transactions in the committed list. And that's occasioned $100 million worth of investment. But perhaps the key takeaway I'd like to leave you with is that while we're continuing to look for M&A opportunities, the $3.6 billion portfolio that I've mentioned and that my colleagues will tell you a lot about is actually not premised on any uncommitted M&A. And so while we'd obviously like to grow with continued mergers and acquisitions, we're certainly not dependent on it.

 With that, I know there was a lot of interest in tax reform on the Liberty Power side. And so maybe I'd like to call up my colleague, Elizabeth, to tell you a little bit about its implications for Liberty Utilities.

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 Elizabeth Dumm,    [4]
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 Thank you, Peter. So to dig a little deeper into the current state of tax reform, our industry has been very proactive in the discussions surrounding tax reform. Late last year, the Edison Electric Institute as well as the American Gas Association, pulled together their financial leaders and that was to discuss what principles could we get behind as an industry to support comprehensive tax reform. So in that discussion, it was agreed that tax reform must support investment in critical infrastructure and it also must support energy bills that are affordable and as predictable as possible for our customers. So 5 priorities emerged from that conversation and they focused on keeping the cost of capital as low as possible. But then in return that will then help our customers as well as encourage much-needed investment. So in looking -- a lot of time, obviously, was spent to educate lawmakers about these priorities and the importance of those. And placing the production tax credit issue aside, we're very pleased with how the -- both the House and the Senate bill turned out. You can see from the chart that in most parts that they're in agreement, it's just simply when the corporate tax rate may be implemented.

 So we wanted to provide a time line of what this might this look like. I must say that this time line is speculative. It is difficult to predict how exactly this is going to play out. But just starting from the House bill, as you know, the House passed a piece of legislation on November 16. That Bill went to the Senate, and the Senate heard that and passed their own bill in the wee hours as Saturday morning.

 So now that piece of legislation, they're going to go to a conference committee where members of both the House and the Senate will discuss and merge their bills together and work through the differences. So once that conference committee bill is finalized, then it returns back to the House and Senate and must be passed in both chambers. And from there, if it's passed, we'll move on to the President's desk.

 We do expect that the President will sign a tax reform bill. And even after his pen though, we have opportunities to influence the implementation of this bill. So first would be through a Technical Corrections bill. And that allows us an opportunity to either clarify or fix language that's in the bill that we believe is going to keep it from being implemented in a manner that it was intended. And from that bill would be then it goes on to the rules committee with the Department of Treasury. So you can intervene and be a participant in that process, and we will be. And then lastly, as David mentioned earlier this morning, we fully expect our state regulatory commissions to engage our utilities, to discuss and analyze what is the impact of tax reform on the utility, and what is the best manner to treat that in the customers' rates. So again, we have many more steps in the process and we'll be participating.

 So looking at it from a state utility regulator perspective, we know that this is going to be implemented in varying times, in different approaches across our states. And looking at the 1986 tax reduction, we saw that the states, they had a range of ways that they addressed this. It was as if a company was in for a rate case, then they addressed it during that. There were also cases where they set up a -- they established a regulatory liability. They had trackers and writers, and one state even asked their utilities to come in voluntarily to request a rate reduction. But the most common theme across all of those states was that it was not something that was implemented overnight, but rather, it occurred across a period of time. Our individual state regulators have not indicated at this point how they plan to handle the implementation of tax reform. But again, we're confident that, that won't be an overnight approach, but rather it'll be measured in across a period of time.

 So I will turn it over to Gerald who is going to talk about growth opportunities.

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 Gerald Tremblay,    [5]
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 Thank you very much, Elizabeth, and just before I start, maybe David you and I -- we can hook up. I drive a 2000 Honda Civic. So we can probably have a little micro grid going on where I can get some revenue off your Tesla.

 So I'm Gerald Tremblay, in charge of field operations, and today, I'm going to be talking to you about some growth initiatives that we have within Liberty Utilities and some major projects that we're going to be initiating over the next 5 years.

 So to kick things off, Peter pointed out earlier, he talked about macro-economic trends. There's some positive trends happening out there, that allows the opportunity for Liberty Utilities to invest capital. In fact, we see over the next 5 years, over $3.6 billion worth of investment opportunities. Within our distribution division, there's $1.5 billion of investment. A lot of that will be centered around investing in the safety, the reliability of our systems, expanding our customer footprint with new customers coming on. And also, taking on our new acquisition, St. Lawrence Gas in the beautiful new state for us, brand-new state, New York.

 Within the transmission division, there's $560 million of investment here. And a lot of that will revolve around trying to resolve that gas supply constraint that's happening in the Northeast region. A prime example of where we're seeing an opportunity here to try and resolve that issue is a Granite bridge project. It's about $312 million that will now be incorporated into the rate base of one of our facilities. And David will talk a little bit more in detail about that later.

 Within our Generation division, there's $1.6 billion of investment here. As you know, a lot of that will revolve around renewable opportunities. 800 megawatts of wind in our Midwest region, but also other opportunities, solar, an additional solar firm going into our California Utility, which we just found out, should be approved in the next couple of weeks. And of course, other communities solar projects that we have initiated across certain areas of our service territory.

 So all of these investments is $3.6 billion worth of investment. That translates into a safe, reliable rate base growth. And in fact, when you think about it with this new tax regime happening, going from 35% to 20%. You look at it on your balance sheet. And that actually creates a little bit more headroom from an ADIT perspective, accumulated deferred income tax. Over the years, that ADIT will drop. And of course, have additional rate base for us on an incremental basis, allowing for incremental earnings.

 So now I told you about $3.6 billion. Well, that's a lot of investment. But we at Liberty Utilities, truly understand the rate impact this can have on our customer base. And it's for this reason that about 83% of this capital investment of $3.6 billion will have no incremental rate impact on our customers, whatsoever. Some of this investment revolves around replenishing existing capital, which is already in rates. Accommodating for new growth initiatives, which is new customers coming on, there's pace for itself. And finally, the largest, the biggest portion of this capital investment is aligned with Liberty Utilities' key strategic initiative is to always look for opportunities to replace operating costs, commodity costs with capital investment opportunities at no incremental cost to our customers. And in fact, what we see, and you'll see later, there'll be some savings going to our customers from these projects.

 So if you look at this chart right here, over the next 5 years, that $3.6 billion translates into an incremental rate base growth of approximately 50%, the blue line. The green line represents the rate impact to our customers. And we expect that, with a little bit of inflation also incorporated into our operating costs, coupled with that capital investment rate base, comes in line with about -- maybe year-over-year, about a 3.5% rate increase for our customers.

 So I told you about the rate impact to our customers. Now another thing that Liberty Utilities truly understands is maximizing shareholder returns. And we do this through 1 key initiative. And that's optimizing our capital spend. It was pointed out earlier, at Liberty Utilities, we have a lot of utilities, across the U.S., different states, different modalities. This is an opportunity for us. We can take those different utilities. Some of them will be in between test years. They'll focus on all those mechanism capital items that was discussed earlier, allowing them to over earn, overachieve in between test years. Whereas some of our other utilities will be in a test year, and we're going to have a broader, wider envelope of investment opportunities at their disposal. So what this allows us to do from a Liberty Utilities is to minimize that famous regulatory lag that most utilities face today. And we're proud to say that we're forecasting our 2017 return on equity numbers to be above the authorized return on equity numbers.

 So now I'm going to walk you through a few of our major projects that we have on the go. The first one revolves around organic growth opportunities. It was pointed out earlier that the #1 priority that customers expect from their utility provider is continued reliability, safety from the utility. We've done that over the past 5 years. We've invested capital in our utilities. And we see that, okay, we've invested probably, over the 5 years, we've improved a lot on our integrity and reliability with our systems. All in, water, gas and electric.

 If you look at it from the viewpoint of a real-life example, our California Utility out in Lake Tahoe. I guess our employees like to call this event back in 2017, January 2017. In Lake Tahoe, they received over 30 feet of snow within a 3-week time frame. That caused quite a bit of outages for our customers. All the feeder lines coming in from NV Energy went down. We had quite a few of our customers go dark. But 1 line that stayed up and running is that famous 650 line, transmission line that we've been telling you about, where we've been putting additional investment into that line, that line stayed up and running. So when those NV Energy feeder lines came back on, our customers in North Lake Tahoe had electricity instantaneously. That reduced several multiple days of additional outage time that those customers could have had. So it's a prime example of us investing capital and improving the reliability of our systems. But we still see more opportunities over the next 5 years. In fact, we see about $1.5 billion worth of opportunities to improve the reliability of our systems.

 So within our electric modality, there's over $800 million of investment. Much of that will be around improving, refurbishing our existing infrastructure, upgrading and replacing our aging substations and installing a bunch of new technology that helps us improve the reliability of our systems. Within our gas distribution modality, there's just under $300 million of investment, of which half of that revolves around replacing a 175 miles of old cast-iron bare steel pipe. Within our water modality, there's just over $200 million going into new mains, reservoirs, additional wells. And finally, there's around $300 million going into additional growth opportunities for what we always look for is new customers to bring on within our service territory. So as you can see, this continued customer expectation in demanding from their utility to improve the safety and reliability of the product and service that we provide to them allows for Liberty Utilities to invest capital.

 So now onto our next growth initiatives and this one revolves around our famous greening the fleet initiative. We see lots of new and exciting opportunities in this area. In fact, we see over $3.6 billion worth of investment. So in prior years, we told you about our Luning facility that was a 50-megawatt solar firm located in Nevada. That's 100% incorporated into the rate base of our electric utility out in Tahoe. So this project was not only of significant proof-of-concept for us. But it was the first of its kind in the U.S. to undertake inserting tax equity financing into a rate-regulated project. Now we took our proof-of-concept and now we're expanding it to other investment opportunities. One, 10-megawatt solar fan that we are putting in for our Tahoe utility in California, which is going to be approved in the next couple of weeks. The second one, we're going to be doing more community solar projects. And finally, the cream of our crop here, we're taking this proof-of-concept and we're instilling it into our 800-megawatt wind firm in the Midwest region.

 So as you can see, the greening the fleet strategy, it's not simply about 800 megawatts of wind, it's very important. It's a big project for us. But it's also larger than that. And it's getting bigger and bigger. And you're going to see in future Investor Day, years going forward, there's a lot more opportunity in this area.

 So now I'm just going to update you on our 800-megawatt wind project in the Midwest region. As I mentioned earlier, this project is strategically aligned with Liberty Utilities' concept of identifying opportunities, to reduce operating costs. In this case, we're going to close up our Asbury coal plant, and replace it with incremental investment opportunities, 800 megawatts of renewable wind, at no incremental cost to our customers. And we see out of this project -- and this is what -- even the new tax reform regime going in, that we see, on a per customer basis per year, our customers will save about $60.

 So we're really excited about this project, not only because it saves our customers' money, but if you look on this chart here, the bottom left hand side, our energy supply mix in the Midwest region right now is sitting at around 43% coal, a little sliver, 13% wind. When we initiate this project, it's going to shift that drastically to 20% coal and 52% wind in 2021. So this project, great for our customers, initiate savings for them. And guess what, great for the environment also.

 So just as a reminder, here, we're not the only utility that's doing these types of projects including in renewable projects into the rate-regulated portfolio mix. Other utilities are doing it. But it's not us that's driving this. It's economics. As Ian pointed out earlier, renewable power now is quite cheap. So but it allows us to invest $1.5 billion for this project. And that translates into with the new tax reform about $900 million of incremental rate base.

 So to finish off here. The following is a quick summary of the timelines of the completion of our project. So you can see, we took on January 1, Empire. And as a moved forward from that date onward, we started to educate new stakeholders, regulators about what we plan to do. At the end of October, we then filed with our regulators a complete filing, updating the regulators what we plan to initiate with this project. And then we anticipate the final order in 2018, June 2018, to come in with the approval of the project. As soon as that happens, we then began and initiate the Asbury closer of our plant. And that'll happen in Q1 of 2019. And at the same time, we'll begin the construction of the wind firm to be completed sometime around Q4 2020. That'll be strategically aligned with new rates implemented in Q1 of 2021.

 So you could see this project is well underway. The wheels are in motion and we are receiving a lot of positive feedback stakeholders, customers, but also intervenors are mentioning some good news stories. We've the Sierra Club that just mentioned that they're happy to see coal go away, being replaced with renewable energy. And quite a few of our customers are also expressing, wow, we're going to have savings from this project also, and it translates into, about over the life of this project, $300 million worth of savings to our customers.

 So with that, I'm going to pass it over to David, and he's going to talk to you a little bit more about utility modernization initiatives.

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 David James Pasieka,  Algonquin Power & Utilities Corp. - COO of Liberty Utilities Group   [6]
------------------------------
 Thanks, Gerald. As the last presenter in this section, I'm the guy who either gets to stretch it out or speed it up. So I'm going to speed it up. So let's talk a little bit about those pesky customers and what I wanted to do here is talk, I think earlier on, Ian and Joanne talked about the 3 key disruptors. One was the levelized cost of energy, the battery storage and the change in information technology. This -- these factors, these disruptors coming together are -- will be changing the customers' expectations, and what they expect from their utility and the choices that they have.

 We've built a 5-year plan for our customers. It involves modernizing our information systems, our customer information systems, our asset management systems as well as advanced metering. And that metering will allow us to gather more data and create new products and services, such as increased visibility and control, automated notifications and position us well for new technologies and the ability to do those peer-to-peer transactions.

 As entrepreneurs, and we talked about the entrepreneurial flavor here. Entrepreneurs think big. We've got big vision. But we have to start small and we have to learn how to scale rapidly. So at LU and APCo, we've done this. We've done this successfully over the years. We have a portfolio here which fits into that category. And there's 5 or 6 projects up here. The first couple is -- are focused in California, where they seem to be embracing technology innovation quicker, sooner, faster than the rest of the country. Two micro grid projects going into our South and North Lake Tahoe facility. And for those skiers in the group, okay, so just close your eyes for a second and think that it's actually snowing and it's been snowing for 4 days. And now we have 3.5 feet of fresh powder. So you've approached the kids over to the chairlift and they're on the chairlift and you're going up the chairlift and you're halfway up and the windiest section of the mountain, at Squaw Valley, and the power goes out and the kids start crying.

 So here's what we do. In the old world, you'd wait probably 10 or 15 minutes before the dirty diesel kicks in and you chug yourself off this chairlift. In our solution, no cut in power and you seamlessly move up to the top and you'd be able to take the kids down for the hot chocolate at the halfway house.

 We also have a couple other projects. A distributed storage project, which has been filed in New Hampshire where we're actually putting battery storage units into residential homes. Let those folks use the power to reduce their time of use costs. And we'll be able to tap into that power and pull that power out of those batteries when we needed to run our grid.

 We've also been working pilot projects in Missouri. And we have a community of project -- community solar project underway with an anchor tenant, Walmart. So as you can see, a very significant investment in starting small and then ultimately, figuring out how to scale. All told that set of pilot projects, if you will, USD 50 million of rate base investment. So you can see that we're well on our way.

 Many of you -- and we talked a little bit earlier about the natural gas infrastructure problem in the Northeast. This creates the highest cost of gas and the highest cost of electricity charges for New England states as a result of those shortages. You got the big shale pockets, but you have no way of transporting across the system. So that infrastructure -- that lack of infrastructure, coupled up with demand for those states to be more renewable has created a bigger opportunity for liquefied natural gas. And liquefied natural gas is typically been used as a peak shaving opportunity. But now it's working its way into baseload.

 So as a result, we've created 3 or 4 projects -- 3 projects up here to augment our natural gas infrastructure. The NEC project, Northeast Energy Center. We've talked about before at Investor Day. It's a gasification, liquefaction and storage project. We are augmenting our Fall River LNG tank that we currently own in Fall River, Mass with a small $18 million investment. But one more important and one that was just announced yesterday in our local community was this thing called the Granite Bridge. And essentially, what we're doing here is we're connecting 2 pipelines over here on the seacoast of New Hampshire and running a 27-mile lateral through the state and connecting it up with our other pipeline over here. So effectively, you're going to get kind of a looping, if you will, of pipeline capability. The neat thing is other than -- unlike some of those large infrastructure projects that have failed, this thing runs along a highway corridor and it's been deemed by the state as an energy corridor for this kind of purpose. So think about going into the shoulder of a highway and putting the pipeline in as opposed to going through major towns and cities.

 Like other times what we're going to do is we'll plant these flags in the 3 or 4 communities along the way, communities that do not have natural gas. So we'll convert them over. Very attractive proposition. And the third element is here in Epping, what we're going to do is, we'll build a large 2 Bcf storage tank. And the ideas is you loaded up in the summer when the prices are very, very low and then you bleed it out over the winter through peak -- in peak times to keep the cost down.

 So overall, a couple of significant advantages of this project. The most significant, and the reason why we're very comfortable with the regulators very excited about this is it will save customers a lot of money in their energy charges as opposed to this -- with this creative solution. Some of the communities along the way to also as the pipe goes through their community, do get incremental tax revenue. So everyone's really excited about just having the pipe drive-by, if you will.

 So with that, just a quick financial summary. Clearly, you've heard today about our CapEx program of about $3.6 billion. Some new technologies, including customer information, some infrastructure projects, some organic growth -- growing the fleet and greening the fleet. So overall, a rate base CAGR of about 24%, 8% normalized if you take out the Empire guys -- or sorry, if you normalize for post-Empire.

 Clearly, that rate base investment of $1.6 billion translates by 2020 to until about $800 million of operating profit, which, again, has a fairly significant sizable CAGR growth associated with it. And clearly, we're on our way to supporting APUC's dividend growth target that you heard of 10%.

 So in summary, I hope you heard and you can appreciate our diversified portfolio, our ability to predict and hit those authorized returns. Very significant investment in greening the fleet. Focused on customers now and in the future and clearly, a demonstrated ability to get some things done around here.

 So with that, I'll going to hand it over to Ian.

==============================
Questions and Answers
------------------------------
 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [1]
------------------------------
 Thanks, David. As promised, opportunities to asked questions about Liberty Utilities and then we'll jump into the international section. So Rob?

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 Robert Hope,  Scotiabank Global Banking and Markets, Research Division - Analyst   [2]
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 It's Rob Hope, Scotiabank. When you're talking about utility M&A, can you give a sense of are you looking for the sub $5 billion as a smaller municipal ones? Or could you now with your larger size potentially do more of the public listed ones, which would be seen at premium valuation?

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [3]
------------------------------
 I think, to be frank, we're a little agnostic. Clearly, if this is all got to be about value creation. And so I think we were pleased on the private transaction, where we'll do with Enbridge to acquire St. Lawrence Natural Gas. But at the same time, I think we saw value in Empire that maybe wasn't immediately apparent at the time. So I think we're agnostic as to -- or indifferent as to which approach from an M&A perspective. Clearly, I think if you're going to be at the larger end of the size, there likely going to be public entities. Though there was $2 billion of assets sold, $1.6 billion by Southern company just a couple of weeks ago. But just on that, just to be clear, maybe this puts it in context, we actually didn't see value in that proposition. We were heavily engaged in the process. But came to the conclusion that, that would be exactly the antithesis of what we say. It would've been growth for growth's sake. And it just -- it was a very difficult proposition for us to justify. So in any event, wherever were looking from an M&A point of view, we better have a story or had a thesis on how this is actually going to be constructive to per-share value in the organization, be it cash flows or earnings or both.

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 Robert Hope,  Scotiabank Global Banking and Markets, Research Division - Analyst   [4]
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 And then maybe a follow up. In Empire, in the past, you've talked about the potential to add some gas generation there as well, is now the focus almost entirely on wind with the 800 from 400.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [5]
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 Well, 2 things have happened from our perspective in Empire. One is with the falling price of the renewables, the model and the way one does this is one prepares a very complicated model to show you all these various alternatives. And the model picks the most -- creates the most effective mix. It actually chose, as I said, 800 megawatts worth of wind. And that is actually supported by natural gas that already exists, in large part, within Empire. There still is an opportunity. It's outside the investment fees of horizon that we had right now for some fast-start natural gas, which we had talked about last year. That's been pushed into 2023. And so therefore, doesn't fall into this investment horizon. But it's -- but with the machines that are available today, the intermittency, believe it or not, is lower because the capacity factors are higher. And therefore, the need to support that intermittency with natural gas is actually reduced as well. So still there but pushed out. Ben, you had a thought?

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 Benjamin Pham,  BMO Capital Markets Equity Research - Analyst   [6]
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 Yes. So on corporate tax reform. Curious if the House and Senate proposals are approved, you mentioned earlier that you can manage the greening the portfolio in Missouri. Can you walk through the analysis there? Because it seems like that tax of green market could substantially dry up even evaporate overnight, especially with BEAT occurring as proposed. So you mentioned earlier, you can manage this and may be can add a little bit of context on that.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [7]
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 Sure. Well, 2 aspects of the story on how the greening of the fleet initiative, I'll say, still has legs and still is a valid thesis. The first, and we've already talked about is that, the use of the ITC rather than the PTC is -- it sort of preserves the value proposition. Those savings, as customer savings, $300 million, $60 per customer per year are actually premised on the use of the ITC rather than the PTC. So give people comfort that the economic proposition continues to hang together from a customers' point of view. The question would be as, okay, well, what happens if the tax equity market, irrespective of the fact that it creates savings, dries up? I think 2 comments and I think this was what David's slide was intended to convey. That in the event that the tax equity market, I'll say conventionally dries up, we ourselves would be a consumer of tax equity in a sufficient quantum to allow that greening of the fleet initiative to go ahead. So we, ourselves, could provide the tax equity for that. And that's why I think one of the things that David prepared, if you look and juxtaposition those 2 sources of capital slide. One assumes that we are the provider of 50% of the tax equity needs over the coming 5 years. And that's sufficient to support the greening of the fleet initiative. I think when we think about the BEAT tax and just to put Ben's comments in context. That BEAT tax that's been proposed is kind of a minimum threshold tax at a 10% tax rate. But you aren't able to deduct PTCs in the calculation of that tax. What the reasonable expectation of that might be is to lower the appetite of tax equity providers. And if you kind of just do the math, and this is just a fill us, kind of a top-level analysis, it might actually drop that demand by half. And that's one of the reasons we say, okay, we halved the amount of third-party tax equity that we could -- that we would utilize in the system going forward. I will say -- and then the third point is about tax equity. If the opportunity for tax equity actually starts to -- the appetite starts to be reduced, I believe that, and we've seen it in the past, there will be a flight to quality. And what I mean by that, the tax equity providers historically, at the time of when the market has tightened up, have chosen those firms with a proven track record of being able to execute on transactions and deliver against those expectations. And I think we're proud of the fact that there's $1 billion of tax equity in our system right now. And I think we have a proven relationship. So to the extent that the market does tighten up, I think we're well positioned in that marketplace. I do know, Ben, if that's responsive to your thoughts?

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 Benjamin Pham,  BMO Capital Markets Equity Research - Analyst   [8]
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 That's great. And can I ask ADIT deferred liabilities? Are you going to -- give a quantify percent of rate base, what that is?

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [9]
------------------------------
 Well, just to be clear. When the ADIT gets reduced and it just gets reduced as a function of the execution of a changed tax rate, this is what Elizabeth was speaking to is, there are likely going to be mechanisms introduced on our -- from a regulatory perspective to not let the shareholder capture that benefit. That benefit ultimately goes back to the customers. And that is the process we expect that to take a number of years to implement. But it's really just a mechanical calculation of ADIT. David, I don't know if you have any thoughts on that.

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 David Bronicheski,  Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc   [10]
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 And the other thing I'll point out is in our MD&A every quarter, we actually do at the front of the utility section, put the ADIT there. So I don't know the exact number off the top of my head, but it is in the MD&A every quarter.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [11]
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 But just to be clear, that drop in ADIT is unfortunate for our benefit, it belongs to the customers and that's the effect of the lowering of the tax rate. If there's no more -- oh, Rupert, of course. Last question because I know everybody would like to get moving. But go ahead, Rupert.

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 Rupert M. Merer,  National Bank Financial, Inc., Research Division - MD and Research Analyst   [12]
------------------------------
 So a question for Peter. You talked about your ROEs and the fact they've been falling, but stabilizing now. Do you think they're factoring in a potential rise in the federal fund rate over the next year? And if we see, say, a 100 basis points increase, is that enough to affect tailwinds to the ROE?

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 Peter Eichler,    [13]
------------------------------
 Yes. So I think if you look at the way that traditionally, the ROEs sort of lag a little bit. And so what we'd expect to see is an eventual catch up. And so with any increase in T-bills or long-term treasury rates, we'd expect to see ROEs start to tail up shortly thereafter as well.

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 Rupert M. Merer,  National Bank Financial, Inc., Research Division - MD and Research Analyst   [14]
------------------------------
 So you don't think their factoring in an increase?

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 Peter Eichler,    [15]
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 At this point, probably not yet.

==============================
Presentation
------------------------------
 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [1]
------------------------------
 Okay. With that, we're just going to actually do a quick change here. Thank the panel, and we're going to jump into our international discussion. I'm going to welcome Chris back to the stage. And a new face, Armando Zuluaga, who is, I'll say, joining us. He's the future CEO of AAGES, this joint venture with Abengoa. And he'll be talking a little bit about the AAGES opportunity. And so, I'll turn the things over to Chris. Chris?

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 Christopher K. Jarratt,  Algonquin Power & Utilities Corp. - Vice Chairman   [2]
------------------------------
 Great. Thanks, Ian. I mean, one thing Americans and Canadians can agree on is how to say zed, but we just accept that and move on. Wait till you meet the Spanish. They got a whole new way to say zed. Anyway, so as Ian said, we're just going to talk about this new global growth initiative that we have on. And just a lot of this is a repeat. I mean, there are huge drivers in -- globally with respect to renewable energy. And you can see from these charts that there's maternal growth expected in renewable energy. And the reasons are all the same that higher load growth is occurring in developing markets. And also that, as Ian has said a couple of times, it is the cheapest form of generation barring none. And there's this huge drive to convert carbon to non-carbon. So for these reasons, with think it's a great time for us to get into the international markets at this time. Because it does capitalize on the global growth of renewable energy. It matches with our core competencies, and it also provides us with a great growth platform going forward.

 So this chart here just shows a couple of things. It shows how in the U.S., you can see how annual power demand is actually tailing off. And it is actually going negative as you go out. Where in the global markets, you're still seeing modest increase. The graph on the right shows how the carbon intensity is declining, and especially in global markets. So for us, the reason for being in the international markets is just crystal-clear. They capitalize on these 2 benefits. There's also the bolt-on opportunities that we've talked about already, the energy storage, fast-start natural gas that we just talked about, transmission as well as distributed generation. These are all things that are associated with this drive to renewable energy and things we see a huge market in.

 So we have been talking about international growth for some time. If you hear our quarterly calls, you hear it come up and it has probably for certainly a year, maybe 2 years. And we've always said that we would take this step at the right time, when it could be done in a low risk, measured and strategic manner. And the point of this slide is, well, international growth is something that's new for Algonquin, new things for Algonquin aren't new. And if you look at this time line, it kind of shows how we have grown the organization from our first generating station, which was a 780-kilowatt generating station to where we are today. And we've taken on many, many new things. And I would say our playbook has 3 main components to it. First, we bring an entrepreneurial mindset to every type of new initiative that we take on. The second is we spent a lot of time on understanding and mitigating risks. And I guess the last point of it, we always start in a very measured fashion and we scale quickly. And so that's kind of our playbook. And so for us, moving outside the borders of Canada and the United States just is the next logical step for us.

 Just want to talk about what that international strategy is and kind of walk through and spend a couple minutes on the various complementary initiatives. The first keyword here is strategy. And I think there's 2 equally important components of that strategy. The First part of that strategy is the purchase of a 25% interest in Atlantica Yield. This was announced in November 2017, and we expect it to close early 2018. Atlantica is a publicly traded entity, and we're going to talk about it a little more in detail in the next slide. It owns a portfolio of very high quality assets that from the very start are accretive to Algonquin. And about 70% of these assets are in markets which are new to us, namely outside of Canada and the United States.

 The second part of this strategy is the formation of this new international development entity, which we referred to as AAGES, which is Abengoa, Algonquin, Global Energy Solutions. And Armando is the CEO of that organization, he's going to talk about that in a little bit. It's a 50-50 joint venture and it's a measured step. And what you're going hear a little bit about is it's always experienced partners and it's in select, stable and attractive jurisdictions.

 To me, this is probably the key slide to the whole thing because it shows how the strategy all fits together. And now that you know a little bit on who Abengoa and Atlantica are, just going to kind of talk about how this is a true win-win-win opportunity for everybody. From Abengoa's point of view, they get to monetize their investment in Atlantica. They get to get back to their core competencies, which are EPC and O&M service providers. Moving on to Atlantica, what they get to shed is the overhang of having an uncertainty regarding their major shareholder. They also get a pathway to future growth through a new ROFO agreement with the AAGES organization. And they get a supportive shareholder in Algonquin, who is prepared to fund future growth.

 From our perspective, we get to enter international markets in a measured yet meaningful way with experienced partners. We get to capitalize on Abengoa's global presence and expertise, which Armando is going to give you a little bit more details on. And we also get to enjoy the immediate accretion of a portfolio of high-quality assets. And as I've mentioned earlier, we get to fund future growth. So all in all, this is a win-win-win. And the other part of this partnership that's worthwhile talking about is a fact that from a cultural point of view, I would say it went extremely well and we're optimistic that there's a great cultural fit between all the parties involved.

 Just want to do a little bit of a deeper dive into Atlantica and Abengoa. And I'll do the Atlantica section. So Atlantica was formed in 2014 and is listed on the NASDAQ stock exchange. It's an established and well-run entity, and the highlights of our investment, as I said, we're 25% interest, which we're paying at approximately USD 600 million for that. We also see there's an opportunity to add value through a 25% representation in the Board of Directors. And we have, as we've said, this preemptive right to fund future growth. And so you might have recognize a couple of these from the Ameren play book, when they invested in Algonquin, which was great for Algonquin and frankly great for Ameren back in 2008, when they were our larger shareholder.

 So with respect to Atlantica's assets, they've got an unprecedented 21-year Power Purchase Agreement length. They enjoy the diversification benefits, much like we do, geography and modality. And they also have a little bit different financing structure. They financed things at the project level, with nonrecourse project debt. And all debt amortizes before the Power Purchase Agreements or Agreements at the end of the contract life. So consequently, we see this thing as a 100% contracted and quality cash flows. The cash comes off is denominated in U.S. dollars and most of it is hedged. They have a conservative payout ratio, which -- because we are the receiver of the dividends from Atlantica, makes for a very stable and secure cash flow.

 Just wanted to do a little bit deeper dive into Atlantica. You can see that the modalities of the top right there, they're all modalities of things that we understand

 (technical difficulty)

 and we've done it for decades now. So it's generation, transmission and water. These are all things that we understand well. From an investment thesis, they have adopted a very similar thesis to Algonquin, namely that they focus on share price appreciation as well as growth of the dividend. They have a high-quality diversified portfolio. And you can see the pie charts at the bottom. It's mostly renewable energy. Some clean energy. And from a geography perspective, there's a preponderance in Europe and North America. What's interesting for us is the South American aspect to it. We see South America as a significant potential growth area. And we like the jurisdictions that they're in. Probably for 3 main reasons: one, they have stable governments; second, they have rule of law that prevails in them; and repatriation of capital is allowed.

 So with that, I'm going to pass it over to Armando. And Armando is the CEO of the AAGES organization, but he was also a 17-year employee at Abengoa. So he's probably well-suited to give you a little bit of a deeper dive into who Abengoa are.

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 Armando Zuluaga,    [3]
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 Okay. Thank you. Thank you very much, Chris, Ian and the rest of the Algonquin team. As Ian somehow said, my name is Armando Zuluaga, okay. We'll get there. We've been practicing for the last 3 days. But I think that by the end of this week when we repeat this presentation in New York it will...

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [4]
------------------------------
 It will get to Zuluaga.

------------------------------
 Armando Zuluaga,    [5]
------------------------------
 That's right, okay. So I'm very excited to be able to be here, to share with you my thoughts and my views on AAGES and how we see the future for that vehicle. But before that, let me just give you a hint of who is Abengoa, for those of you who doesn't know about the company. I mean, Abengoa was a company or is a company that was founded back in 1941. So has been around the market for over 75 years already. And in the last couple of years, Abengoa has gone through a financial restructuring, that now is completed. The company did sign its restructuring agreement with all the financial entities back in March of this year. And now it's refocusing its strategy. And as Chris was saying before, it is going back to the basics, which for Abengoa, is engineering and construction and O&M services.

 As a consequence, they will be focusing more on EPC and O&M contracts and less on the development. And this is why for those within Abengoa that have been doing development for the last few years, AAGES represents a huge opportunity, because we will be able to combine both the skill sets that today we still have within the company, the global presence that Abengoa still have. And therefore, the business development capabilities that we do have in the local geographies in which AAGES is going to be present as well as we will be relying, of course, on Algonquin's strong access to the capital markets. So we can develop new opportunities and we'll be adding value for both of our shareholders. Abengoa is a company that today is still present in most, if not all, of those key geographies. For AAGES and today, it is already relaunching all its business activities.

 Just to give you another example of what the company has been able to achieve over the last 75 years. Abengoa has been all around the globe working in different kind of projects. And in the power sector, Abengoa has been able to develop, finance and build more than 6 gigawatts of projects, over 2.5 million liters per day projects in terms of desalination capacity and over 27,000 kilometers in transmission lines. And all that, again, in a global market, as you can see in this map.

 But let me get back to AAGES, and what do we see or how we see the future and the strategy of this development vehicle. First of all, why do believe that AAGES will bring the strategic benefits for both parties. First, because we are going to count on a very experienced and highly successful management team. We are talking about people that have been around in the average for more than 20 years in all those countries in which we are going to be pursuing these opportunities. It's going to be an entity that is going to be capitalized from the very first minutes, so that we will be able to take on those early stage development opportunities that we have just there. And also as a consequence of the refocusing of Abengoa's strategy, AAGES will have an access to an immediate earlier stage pipeline that will be offered to the company, as I will explain a little bit later.

 Those sustainable or those capabilities are going to be based on sustainable competitive advantages. But mainly, as I was explaining before, we will be leveraging on 2 things that combined are perfect for a vehicle like AAGES. The first one is the global EPC and O&M skill set of Abengoa. The second is that having a very strong partner as Algonquin will allow us also to have access to the financing of our projects.

 In terms of the transaction structure. I think that has already been explained by both Algonquin and Abengoa. This is going to be a 50-50 joint venture. So it's going to be equally owned by both partners. The initial Abengoa capital contributions will come out from the proceeds that Abengoa is getting out of the sale of its 25% stake in Atlantica. And what is most important, in terms of the governance, we already have in place those procedures and the mechanisms that will allow us to avoid potential situations where conflict of interests appear. And as such, the affiliated transactions among other things will be of course approved by non-conflicted directors. So we will make sure that when contracting, whether with Algonquin or with Abengoa entities, those contracts are going to be arm's length and based on commercial market terms.

 In terms of compliance, which we also believe it is important to address in this audience since it is the first time that Algonquin is betting in a more explicit manner for projects abroad, meaning outside the Canadian and U.S. borders. We will, of course, benefit from the strong corporate culture that the managers coming from both Abengoa and Algonquin, when joining the company, will bring to the table. We, of course, believe and in this case, me personally believe that this is a top-down driven policy. And therefore, leadership is absolutely a must. In fact, compliance is like safety. It is a journey that goes forever. And I personally believe that it is not just the best way but the only way of doing business. As a consequence, we will be deploying a comprehensive compliance program to make sure that everything is aligned at every given moment with standard tools that all companies do have. So we will be making sure that we will preserve, of course, the highest standards, not just of course for the benefit of this company but also for the benefit of all our stakeholders.

 I was talking before about the management team and this is just another example of what we are talking about. Again, we are talking about an organization that as of today, already has names on it. We are talking about a team that is already working in trying to secure the near-term opportunities that we have ahead of us. And as I was also conveying before, it is a very experienced management team working in those technologies, in those kind of projects and in those geographies that are going to be the target geographies for AAGES. We will have all those core capabilities, all those core competencies within the company, in-house, so

 (technical difficulty)

 outsourcing some of what we consider to be the noncore functions of the company. And they will be outsourced to our parent companies or even to third parties. So we make sure that we are, as I was saying, efficient and flexible.

 Just to give you some examples of what we're talking about here. We will have, as the Chief Development Officer of the company, Michael Geyer. Michael is probably one of the best known solar developers worldwide. He has been in the industry for the last 30-plus years. So it's one of the first managers that did start solar developments already in the '90s. And in the last 10 years, he's been the Chief Development Officer of Abengoa Solar, being able to develop projects in Africa, in the Americas and Europe. Together with him, we are also going to have Javier Montfort joining the company. He's an industrial engineer that has been working with Abengoa for the last 10 years as well, where he had a very similar position to the one he will be having within AAGES as a Director of Global Energy and Water Concessions. And finally, we are going to have also Kevin Melnyk as the new CFO of the company. Kevin has been working for Algonquin for the last 5 years. But overall, he has more than 25 years of experience in the sector that will, of course, help meaningfully AAGES to be successful in the financing strategies of the company.

 In terms of the project focus, we're going to be focusing on those modalities, on those technologies that are very familiar to both entities, Algonquin and Abengoa. On the generation sector, we are going to be pursuing opportunities within the renewable, clean energy projects and hybrid plants, where for example, Abengoa has been one of the few companies worldwide being able to develop projects combining solar and gas at a commercial scale. We'll be doing, of course, water projects, desalination, water transportation and water recycling, transmission and distribution, but also storage. Storage, as Ian mentioned at the beginning of today's presentation, we've already -- we've always considered that to be a game changer. We do have the knowledge and we do have the capabilities. So we will be trying to develop also storage projects whether as standalone products but also combined with other renewable generation.

 But what are the key investment parameters? It has been explained, AAGES will be signing a ROFO agreement with Atlantica to reinforce the ROFO agreement that Atlantica today has in place with Abengoa to make sure that this is one of the channels that Atlantica uses to grow. As such, we will be, of course, focusing on high quality off-takers in stable countries, where we can have predictable regulatory frameworks, and as also Chris was mentioning, within a strong culture in terms of rule of law and in terms of low sovereign risk.

 In terms of the currencies and to mitigate the FX risk working worldwide, we will be focusing mostly on what we call hard currencies, meaning euro and U.S. dollar. But we will, of course, also pursue some other opportunities that might not be denominated in either of those 2 currencies. But if that is the case, we will make sure that we have hedge agreements in place to mitigate or to avoid completely that risk. Since these have to be in principle assets that might be dropped to Atlantica or even to Algonquin or a third party, we'll be deciding on a case-to-case -- case-by-case basis. We will need, of course, sorry, to have long-term offtake agreements in place, so that we can have project fund structures also for those projects.

 In terms of the financing strategies, I was saying at the beginning that AAGES is going to be fully funded from day 1. So we will be able to finance and to fund the early stage development activities that the company will need to secure the opportunities. But once the project is mature enough and both Algonquin and Abengoa at the board level have decided that we can consider that to be a real project, a real opportunity, then we will be incorporating a new company, an SPV, that will be doing the rest of the development of the project.

 For the construction financing, we will have in place typically project finance schemes in different modalities that will depend of course on the opportunity and on the market. But what is more important is that Algonquin is also committing to fund most of the equity for those projects, if not all. And finally, of course, once those projects have reached COD, we will think about dropping them down. And as I was saying, one of the natural exits of those projects is to be rotated into Atlantica Yield. But again, that is not going to be an exclusive option, but a good one.

 In terms of the global reach, where we're going to be focusing in our projects? As you know, the world is big enough to find opportunities in different locations, but we're going to be very selective, of course, in the geographies where we're going to be developing projects. Mostly, we're going to be focusing in Mexico and in Latin American countries that we believe do fulfill the key investment parameters that I was mentioning earlier as well as in Europe, where -- as we will see later on that are also significant opportunities in terms of the market size. Those are all, again, markets that we know perfectly well. Those are markets in which we have been working so far for the last 10-plus years. And therefore, we feel pretty comfortable that the projects that we will bring into AAGES are accretive, not just against the company but also potentially in a future rotation to its stakeholders.

 There are some other opportunities that we may be pursuing in other geographies different from Latin America and Europe. We will be, of course, assessing those and analyzing those opportunities on a case-by-case basis. But the fact that, again, in those countries, Abengoa has a long-standing presence and we do have a very specific knowledge of those local markets. We do not want to miss a good opportunity either. So we will be, of course, relying on that knowledge, of course, to develop projects whether in the Middle East or in Northern Africa or in Southern Africa. Again, those are not going to be the key geographies for the company, but we will take a look at the opportunities that we may find there.

 In terms of the size of this market opportunity we're talking about. And again, this is just a hint. This is just an example of how we see the market. To be more specific in the power sector, which is a modality that is more familiar to Algonquin. As you can see in the Latin American countries, in the Americas, we have opportunities that do have a name on them. So these are real opportunities that are being developed whether by off-takers of those projects or that have been developed by Abengoa and the different entities of Abengoa working in those countries. And the market opportunity, the size of the market opportunity in Latin America is above 35 gigawatts of new power projects.

 In Europe, similar thing. The power of the transmission generation is also changing. In Europe, we are going to be seeing very important projects to interconnect the grids in Europe because the goal of the European Commission is not to have any single power island. So all the different countries in the European region will have to be interconnected. And again, in the next couple of years, we're going to see very interesting and attractive projects. On the power side, we're talking about opportunities above 90 gigawatts of new power generation. And in Africa, just to give you a flavor of what we're talking about, we've also identified projects that could be interesting in the range of 15 gigawatts.

 But talking now more specifically about what are those near-term opportunities that AAGES will be able to have access to. The first one is a 220 megawatts cogen plant in Mexico, the A3T, with an approximately CapEx of around $450 million. And that is a project that is today under construction by Abengoa. It is more or less 80% built, and we are expecting to get to COD at some point during 2018. So this is the first opportunity, the first real opportunity that we have just there. Today, the plant has been able to secure already above 20% of its capacity in PPAs that have already been signed. And as we speak, offers that amount to 230 megawatts have already been presented and are being negotiated with counterparties.

 The second opportunity is ATN3. ATN3 is a transmission line that was awarded to Abengoa under a concession agreement 1.5 years ago with an approximately CapEx of around $220 million and with a COD that is expected in early 2020. Also, we have submitted an expression of interest to the lenders, to the bridge lenders that were financing that transmission line. And we are engaging ourselves in negotiations just next week. So that is another opportunity that is just there and that we will make sure that we can secure. It has a concession term of 30 years and very attractive returns.

 And just to finish, let me show another near-term development opportunities with a name, let me emphasize that and last name in some of those countries that we believe are going to be key. First in Chile, there are very attractive opportunities in the transmission sector, transmission and distribution. And we are talking about projects that are being tendered in the first, second and third quarter of 2018 that we are getting ready to bid.

 Same thing with the -- sorry, with the Uruguayan project. We are talking about a project that is being tendered in the first quarter of 2018. And again, that is also a project that the team within AAGES is already working on. And finally, some facilities, some existing facilities in Morocco that can bring, again, opportunities for new investment, if that is so decided by the Board of Director of AAGES.

 Just to conclude, key messages. Number one, AAGES is already a reality. It is true that we have some steps still to complete in order to incorporate the vehicle, but we do have already a team that is working and building the pipeline for near-, mid- and long-term opportunities of the vehicle. Number two, as I said at the beginning, this is a vehicle that is going to be completely funded from day 1, so we will be able to hit the ground running. And third which is not less important, let me emphasize once again that we are going to have a team in place that know how to make things happening. And that is key. There are many, many opportunities, many developers, but again, this team has shown and has a proven track record that we do know how to make this a reality.

 And with that, I pass over to...

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [6]
------------------------------
 Okay. Thanks, Armando. I'm just going to take a couple of minutes of your time before we wrap up to kind of talk about the financial aspects of this international expansion strategy.

 As I mentioned earlier or as you've heard, we're buying 25% interest in a company called Atlantica. Clearly, part of the thesis is that Atlantica will continue to grow, and they will continue to grow either through execution on their own pipeline of growth opportunities or through projects that will be presented to them under the ROFO agreements that exist today from Abengoa and are expected to exist with AAGES.

 The thesis for Atlantica is to, obviously, invest in projects which generate accretion on a CAFD, cash available for distribution basis, on a per share basis. And one of the opportunities actually that Atlantica have in front of them is cash, a resource -- a cash resource, which is accumulated in some respects as a result of the troubles that Abengoa has had that caused some technical defaults and to the loan agreement. And therefore, cash has been trapped, if you will, within the Atlantica structure and hasn't been able to be paid out to shareholders, but the fact is they now have over $100 million of cash available to be used to execute on some of these growth initiatives together with, and you may have heard at the time of the announcement that we have notionally earmarked another $100 million of capital under our preemptive right to invest to encourage and fund growth of Atlantica going forward.

 It is our belief and obviously I invite you to attend the Atlantica Investor Day, but it is our belief that as we look at the opportunities that sit in front of Atlantica today, including the near-term opportunities that Armando described, that seeing mid, even to high single-digit growth in CAFD on a per share basis is certainly accomplishable by Atlantica.

 And a couple of those opportunities I have in the screen here, these are opportunities, these are projects which interestingly have been built. They're operational, they're within the Abengoa inventory. But for the troubles that had befallen Abengoa, would likely have already been sold to Atlantica but because that -- of the circumstances, they remain operational within the Abengoa portfolio and are therefore available for immediate sale into Atlantica. Two of them, a solar project, sister project to an existing one that Atlantica owns in South Africa and further expansion of their water desalination capacity in North Africa.

 But one of the questions that got asked at the time of the announcement of this initiative was how does AAGES make money? What's the economic proposition associated with this joint venture? And in short, it's about buying wholesale, developing an asset and selling it retail. That's how a developer makes money. AAGES, no different than any other developer. So the thesis is that Abengoa or AAGES will develop an opportunity, put the time, effort, creativity in. It will be funded, in large part, by Algonquin. It's the same thing we do right now as we're developing our Blue Hill wind project, as an example, in Saskatchewan. And then ultimately, that project would be sold into Atlantica. It could be sold directly to Algonquin. But the thesis is that AAGES makes a margin on the way through. Clearly, as the provider of the lion's share of that equity, that margin, in large part, accrues to us, and we would obviously translate that into a greater stake in Atlantica if the project got sold out in Atlantica.

 But typically, those margins historically for developers who are active in the industry mark 5% to 10% of the total capital cost. That's not an unreasonable thought about the margin that's available from a development perspective. Could be a little higher depending on the circumstances. But certainly that value proposition, because it's sort of speculative, we haven't baked in to any of the thoughts going forward in terms of growth, so there's an upside that we haven't really discussed.

 The other question that got asked at the time of announcement is do you see the investment in Atlantica as being accretive to the trajectory of growth that Algonquin is professing to be on? And so what we did is we reran the numbers that I presented to you at the – couple, 3 hours ago in terms of the growth and earnings per share and in terms of our EBITDA. And we're confident that the addition of Atlantica in this international strategy is -- creates value both in terms of near-term accretion. It was a question that obviously we asked -- we answered at the time of announcement. We said midterm -- mid-single-digit accretion on a percentage basis from an EPS perspective over the near term.

 But perhaps as importantly is does the trajectory go up? Are we increasing the overall trajectory of the organization from a growth point of view? And we believe that both in terms of growth in Atlantica shares itself from a CAFD perspective, and we expect Atlantica is roaring and ready to go back to work with clearing of the obstacles that, as I said, arose as a result of Abengoa's troubles. But second of all, the opportunity for Algonquin to increase its stake beyond 25% is just to reiterate a comment that got made at the time of the announcement. We have the right, in some respects, preemptively to go up to 41.5%. And so growth and accretion for Algonquin can come in those 2 forms, growth organically within Atlantica and increasing of our stake in Atlantica.

 So just a quick couple of closing remarks. As Chris mentioned, this is the culmination of a couple of years of thinking about how do we go about this? And to be frank, this feels a lot better than that thought of, "Well, let's go open that office in Santiago, Chile, try to staff it up, figure out what's what and start to build a team down there and seeing what we can come up with." I'm not even sure that we know if Santiago, Chile was the right marketplace. What Armando has described is a team that's up and running, and I think produces far nearer term and far lower risk results than a strategy of just trying to do this ourselves by capitalizing on the talent that exists within Abengoa, and maybe perhaps even a little modestly, the development expertise that Algonquin has demonstrated over the past 30 years as well.

 So thoughts, comments, questions, happy to open it up for some questions on the international side of things.

==============================
Questions and Answers
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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [1]
------------------------------
 Nelson, you had your hand up first. You've kind of like reached for the top. I guess I'm dating myself with that one.

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 Nelson Ng,  RBC Capital Markets, LLC, Research Division - Analyst   [2]
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 So Ian, in terms of when you talk about that team size for -- can you talk about the team size for AAGES? How many from Abengoa versus Algonquin? And then with that, can you talk about the, I guess, the cash burn rate? I see -- like before making equity investments and developments.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [3]
------------------------------
 Sure. We've envisioned between probably 12 and 20 is the number of individuals that would be recruited. As I said, it's a brand-new company. AAGES would have these as their employees. It's not a secondment. It's actually a new employer. And as Armando had mentioned, AAGES is going to be initially capitalized with $10 million worth of capital. But both Abengoa and Algonquin have made a commitment on a go-forward basis to fund the burn rate, we're kind of estimating in the couple of million dollar range, if you want to think of it that way and you think about 15 to 20 people plus travel costs. You can -- that feels like kind of the quantum of it. Obviously, I think where things get more interesting is when the opportunity to invest in a particular project comes up, and we'll have the kind of look at the time. And just to be clear about one of the comments that Armando made, well, it's clearly expected that the capital for this initiative will come from Algonquin. It's not without, I'll say, Algonquin's approval. There's a board and both Abengoa and Algonquin would have to agree upfront unanimously to say this is an opportunity we want to pursue. So and in the context of that, we would look at how much capital needs to go into it, what are the competitive uses of that capital across the organization? But that's where, obviously, the numbers get more meaningful.

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 Nelson Ng,  RBC Capital Markets, LLC, Research Division - Analyst   [4]
------------------------------
 And then just to follow up on looking at projects. Can you talk about the -- like do you look at a WACC return, equity return, assuming there's some level of debt? Like what's your approach to that? What's the, I guess, premium you see in like some of the various geographies? And then when you look at that, is the approach to say, like do you look at it and say, that's the derisked value? Can I bill it for 5% to 10% less? And is that...

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [5]
------------------------------
 Yes, clearly -- yes to what you're saying. Clearly, the valuation methodology for a project which is project financed, would be -- you would think of a different leverage level than we would do within Algonquin proper for a development project. Having said that, I think project IRR is a fundamental metric that we'd be looking at that to see does it feel reasonable. And in the context of what's a reasonable project IRR, yes, you obviously have to build in a country risk. So if you thought that Peru right now might have 85 basis points on top of what would otherwise be a reasonable project IRR. So if we were willing to do a project for, call it, 8% here in Canada, U.S., you'd probably be looking for at 8.85%, but ultimately, the part of the value thesis has to be is if I build it for 8.85% from an IRR perspective and I leverage it just so from a project finance point of view, what does my dropdown look like now when it has to go into something like Atlantica? Because ultimately, AAGES itself isn't a buy and hold vehicle, could be an Algonquin, could be an AAGES. So AAGES has to look that one step further to say, as we think about the parameters, as Armando had articulated, they have to be suitable ultimately for that project either to be held by Algonquin, which would impose its own set of constraints or held by Atlantica, which, again, has its own constraints. Obviously, Algonquin, getting back to Jeremy's very first question, is an earnings kind of focused organization. Atlantica's more cash flow focused. And so those are the -- I mean, the good news is, we have some optionality as we think about that going forward, but those are all the considers that we'd look at from an investment perspective. With the thesis ultimately that AAGES needs to make money for taking that development risk, which Algonquin does right now as it thinks about it. You had a question? Yes, go ahead.

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 Unidentified Analyst,    [6]
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 It's [Dean Highmoor] again from Mackenzie Investments. I apologize, I'm less familiar with Abengoa, but I'm just curious to know what were some of the main mistakes that you guys committed in the past? I guess, this is a question for you, Armando. What were the main mistakes that you committed in the past that brought the company to the point where you needed to restructure it? And probably more importantly, what were the main lessons learned from that experience?

------------------------------
 Armando Zuluaga,    [7]
------------------------------
 I mean, as you can imagine, this has been a massive restructuring. So there is no just one factor. It's, I'm afraid, a little bit more complicated than that. But mainly, it is a combination of, on the one hand, maybe the bet that Abengoa did some years ago for the bioethanol business. Number two, we had to face some problems that were not predictable in Brazil because of the problems that the country did have. For example, a good number of the kilometers that you've seen in the transmission lines that Abengoa was able to develop and build were in Brazil. So there was a huge financial bet on the country that the company wasn't able to overcome. So again, all in all, what I would say in brief is that, first, it is not just one factor. Second, it is mainly driven by financial reasons, in the sense that from a technical perspective, the projects -- and Algonquin have been visiting all those projects that were rotated into Atlantica. And I think they feel pretty comfortable with them because of the quality of those projects and the level of performance. So again, it is more on the financial side and the financial management side of the picture than on the technical side. But those 2, for example, were 2 very important factors that the company wasn't able to manage.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [8]
------------------------------
 So just to add some words to that. As we looked at the work that Abengoa has performed from an EPC perspective as we did our due diligence, we never came to the conclusion that, "Oh gosh, we didn't like the quality of the design or the implementation." Clearly, as Armando said, the challenges they had were, I'll say, money-related as opposed to competency-related. So I think that speaks to our comfort with continuing to, I'll say, lean in on Abengoa as a provider of EPC services. I think Abengoa has been pretty clear that they're out of the development game themselves that, that's not clearly -- cannot understate that bet on bioethanol where you're obviously arbitraging 2 unhedgeable commodities, that being oil and the price of corn. It didn't work out very well.

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 David Bronicheski,  Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc   [9]
------------------------------
 We have 2 questions coming in from sli.do. We do have 2. What is the status of the DOE waivers for Solana and Mojave? And can you describe some of the key milestones for the $0.60 earnout for the AY?

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [10]
------------------------------
 Sure. Well, very quickly, I understand the DOE waivers, the agreement has been reached with the DOE on those waivers, and so in some respects, it's simply a matter of executing documents associated with those if...

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 Armando Zuluaga,    [11]
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 I mean, the documents have been, in fact, executed. It's about complying with the CPs that are typical in these kind of (inaudible).

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [12]
------------------------------
 Yes. And one of the CPs, just to be clear, just to put this in context, the question is regarding Department of Energy, which is -- was a provider of support for the significant solar projects of Atlantica that exist in the U.S., involved a posting of security by Abengoa for some warranty repairs that are still being made right now. And so that security is being posted out of the proceeds of the sale of the Atlantica shares. And so clearly, that CP won't be satisfied until closing. I guess, the other question is what are the steps? Well, let me just finish off. In terms of the closing, the FERC 203, which is a requirement just under the FERC regulations, will be filed, I guess, it's going to be later this week. And that's got a 45-day or so clock associated with it. Then the other question's on the earnout of the -- what David's making reference to is in the agreement that we reached with Abengoa on the purchase of the 25% interest. There was a $0.60 -- up to a $0.60 step-up in the purchase price paid. It's tied solely to escalation in the price of the Atlantica shares over the period of time, the year following closing. It was intended to, if you will, align the interests of Abengoa and ourselves in terms of providing as much support for a re-rate, if you want to think of it that way, of the Atlantica shares. And so that's how that $0.60, it's 1/3 of the first $2 of escalation of the price of the Atlantica shares above the price we paid of $24.25. Yet another one, David?

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 David Bronicheski,  Algonquin Power & Utilities Corp. - CFO and CFO of Algonquin Power Management Inc   [13]
------------------------------
 That's it. You've cleaned my sli.do.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [14]
------------------------------
 Okay. Mark?

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 Unidentified Analyst,    [15]
------------------------------
 Yes. Just wanted to go back to one of the projects you talked about near-term investment opportunities, the A3T project. Obviously, it's a bit later stage. So explain to me how this evolves from your perspective? How much capital you might commit? And whether or not you just replace the capital that Abengoa has spent in that project so far?

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [16]
------------------------------
 Yes, so just to put both A3T and ATN3, that cogen, which is an expansion of the existing cogen which is owned by Atlantica and a new transmission line called A3TN -- ATN3 into a context is, clearly the continued funding of the development and construction of those projects is a strain on Abengoa. That creates an opportunity for AAGES, if you will, to take over the construction of those projects and ultimately, the vending them into Atlantica. The actual quantum of the capital, how much would AAGES pay versus how much is the project worth, is frankly going to be the subject of a negotiation. There's a ROFO agreement in respect to those between AAGES and Abengoa for those projects. But the actual commercial terms of what does it get dropped down into AAGES at and then ultimately dropped down into Atlantica, those are the terms of negotiations which are underway right now. But the thesis would, obviously, be as AAGES steps into the shoes of Abengoa as the developer, there's an expectation that AAGES would earn a return on that, but the amount of that return is going to be the new process -- the subject of yet-to-be-had negotiation. In fact, it's a currently underway negotiation right now. So I can't tell you the exact quantum of it. I think you can get some context at the whole project, at least the A3T is in the $400 million range. Obviously, construction financing is a piece of that. So what's the equity check? Don't really know right now, but it's obviously less than $450 million.

------------------------------
 Unidentified Analyst,    [17]
------------------------------
 Okay. And then a follow-up on that would be in Jeff's presentation, you talked about perhaps about $800 million of capital invested internationally in power. Maybe you could flesh out besides A3T, which projects you guys have itemized for that bucket?

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [18]
------------------------------
 Well, there are -- in some respects, we've identified 4; 2 immediately available dropdowns that Atlantica should be, in our opinion, considering from Abengoa though, that's the China and Ténès projects that are already up and operational and should be dropped down. They're available for dropdown, and so we're encouraging Atlantica to negotiate that arrangement. And then the other 2 are the ATN3 and the A3T projects. If you kind of look at that portfolio together and given that Algonquin has a preemptive right to fund that equity, that's the lion's share of the source of that $800 million of incremental capital opportunity that we're forecasting over the next 5 years. And so you actually don't have to look very far, Mark, to kind of see that, that $800 million of future investment potential that's occasioned by the investment Atlantica, you have to look very far to be able to add those numbers up. I think if you do the math, you'll see you get pretty close.

------------------------------
 Unidentified Analyst,    [19]
------------------------------
 Okay. Just one last one here. Yes, could you talk just a little bit about some of the new modalities you're getting access to? And how do those fit into AAGES and, I guess, Algonquin's longer-term strategy?

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [20]
------------------------------
 Sure. I think the most, let's say, significant, you're going to hear a story from Charlie, the science guy, about energy storage. And one of the aspects of the story you're going to hear from him is the ability for, I'll call it, thermal energy storage. So this idea of being able to use a thermal mass to store energy to -- for temporal shifting of that. I think it is -- Abengoa would be, I'd say, a pretty unchallenged leader in the use of concentrated solar CSP with storage baked into it. And just to put that in context, the largest storage facility is actually owned by Atlantica. It's the Solana project in the U.S., has 6 hours of storage at 200 megawatts or...

------------------------------
 Unidentified Company Representative,    [21]
------------------------------
 280.

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 Ian E. Robertson,  Algonquin Power & Utilities Corp. - CEO, President and Non-Independent Director   [22]
------------------------------
 Pardon me, 280 megawatts. So when you think of that in terms of like 1,200-megawatt hours of storage, like, I couldn't even imagine the number of batteries that, that would occasion. So that's an interesting thesis. And so I think there's applicability for that as we think about, and you're going to hear about Charlie's comment about the decline curve of storage. I think thermal storage is something that's very interesting from our perspective. Particularly, if you just want a little bit of a brainteaser, all of these coal plants that are about to be retired across the U.S. have interconnection, steam turbines. They've got a lot of the infrastructure that you could imagine that somehow you could be thinking about using that for thermal storage. So that's an interesting opportunity. The other one that we're clearly supportive of is desalination technology. As we think about the global need for freshwater, it just -- it seems like just a no-brainer from our point of view. We've got a lot of water utilities across the U.S. We know how to -- but man, here in North America, we lose sight of the fact you just sink a well and all of a sudden, you've got 500 gallons per minute of a free-flowing well. That's just not the way it is across the rest of the world. So we're quite excited from that technology perspective as well.

 Okay. I'm sorry we've run a little bit late, but I guess, I'd suggest that we wrap it up. We have lunch. As I said, I encourage you to grab lunch. And as a kind of -- as sort of a thought for -- to lure you back to follow on the question about energy storage, Charlie's got a great presentation to kind of walk you through the various alternatives for energy storage and how they make economic sense.

 So again, thank you so much for showing up for this 8th Annual Investor Day. And we would very much welcome feedback on the day as to whether this has been helpful and informative, what we can do to make it better, whether we answered all your questions. So thanks very much. If we don't see again, be safe.

 (Break)

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 Charles Ashman,  Algonquin Power Co. - VP of Technology   [23]
------------------------------
 Moving up. How's that? With my Florida accent. So but welcome, everyone. My name is Charlie Ashman. They told you my title, which is better than the title that's up here. I get calls every week about information technology and that's not my field. Being the science guy is the nicest things people have said to me in a long time, so that's pretty good.

 Today, we're going to talk a little bit about the role of storage in a world of 100% renewable energy. When they first gave me this topic, I got really excited. They wanted me to tell you everything there is to know about energy storage. And I showed up for my first practice with a syllabus that would've taken about a semester talk about. So Ian quickly took that away from me. And he rephrased the challenge, tell them everything they need to know with virtually no information. Keep it fun, humorous, don't offend anybody and don't spoil their appetite. So I really feel challenged by the presentation today. They gave me 10 blank pieces of paper. A yellow, a green, a blue and a red crayon and a couple pictures and told me to create a scrapbook of where we stand today on storage technology, highlighting a few perhaps high-level concepts.

 And before I get too excited walking through my scrapbook, I thought I would kind of highlight the -- some of the key takeaways from today. It's hard for me to stand up here, I'll forget what the messages are, so some of the things you'll here today, and you've heard today is we're on a journey toward 100% renewable energy. The entire globe is doing it, it's inevitable. One of the things I thought about is Abengoa, when you look at their core competencies, there is probably no better joint venture partner to take -- participate in that journey with. Technology is going to solve our problem but no one technology solves all of our challenges. If you ask me, is battery storage economical, I would say, yes. If you ask me, is battery storage the answer to our problems, my answer is probably no, and we'll talk about some of those highlights today. The other big thing is our customers have choices. If we don't provide the solution, they can go to someone else who does. The grid doesn't disappear, it just has to get a lot smarter so we can orchestrate all these solutions to work to the optimum benefit of the customers.

 So let's see some of the things we're going to cover in the next 30 minutes: one, you're going to have to give me some latitude today, because we're going to take some extreme dreams. What's the world going to be like with a 100% renewable energy? And we're going to make our world a small little case study in California with some very discerning unique customers. We're going to have a little high-level review on energy storage technology and I'll take you through a tour of a concentrating solar plant. It's going to be the Solana plant that Abengoa built in Arizona.

 Before I talk too much, I wanted to talk to you -- present a little bit about my personal journey of trying to get 100% renewable energy in my home. And I think you'll take from this some very interesting parallels that we faced trying to solve this for our customers. But about 9 years ago, my wife and I moved to the Boston area. So we lived in New England. I wanted to -- I've always been conscious about the environment and conservation, so I wanted to look at how I lower my carbon footprint, how I become a better citizen. And I looked at the utility information, and for about 150% of the cost of my normal energy, I could have 100% renewable energy, and I didn't think that was a very good idea at the time.

 So we went the alternative route. We first looked for solar rooftop. Well, it didn't work in my neighborhood because we have this thing called the maple tree. And we weren't about to cut them down, so that didn't work, even though every week, I was getting a call from a solar provider to put on solar panels to my house. So we went to conservation. We turned down the thermostat. We turned it down quite a bit. It's -- We got used to the cold because it has a technology with variable frequency drive with heat pumps. So it keeps a constant cold temperature instead of a cold and a hot. So we got used to it. We went to demand reduction, we went to LED lights, they were $20 to $30 apiece, instead of $2 to $3 but, hey, it seemed to make sense. For every dollar I spent, I got about $5 back. We finally got retail choice, so I was able to switch from Eversource to an alternative supplier that was cheaper, and it all happened one day when we noticed our bill, we went from about $0.11 with a couple years ago, we had that real, real bad spell of high gas prices, and for 6 months, I got stuck with $0.22 electricity.

 So that prompted me to go to retail choice. I'm sure all of you have Fitbits. Some of you may have a Nest device in your house. Let me see, I forgot to open this up, but in the U.S., we have this little thing called cent, and I put -- I used to have a kilowatt-hour monitor on my house. This one does it real time, so I can see what's going on in my house and with my Fitbit, I run up and down the stairs and turn off lights and find out which circle I'm affecting. The interesting thing about this technology is this, it's doing things in milliseconds instead of in the day, and it can actually detect what device is operating. So if you have 2 refrigerators, it'll figure out it's a refrigerator by its fingerprint of its startup.

 After about a month of it figuring out what loads I have, it said, gee, we have 3 refrigerators, so I looked at my wife and said "Well, this thing doesn't work, it says we have 3 refrigerators." I said, "We only have 2 refrigerators," she said, "Charlie, we have 3 refrigerators.'' I forgot, I had bought a little refrigerator for our pet food. The other thing it can do is it can see the changing fingerprint of the startup of a motor or your furnace. So if your furnace is malfunctioning, they can give you a call eventually and say "Hey, your igniter is coming on 4 or 5 times, instead of 1, you have a furnace problem." So it'll help you keep track of your house a lot better.

 So we became very conscious of our energy usage. And then we have this thing called Community Solar, so I got a call one day from the solar guys again, and I said, "Gee, for the 12th time, I can't put a solar panel on." They said, "No, we got this new program called Community Solar. We'll build the panels down on Cape Cod. It's going to be virtual net meeting -- metering, so you'll get the credit for your solar generation for your part of the farm." Made sense to me. I hopped over on the National Renewable Energy Lab website, kind of modeled it out. I talked them into giving me the most solar I could get for my historical use, about 90% of my energy.

 That's when the journey turned south. The company that had sold me the lease is a very well-known company, their customer service was lousy. The first month went by, I never heard from them, I called them back, "Who are you?" I said, "Well, I'm Charlie, I signed that lease you know about." "I don't know who you are." So perhaps customer service is really important if we're going to play a role in that.

 I never told them who I was and what I did, and it's probably a good thing because there's probably some recordings that were for training purposes that if they knew who I were, and Ian know what I said to them, I probably wouldn't be working today. All suddenly, I went and put a small battery in my house, not so much for energy storage, but for reliability when I'm traveling a lot. Those instantaneous times the lights go out and all the clocks have to be reset, my wife doesn't have to work about it -- worry about it. Or if the lights do go out when we have a big blizzard in New England, it gets me an hour or 2 to get the generator out and plug it in.

 So anyway, that's been my journey and we just got, after 3 years, the firm finally got up. We got our first bill, and I was wondering how well I made my decisions. So let's look at the outcome. The first thing that you'll notice and I get these notices every month, how I'm doing compared to my neighbors. And I always get these alarms saying, you're using 20% more energy than your neighbors. Well, none of my neighbors live there. It's a summer place. So we're doing really good on our energy. Our overall consumption has gone down about 50%, even though I'm heating my house with a heat pump now, instead of using oil. But my profile switched from summer air conditioner to a winter peak. Let's see, what else can I tell you about that? That's probably been the outcome there.

 Energy supply and delivery. Well, my supply is less than my delivery now, and that's based -- this was -- been the supply, if I was using my retail choice of supplier, and that's sits about $105 a megawatt hour. Still pretty high. So if I was able to deliver somebody, let's say, 6 set renewable energy, a 100% of the time, to me, that's not too bad. In the wintertime, that number goes up to a much higher because natural gas prices spike in New England up to $20 a dekatherm, and all of a sudden that doubles in price. My score lease is fixed to $111 for 20 years, so we're kind of gold. My very first bill, I ended up with $178 credit, and that credit, since it's virtual net metering, I get to carry to pay for these peaks in the wintertime. So we're really good and it's probably if there's anything I've learned about this lesson is I probably went too far on energy conservation, I plan on turning up my thermostat a couple degrees.

 So let's think -- let's move on a little bit. Innovation occurs when someone asks some really bold questions. Think about Tesla. Think about Ford. Think about Edison, Gates, Jobs, Kennedy and the Moonshot, King, as we heard before. Probably not for most of you, but for me, even though I might act like a teenager, look at my hair. I was born during the era of coal, 1955. So you've seen the heydays of coal of, perhaps, the '50s and the '60s. I started my career in nuclear power, so the '70s and '80s, we saw the advent of nuclear power. When I was in college, you weren't allowed to create electricity with natural gas under Jimmy Carter, it was against law. Natural gas was for the home. Well, then in the '90s and 2000, we saw the gas turbine, which was the invention of World War II, finally get to be efficient and economic so it could become baseload power during that -- the last decade of the century and then the first decade. And now we see solar and wind and perhaps, by 2030, it's going to be the decades of storage.

 So let's get started with a really audacious question. How can we achieve 100% renewable energy generation? This was posed by a customer of ours, and let me rephrase the question. "I want clean, renewable energy today. Can you provide it for me?" And that's a very different question. So we're going to take this to the extreme, not by a city who just goes out and buy renewable energy credits or if the generation I have for the year equals the demand I have for a year, but every kilowatt a customer wants when they turn the switch on is 100% renewable energy all the time. That is a real challenge in question.

 So the challenge is balancing that intermittency of wind and solar to make sure it -- the profile looked just like the demand. So we don't overbuild wind and overbuild solar and then curtail them to maybe 20% of their capacity or elsewhere. The answer, additional low-cost storage. We're talking about $0.45 a day unsubsidized. How do we shape that profile without turning that $0.45 into $1.50, as you'll see where the most competitive supply of storage today.

 So let's begin looking at the opportunities ahead. Our long-term planning, historically, utility would look at the future needs, look at what they have done before, add on some money for inflation, throw in contingency and build more capacity. And today, our model is quite different. The cost of generation 5 years from now might be 50% less than it is today. So we have to have relations with technology providers who will provide us price certainty so when we begin our permitting and our regulatory process and we finish our execution, perhaps 5 or 6 or 7 years from now, we're taking a really good gamble on the best choice out there.

 And it's going to require more than just building more units. We have to have storage, we have to have information technology, we have to have batteries, we have to have something else. So we have to look at all the mixes we have to do well in advance in order to get through this process and then deliver it to the customer. And yet, the customer wants the answer right now. We have to continuously balance that generation against their demand, so we don't have any excess and we especially don't have any shortfall. You can imagine if we built a facility and all we had is wind and solar and we got the mix just right. And then one night, the wind just stopped blowing, what would we do? And perhaps, more challenging to that, what do we do for black start? If we lose the grid and we have to bootstrap it backed up? Interesting challenges.

 Continuously, we have to balance things in seconds. And we do that now and we'll show that batteries and the flywheels do this really good and really economically. They don't necessarily do this affordable or economical. So let's move on. I'm going to go through a pretty high-level comparison of storage technology, and perhaps, contrary to a lot of news you hear, batteries aren't necessarily that economical. But let's talk about it a little bit.

 I threw lead-acid batteries on here because of the maturity of them in years. And I remember, as a kid, driving to the dairy, we lived near Campbell, Florida, and we went by this old factory and I was always told that, that was a battery factory. So I knew lead-acid batteries have been around for a while. In fact, I found my grandfather's registration. I never knew him, I found his registration for World War I, signed in 1917, 100 years ago today. And he was employed by a company called The Electric Storage Battery Company. He was -- not only was the technology the talk of the town in 1917 for energy storage, his trade was so critical he wasn't allowed to fight in World War II. They were probably developing the first hybrid diesel-electric submarine. One of the reasons lead-acid is so expensive, it has a limited life in cycles. If you charge it and discharge it about 1,000 times, this disposable has to go for recycling. And so that's why you see this very high-levelized cost of dollars per megawatt hour. If you just wanted a backup system in a micro grid to come on once a year, it would probably be the right choice.

 Lithium ion's only been around 30 years or 30, 40 years. It was first demonstrated at Stanford University. We're going to talk about Stanford 3 or 4 times today when it comes to energy storage. First demonstrated as a rechargeable battery, has taken about 30 years to get to its point to being competitive for some solutions. But even today, Stanford is working on a replacement, and the replacement won't be lithium, it's going to be sodium chloride. Basic sea salt or even urea, a very common fertilizer, why? Lithium is rare. And we need -- we'll probably never get another battery that performs like lithium ion, but we need -- its main competition is energy density. How much energy can I get in a kilogram, and how much energy can I get in a cubic meter? That's not important for energy storage. And we really don't have a recycling capability with a lithium ion, so 20 years from now, there's going to be an opportunity to do the same thing for lithium, if it can be done, as it was done for lead-acid. So we're not going to talk too much about lithium ion anymore.

 Sodium sulfur was a battery technology, it's about 40 years old. And it was a battery technology that could perform some of this bulk energy management we're talking about, but it's now been passed over by the capability of lithium ion. And Jeff talked about energy density. So energy density for the vehicle and the lithium ion price is really been driven down by vehicle technology. But I did some quick math, and if I took my Prius, about 129 horsepower and I took out the battery, I wanted to drive it with solar panels behind me on a bright sunny day, I had to pull a trailer of solar panels 100 meters long by about 5, 10 meters wide. Not very practical. So that's how much energy, and that's on a sunny day. At night, the Prius comes to a stop. That's why the battery serves the vehicle very well. You need to be light enough so you can drive at 300 miles and you need trunk space.

 Flow batteries is the new battery -- it's not a new battery, it's a fairly old battery, 100 -- over 100 years old. And it provides some promise because it's basically taking 2 electrolytes and when you need electricity, you pump them through. So it's really limited by the volume of electrolytes that you can pump through the battery. Pumped hydro is the tried-and-true solution today. It accounts for about 95%, 96% of storage and compressed air, in limited cases. The problem with pump hydro, it has to be located where there's a high reservoir and a low reservoir. The hydro technology we know is over 100 years old. The electrification of the world began 1895, right down here in Niagara. So not very different. So special sighting, perhaps, it might take 10 or more years to develop a site for pump hydro.

 Compressed air, there is a new variation of that coming out that GE, Siemens and others are working on. Basically, it's liquefaction technology just like LNG. You take air, turn it into liquid, store it in cryogenic tank, when you need it, you expand it. And they've been working on, basically, storing the cold that helps from the expansion, to help with the liquefaction and then storing the heat to help with the expansion. That technology should be very cost-effective against lithium ion today, and you can park it anywhere, so you can collocate it with your resource. The trouble is, it's in demonstration stages today, and who wants to take technology risk or commercial risk with something that hasn't been proven?

 Now we put something on here that people don't talk about a lot that we've been talking about in our office quite a bit and that's thermal salt. So we're going to talk about it integration with a concentrating solar project and why the costs are so cheap and why it might provide a solution going forward. And you're going to find some interesting parallels that other people think so as well. Before we get too far, we wanted to talk a little bit about concentrating solar and why it's a little bit different than photovoltaic. Concentrating solar, we're taking this low-intensity solar radiation coming down and turning it into high temperature, high-intensity energy and driving a traditional steam turbine.

 So the power block of a concentrating solar plant is exactly like the steam turbine at our Riverton Station in Kansas, in the Midwest. And the photovoltaic side, we're just converting the light or the photons to DC and then converting it into an inverter. The thermal storage cost integrated in the concentrating solar power plant is only about $50 a megawatt hour, which is about 1/3 the cost of pump hydro, the most economical storage today. If I took a battery and parked it on a photovoltaic, it's going to be more like $300 a megawatt hour. Really doesn't solve the bulk storage issue.

 The output of concentrating solar doesn't really degrade over years. In fact, there are a number of the -- you probably heard of a SEGS plant, the Solar Electrical Generating Stations in California, there are 9 of them. Many of them were built at 30-megawatt capacity. They're past their PPA of 20 years. Many of them today are running at 40 megawatts. The overall efficiency from solar radiation to electricity on a concentrating plant is about 40%, the efficiency of a photovoltaic is about 18% to 28%. Concentrating solar is usually large-scale to get the economy of scale, we're talking about 100 megawatts, photovoltaic, you can put on your roof.

 Give you a brief description of how the concentrating solar plant works. Let me get my little light. We'll talk about the solar field or the energy source. In this case, it's parabolic mirrors. There's about 4 different kinds of technology. Abengoa has kind of dabbled in all 4 of them. One of them is a parabolic trough, so it's just a curved mirror to focus on the collector. You saw the picture before or the previous slide of the power tower, so then you have a heliostat surrounding a big tower shooting up at the top. You've seen pictures of that with the top looks like it's glowing. There's a, perhaps, a bowl that focuses the power on a Stirling engine, and then there's another basic variation of this trough-type technology.

 So a fluid, in this case, it's going to be an intermediate fluid, it's an oil, we'll call it, passes through the collectors, through a tube, through the middle, and you'll see later on the parabolic trough shines the light onto the tube, heats it up to about 740 degrees Fahrenheit, or 400 degrees centigrade. It's limited if I cook it, it will ruin it. So I'm kind of limited to 400 degree C, and you'll understand that point later. And then that fluid goes back through a heat exchanger to make steam and then drives a traditional steam turbine. Solana is a little bit different than the Mojave plant. It has this molten salt battery, if you will. So excess energy can now be stored in hot salt. It can happen if I have excess panels here, or if my steam turbine's down, I can store that energy. It makes hot salt.

 At the end of the day, that hot salt is pumped through a cold tank. The cold tank being about 550 degrees, so it's pretty cold. That's about 300 degrees centigrade. And then I heat this, heat transfer fluid back to the steam generator, it makes steam until it's all over. The real critical thing about this battery, and you'll hear them talk about its freeze protection. But freeze protection isn't 0 degrees. Freeze protection is 500 degrees. The salt turns solid again at about 450 degrees, or about 230 degrees centigrade. So a lot of insulated pipes, a lot of large, either electric or gas-fired heat exchangers that keep that molten salt above it. But if everything shut down, and you didn't do anything else, this hot tank might lose 1 degree per day. And at 750 degrees, you got a lot of days of hot storage there to keep it from freezing.

 As I indicated, I got really excited when we first started looking at Atlantica. Probably, because I get a chance to go to Mexico and go to Arizona and see some of these sites. But when I came back up I'd already made up my mind from what I've seen that they had a very reliable, robust technology. They were really good engineers. They built things that I had never seen before even on switchgear. And so I came back not worrying about the technical problems they may have experienced. My excitement was the potential for the future. And when the executives started talking about Abengoa is a joint venture partner, that's when my excitement really got up, because I don't think we would ever be able -- I'd never be able to perhaps participate in the last, perhaps, decade or 2 of my career, and some of the things that we're going to be able to see in the next 20 years.

 And I wanted to show you some of the technical strength that Abengoa brings as both a research and development partner and as a technical executor of building plants. This is one of their facilities. This was about 2,500 acres in Spain. Collocated on it are some of the commercial facilities owned by Atlantica. But still remaining, I wanted to show you, the depth of their research and development capabilities. And if you looked at their concentrated solar power experience, over 30% of the world's installed capacity. They really are a world leader. And they have been, perhaps, all the work they had done to date can be a -- could be the reason that concentrating solar power might get as low as perhaps $0.06 a kilowatt unsubsidized.

 Of that, perhaps, 1,600 megawatts in operation, 1,400 megawatts are owned by Atlantica, so we have a share in it and they have another 360 under construction. It took me a while to find it, they have 167 patents on solar, including storage technology. And when you start playing in the technology field, IP is everything. There are things that you can do technically, but you can't do commercially because somebody else hasn't given you the license to operate, and you have to pay them a big royalty. That could give us a big step ahead of anyone else perhaps competing in this area. The research and development facilities are there. And you can see, there's numerous ones. They have, actually, you'll see here, this is PS-20, which we didn't list here, and then the PS-10. These were the first, and you can see it's a power tower type with the heliostat here focusing on it. The world's first and second power tower facilities. They're only 20 megawatts and 10 megawatts or 11 megawatts, and you can see here, this was their little 1-megawatt pilot. Very first in the world.

 Let's see here. There's a little storage pilot here, so before they went out and built Solana, they actually tested the concept of salt in the tanks, the heat exchange and the freeze protection. So it de-risked the technology. They built the first thermal storage project in the U.S. and Solana is the world's largest parabolic trough project in the world.

 And they're working on completing a project in Chile in the Atacama Desert. It's an interesting hybrid of concentrated solar, PV and battery, and it's over 100 megawatts of baseload solar energy.

 So let's take a little tour through the facility. You're probably not going to get as excited as I did. The one thing I noticed as I walked through the facility and saw nameplates is the manufacturer of all the equipment were the same people that I've grown up with. Foster Wheeler heat exchangers, Metso controls, Siemens steam turbine, identical to the one in Kansas, shot glass, and I'll show you a closer picture of the collector tube. But if you remember your days in chemistry or bio lab, if you look carefully at the beakers and the flasks, you can see a little shot. They're a specialty maker of glass in Germany, and they make the little -- the heart of the solar field, the collector tube.

 But a real quick walk. This is me standing on top of the thermal energy storage tanks looking out over the solar field. This is where steam is produced. So we have the heat transfer fluid going through a preheater, an evaporator and a super heater, just like a traditional boiler, and these are standard shell-and-tube type heat exchangers. What's unique about them is they're designed to operate with really high temperature gradients. Starting them up fast and starting -- and hitting them with perhaps 700-degree molten salt, our heat transfer fluid can cause some damage. So a lot of work goes into engineering the heat exchangers.

 The steam turbine we've all seen. I wanted to show the control room. And in this case, they have 4 people watching the solar field and the power block all at the same time. So controls are really critical. If we had a battery, we wouldn't necessarily have a control room. So that's one of the differences we see here.

 Getting out into the solar field, some interesting notes here. Here's the big mirror, and you can imagine me, I was a science guy. When I was about 10 years old, I went chasing ants with a little magnifying glass. You can imagine how big of an ant I could have killed with that mirror. You can see this little tube right down the center lines. So this mirror is shaped to focus all that energy right along the centerline of a tiny little tube about this big, and you see it looks like a neon light. And it's interesting, they kind of control the output temperature of each row of these parabolic mirrors and the entire field by just tilting this maybe a fraction degree out of the sun's path so that, that focal point isn't right on that -- the bottom of that tube.

 Here's a look at the tube. It's concentric glass tubes. Kind of interesting, the inside tube gets up to 750 degrees, but you can actually go out there and touch the outside of the tube. It's insulated with a vacuum. So you can see the little glass nipple where they pull the vacuum and the seal. It melted it and sealed it. It even has a leak detector. So if for some reason this little seal fails here, it'll let you know that you have a leak, and then you need to go out there and change this tube. If the inside of the tube is at 750, it's growing at a different rate than the outside. So they had to figure out how to allow it to expand. So you can see a little bellows, but this tube is attached to this end cap, and it has to grow at the same thermal expansion as the glass. If not, it'll break the glass. So they figured that out.

 So it's pretty remarkable. These aren't just used in concentrating solar projects you see making electricity. You'll see these a lot on solar thermal projects on roofs, vacuum tube just like this, and then tanks down in the basement that are full of pebbles or rocks. And on hot summer days, it heats those 3,000 gallons of water rocks. And then if you lose, a blizzard comes in, you've got nice, warm, steady energy the whole time.

 And I saw that back in the '80s. So it's not new technology, and I just showed a picture. This is the graph. This is actually the computer screen. This is a big screen up on our TV so that you can keep track of every one of the rows of these, which ones are in the sun and which ones are out and which are -- little red ones are taken out of service, perhaps changed or broken glass or whatever.

 So let's move on to really the -- oh, I forgot. The cleaning of the mirrors. To keep this at peak performance, you've got to clean the mirrors. And there's a crew of 7 people at Solana who work every night, and it takes them 2 weeks to go from one end of the facility to the other with this truck, and the truck is set up with a robotic arm and has got position detectors. So you just drive the truck along these mirrors, and it misses all the obstructions and even washes the collector tube at the exact same time. So to me, that was interesting.

 So next, let's move on into the thermal storage a little bit, and here's where we're going to learn a lot about how technology is advancing. As Ian indicated, this is about 1,400-megawatt hours of storage, which is over 1 gigawatt. That's a lot of storage. There are 6 pairs of tanks, hot tank and cold tank as we described before going from about 400 degrees to 290 degrees. Each tank is about, let's see, in our terms up here 30 meters wide, 10 meters high. It'll make a lot of sense, it takes up about 8 acres.

 What are the applications that we see for this? Well, new concentrating solar projects. Yes, they may not be at $45 a megawatt hour, but when you take into account the advantage of being able to shape that generation for the demand, it's more economical than any other combination of solution. Retrofitting existing facilities, some of the projects in Spain when you go there, there is a big area right in the middle of the facility left wide open. It was meant to be the addition of the storage facility. So it can be retrofitted quite easily, stand-alone grid scale storages as Armando had indicated.

 And one of the -- we'll see one of the improvements that can be made on this energy storage is getting away from that intermediate fluid that's limited to about 740 degrees. This salt can operate up to 1,050 degrees. So if that's the heat transfer fluid, I could get rid of 4 pairs of tanks, and now I'm down to 2 tanks, and that's for Solana.

 To give you an idea of scale, 100-megawatt concentrating solar plant with 10 hours of storage could be done in 1 pair of tanks perhaps not much bigger than this. That's 1 gigawatt of storage for about $50 million. The equivalent lithium ion battery would cost about $350 million. So hopefully, that puts some of the economics quite clear to see. In other words, that's 100-megawatt hours per meter of salt. I'll give you another little key metric on why you save so much money on this. A ton of salt is $1,100 a ton. That's 125,000 metric tons. That's almost $140 million worth of salt, half the cost of this storage system. So when you're able to go down to one tank, you're not only saving tank cost, you're saving a lot of money in the salt.

 And we'll see on the next slide here with advanced materials, if they can go much higher than 1,050 with a variation in the salt or something else, then that means more energy density, more savings. One of the thermal storage technologies that's recently been announced, it's a company going public. It's a company called 1414 out of Australia. They're using molten silicone as their storage medium at 1,414 degrees centigrade. So you can imagine the significant changes of energy of that molten silicone. And I think they're probably taking into account, not just the sensible heat, not the temperature rise but the latent heat of switching from molten to solid. So really high energy density in the future of thermal storage.

 Tank design, moving from a 2-tank system to a 1-tank system or a thermal clients so the hot's in the top and the cold's in the bottom. Turbine generator technology, getting away from the traditional water-based steam turbine to something like supercritical CO2. Not only can they automate it, but it's much more efficient than a steam turbine. So the best steam turbine we can build today is only about 50%, and that's why the overall efficiency of this plant is about 40%. Everybody asked me about this solar efficiency. They're actually capturing about 95% of the solar energy in those parabolic troughs. It's really incredible.

 One of the things I or you can see in the -- as we see the price decline here, Solana was built when the price was approximately $210 a megawatt hour, pretty high. But 2030 or maybe even sooner, the DOE SunShot target is $60 a megawatt hour. That's pretty cost competitive when we compare wind and solar to pump hydro, the most economical storage solution out there.

 I bring up this last point, Alphabet. Alphabet is the parent company of Google. Google wants 100% renewable energy, and they don't see the battery as the solution. So they formed this company called Project Malta. It's their Skunk Works project. It is a secret project. It took me about a month to find the science paper on this Brayton Battery cycle that they're working on. It was conceived by a researcher at Stanford University, of all places. I couldn't tell you what's in the paper. After reading it for about a day, it was like watching about 10 seasons of The Big Bang Theory, but there are some pictures in it, and I kind of got the gist of it. It's a heat pump technology between molten salt and a cryogen tank, and it looked pretty much like a gas turbine, which was the Brayton cycle, therefore, the Brayton Battery.

 Project Malta, Ian indicated before the why. So Google set up Project Malta not just to solve energy storage. Their mission is to identify issues that the salt would affect the -- positively the life of millions, if not billions of people. And their model is to raise bold questions, identify a problem, look for a technology that exists today. That gives them hope that there's going to be a solution in the near future and then work like a start-up entrepreneurial company and try to commercialize that technology in years instead of decades. I guess up to that last point, it kind of sounded like what we're doing. And so I thought that was quite interesting that somebody else is working on the thermal technology just like we would like to look at.

 So let's look at the challenge that we face. This is, again, give me latitude. We're going to take the extreme case that we have customers who are living around this beautiful shore of Lake Tahoe. It's geographically in California, so that's the regulators we deal with but connected electrically to Nevada. It's tucked away in a pristine area. They have a winter peak. The biggest peak are the weeks of the Christmas holidays when everybody goes there to ski. It's very sensitive geography and very discerning, environmentally conscious consumers. California is on the road to 50% renewable perhaps in 2040. Hawaii is on the road to 100% renewables in 2040. These consumers want 100% renewable today.

 I wanted to provide you a little bit of background on the unique challenges if we looked at the CalPeco consumer as an island. And you can see they have a low of maybe about 38 megawatts of demand, up to a high of 140. Most of them in this last month of December, really concentrated in the last week of December. If we were to go to build a -- well, we've -- if we had a capacity factor of 40, we might have to build a 300- or 400-megawatt wind project predominantly at night and then during the day, there wouldn't be enough to power the utility when the wind stopped blowing between about 10:00 in the morning till 3 in the afternoon. If we build a solar project, well, it comes on at about 9 in the morning, and it turns off about 7 at night. So that doesn't solve the solution.

 We have very limited space or rooftops around that lake to put in solar either on rooftops as community solar or whatnot. There's really not much industrial area at all. Scale is really a challenge. We're only looking at perhaps 585 gigawatt hours. That's a drop in the bucket for most utilities. So we have to build something at an economy of scale that we can somehow control and manage to their demand. And lastly, you can't do it at any cost. It has to be competitive because if we don't do it, they'll go to someone who will do it at a different price point.

 So let's look at a -- this is a very audacious scenario, and it's not a representation of solution, it's a representation of the challenge we'll face. But what we did is we took Luning and Turquoise, and I modeled it in some NREL software to find out what it would do every month and what it would do it in the year. And I hypothesized a stand-alone 50-megawatt wind project somewhere in California that kind of looked like California load. And then we superimposed 100-megawatt concentrating solar project because right down the road in Carson City, a really high solar radiation desert, perfect for us. We wouldn't put it in our facility in our location because we might get 30 feet of snow. We're local. So we'll try and do that.

 So if I took the typical winter day, and what this is showing, this green is a combination of wind and solar supply. And wouldn't you know it? I picked January 7 out of the clear blue sky, and July 7 out of the clear blue sky as typical winter and summer days, and no, the wind wasn't blowing at night that day. So I need enough, and the blue line is taking this 100-megawatt concentrating solar project with only 4 hours of storage. And what it's doing is filling the gap between the green supply, and then you can see the yellow and the blue. That's the demand and the total supply. I got them close to each other, and so if I add this to this, I get that.

 So in a very simplistic way, that would solve the winter problems. The worst case, I'd always be able to supply 100% renewable energy at a cost of $70, which isn't so bad. But then you look at summer. And summer, their demand is low, and now the solar resource is up, and I've got all of this excess of about 150 gigawatts that I have do something with, which highlights the importance that we still need this grid. I need to be able to -- whoever has this facility, whether it's us or someone else or NV, they had to use this in the market, perhaps Las Vegas.

 I threw out a question last night during a practice, maybe it's not Las Vegas. Maybe we find another audacious entrepreneur who built a gigawatt factory in Nevada, and we show them how cheap this nighttime solar is. Maybe he'll sign a corporate PPA, but anyway, you can see it's getting us down to a price that's pretty reasonable. Compare that against my $1.05 during the summer in the Boston area, this isn't too bad.

 But what we can't do is forget all the other things we have to do from here. We have to get down to the second and the minute and the hour of energy use and balance those fluctuations and the variations we see from the supply and the demand. We have to get the right mix of wind and solar and storage and other renewable technology, so we can most economically match supply and demand.

 We need not only the grid, but we need a really smart grid. We have to orchestrate not 2- or 3-generation resources, perhaps thousands if we're counting upon all those vehicles being in garages in the future. So really, really smart -- that's a Trump point, isn't it? A really smart grid and fast, realtime balancing.

 I guess, in closing, I'm going to leave you with this thought. And as Ian indicated, it's really about understanding the why. The question that the consumer pose is an important one. It -- first, it seems like something that's possible in the future. But in fact, it's something that's quite possible within our visual horizon. The reason why it's such a good question is we need to learn from it, and the lesson we need to learn is we need to be back to our customers telling them how we're going to do this in a reasonable amount of time for a reasonable price. Why? Because they have a choice. If they don't get the answer from us, they will get the answer from someone else.

 And with that, I'll leave you to enjoy the remaining part of your meal. I hope to see you next week, and thanks for your attention.




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