Algonquin Power & Utilities Corp Corporate Investor Morning
Nov 25, 2014 AM EST
AQN.TO - Algonquin Power & Utilities Corp
Algonquin Power & Utilities Corp Corporate Investor Morning
Nov 25, 2014 / 01:30PM GMT
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Corporate Participants
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* Kelly Castledine
Algonquin Power & Utilities Corp. - Director of IR
* George Trisic
Algonquin Power & Utilities Corp. - SVP of Business Services
* Ian Robertson
Algonquin Power & Utilities Corp. - CEO
* Chris Jarratt
Algonquin Power & Utilities Corp. - Vice Chair
* David Bronicheski
Algonquin Power & Utilities Corp. - CFO
* Mike Snow
Algonquin Power Company - President
* Jeff Norman
Algonquin Power & Utilities Corp. - VP of Business Development
* Todd Mooney
Algonquin Power & Utilities Corp. - VP, Finance and Administration
* David Pasieka
Algonquin Power & Utilities Corp. - President of Distribution
* Peter Eichler
Algonquin Power & Utilities Corp. - Director of Strategic Initiatives
* Gerald Tremblay
Algonquin Power & Utilities Corp. - VP Finance & Administration
* Dick Leehr
Algonquin Power & Utilities Corp. - President of Pipelines and Transmission
* Charlie Ashman
Algonquin Power & Utilities Corp. - VP, Technology
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Conference Call Participants
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* Rupert Merer
National Bank Financial - Analyst
* Nelson Ng
RBC Capital Markets - Analyst
* Matthew Akman
Scotiabank - Analyst
* Sean Steuart
TD Securities - Analyst
* Ben Pham
BMO Capital Markets - Analyst
* Mac Whale
Cormark Securities - Analyst
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Presentation
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [1]
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Good morning, everyone. Welcome to our fifth annual Investor Day here at St. Andrew's in Toronto. It's nice to see a sea of familiar faces. But for those who don't know me, I'm Kelly Castledine, the Director of Investor Relations for Algonquin. In addition to the live audience here we also have people participating online over the web. And to those people, just for your information, anyone listening online can ask a question if they like through the chat feature in the webcast software.
So our structure for today -- we're going to start with an executive panel. Most of you know Ian, Chris, and David up here. We will do a little brief introduction of them in a moment. We are going to start -- following them were going to have generation panel, where our generation folks will get up and do some presentations on their business. And then we will take a quick break and then we will get back in with distribution and transmission groups that will present their information for you today. Over lunch we have Charlie Ashman with us. He's going to do a presentation on energy storage as well.
So there's a couple of things I wanted to do right before we get going. We have a few of our board members in the audience. So I'll just ask that you stand up or turn around; put your hand up. We have George Steeves; there he is in the back corner there. We have Chris Ball, right there right there; and Ken Moore, also in the back.
So right before we get started, I know many of you have been to our Investor Day before and have experienced our safety moment. It's part of our safety culture, and we are always driving to zero accidents in our business. And part of this is by doing a safety moment, which is where somebody -- any time we have a meeting with five or more people we do a safety moment where someone volunteers or is chosen to describe an incident where safety was an issue, basically to pass on learnings. So, I'm not going to pick on anybody in the audience and put them on the spot. But we do have George Trisic here -- he's our Senior VP of Shared Services -- to offer the safety moment today.
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George Trisic, Algonquin Power & Utilities Corp. - SVP of Business Services [2]
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Thanks, Kelly. For the safety moment this morning what I thought I'd do is share with you a safety moment or a bit of a vignette that's relevancy what we're up to this morning. And that is we're all in a venue that we are not familiar with and attending an event in a venue that we are not familiar with. Now, most days you are in your office or in your home and you are in the facility that you are familiar with or you've had to go through a few fire drills, so you know exactly what to do if the alarm bell goes off.
This morning, though, I'd venture that if the fire alarm went off in the next five seconds most of you would have a perplexed look on your face. Half of you would head to the elevators, and we know that's not a good idea because they won't be working. The other half of you might just follow the crowd because you don't know what else to do. And if a lot of you are in the investment business, I know that in times of panic you know that it's not good advice to follow the crowd.
So part one of this safety moment is I'm going to equip you with the information you need in case that alarm bell goes off so that you can make an informed decision. And that is to point out to you the two egress routes that you need to be aware of in that situation. So the first one is here to my left and to your right. Just behind that curtain there's an exit sign. And if you hear the alarm bell you can go out through that door across the hallway and straight down the fire exit stairs. If that's jammed up or you can't get past that stage or Ian is in the way blocking the path because he's running --
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [3]
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Well, I'll be out there first. Don't you worry about that.
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George Trisic, Algonquin Power & Utilities Corp. - SVP of Business Services [4]
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-- If you get there first, reverse that you can go out this backdoor, hang a left, go back across the elevator lobby to the front desk and turn right. And if you look down the hall there, you'll see the other emergency exit. So that's part one.
Part two is just to take away from this moment that next time you are at a conference or an event, take those few minutes or a few seconds to just be aware of for those emergency exits are so you don't have to follow the crowd. Thank you.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [5]
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Thanks, George. I think we all feel a little safer now, knowing where we are going.
So we are going to get started with our executive panel. I'll start with a brief bio for each of our executives, although most of you know them. Ian Robertson is our CEO, in the middle there. He was a founder of Algonquin back in 1988. He has more than 25 years of experience in development, financing, acquisition, and operating electrical power generation and utilities. He is an electrical engineer himself, holds an MBA, a CFA, a Chartered Director designation. And if that's not quite enough, he's currently pursuing his Masters of law at U of T.
David Bronicheski is the Chief Financial Officer for Algonquin. He joined us back in 2007. He has over 26 years of senior management experience including 14 years in the cable television and telecom industries. He's had various senior management and finance positions including CFO of a publicly traded telephone, cable, and Internet service provider. He has a Bachelor of Commerce degree, an MBA, and is a CPA.
And to my immediate left we have Chris Jarratt. He was appointed Vice Chair of Algonquin Power back in 2009 and was also, like Ian, a founder of Algonquin back in 1988. He has over 30 years of experience in development, financing, acquisition, and operation of power generation and utility projects in North America. And he's a water resources engineer and has a Chartered Director's designation.
So, we will kick off the panel with Ian this morning. Ian, can you give us a quick summary of some of the big-picture objectives that the organization has on deck, to give a broad context of what we're going to talk about today and where the organization is going?
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [6]
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Sure, Kelly. And it's always helpful when you are going to get three hours or so of information bombarded at you to have a picture into which to -- a backdrop against which to put that information. And I always like to think, if we were standing in the elevator riding up to the 27th floor here today, what would I tell you in the 30 seconds that this organization is all about.
And so the big-picture plan then I'd say for the next midterm, three to five years, is that we want to continue to building our business as a trusted provider of natural gas, water, and electric services through a diversified portfolio of high-quality, long-lived utility assets. I get it that people -- as Kelly mentioned, this organization was formed back in the late 1980s as a developer of independent power assets. And that's basically our roots. And a lot of people still see us as that. But I'd say our self-image is probably more as a diversified generation, transmission, and utility company. And our vision includes being the most admired organization by our stakeholders, and that includes our investors and our communities and our customers, for our people, passion, and performance.
And the question, of course, is how is that admiration going to be earned? And we would like to think of it from a world-class safety record, environmental and community stewardship, our perception as an empathetic organization with our hearts in the communities that we serve. Specifically for our investors and the capital markets more broadly, we really want Algonquin to be viewed as a must-hold security and in the portfolio of every long-minded investor in, I guess, primarily North America but perhaps more broadly across the world.
And we acknowledge that this isn't going to happen -- none of it is going to happen without an engaged and empowered employee group. And therefore I guess our vision is for those people to see us as an employer of choice. And so there's, I guess, a little bit of background to our organization and what we are hoping to achieve with all the information that's going to be provided to you today.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [7]
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Great. Thanks, Ian. And Chris, I'll move on to you. Given Ian's summary of our big-picture objectives, can you shed some light on how the executive team and the Board approaches strategy, if that has evolved over the years, and what we may see going forward?
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Chris Jarratt, Algonquin Power & Utilities Corp. - Vice Chair [8]
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Sure, Kelly. Well, first off strategy is a process that is driven from the bottom up in our organization. It's corporate-wide and it actually starts with a process of the strengths, weaknesses, opportunities, and threats. And that is a process that is done through a wide range of management. And from there it moves up to the executive level, where we come up with a strategic plan. And from there it goes to the Board for endorsement.
A couple of the other things about it is that it's a rolling five-year plan. And it is updated annually. And so what you see are shifts, quite small, from year to year. And it's probably one of the most important things that we do in our Company. It's woven all through the rest of the Company. You see it in the growth that we pursue. You see it in the corporate scorecards that we are measured against. And you also see it in the management compensation. So it's something that you will see time and time again throughout the whole organization.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [9]
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Okay. So I'm going to continue with you, Chris. We have evolved our strategy, our approach to strategy, over the years. And our Company has changed quite a bit in other ways over this time frame. So from your perspective, what do you see as the biggest changes in the Company and what has had the most impact on where we are today?
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Chris Jarratt, Algonquin Power & Utilities Corp. - Vice Chair [10]
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Well, obviously, as the Company has been around for 25 years, there are lots of things -- massive changes that Ian and I have seen since day one, and some since David -- have come up several years ago. But maybe we can start with a couple things that probably haven't changed. You can see from the photo there my haircut is more or less the same. My mustache looks about the same. But there's an entrepreneurial spirit that I don't think it's changed and I hope it never does change. We have this attraction to long-lived bricks-and-mortar assets. I think we are a very creative bunch. And that creativity is applied to everything we do. And I guess modestly, I think we are a very strong development team, and we like to build stuff. And I think we are pretty good at it.
Now to get to your question, so what has changed, Ian's mustache has changed, thank God. But we have gone from about four employees to 1,500. And this maturation process is kind of natural, but it has been quite accelerated through our association with Emera. The changes that I see fall into a couple different buckets. The first one is the operational type things -- health and safety, environmental compliance, maintenance standards, and things like that. We also have financial changes that we've seen over the years. Internal audit is something that we have now that we never had before. Compensation plans are very -- are much more structured than they were several years ago.
We've also made quite a bit of change to our disclosure. And that you see in the MD&A that we put out on a quarterly basis and also in the management information circular. We strive to be as transparent as possible. And I guess the most recent change is we've made great strides in governance. Risk management is a big part of that. And we made some changes to our Board as well. So those are some of the changes that I've seen.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [11]
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Okay. Thanks, Chris. You may notice in the audience that we've structured the day around generation, just distribution and transportation business segments. So Ian, can you give us a little bit of color on why we are looking at presenting the information that way today versus typical how we have done it in the past where we do our Liberty Utilities section and our Algonquin Power company section?
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [12]
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Yes, certainly. And maybe the change looks subtle, maybe it doesn't. But I think at the very least the change is consistent with our self-image of the organization as a diversified generation, transmission, and utility company. I think the subtlety externally may be there. But I think there are a couple of important considerations. It does confirm the position of this organization across the entire utility value chain when you think of -- at least on the electrical side, that it starts with the generation and it ultimately ends with the light being switched on. And we really participate now across that entire value chain.
And it does make the extension of our business into the transmission sector -- it makes it formal. And I hope everyone had a chance to take note of the press release of our participation with a global leader, Kinder Morgan, in the Northeast Energy Direct Project. And so I think really, it's really consistent with that, if you will, broader positioning, though there are a couple of internal observations that I would make. And while perhaps most of you don't -- it's not really relevant from your perspective, I think it is important that we just highlight them.
I think, first, it allows APUC or Algonquin Power & Utilities Corp. to bring that entrepreneurial spirit that Chris talked about, really the founding emphasis that this organization has in terms of developing a project, allows it to export that out of the generation group, which is pretty much where it has been focused. And when you think of some of the projects that we have underway in what we have classically thought of Liberty Utilities, I think of our CalPeco solar project. Even this Northeast Energy Direct initiative with Kinder Morgan -- I think those are a couple of opportunities where that development expertise can serve the organization well, to the extent that we formalized that it be spread across.
And then the second thing is it does drive efficiencies. And we are in the business of pressing assets into public service. We are serving 0.5 million customers in water, gas, and electric space. And to the extent that we can do that efficiently, that value accrues to the benefit of our customers, which is obviously important. I think one of the things you will hear about today going forward from both our groups is the continued investment of capital. Well, that obviously has an impact on the rates for our customers. And to the extent that we can lower our costs by being more efficient, that helps offset the impact of that. And that's clearly where our focus is.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [13]
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Okay. Thanks, Ian. And with the addition of the transmission business line, I'm going to flip back to Chris a little bit more onto governance. We recently, this year, added two new Board members. In June, Masheed Saidi joined us. She was most recently the COO and Executive VP of US Transmission for National Grid USA. And then in October we had Dilek Samil join us, he was EVP and COO of NV Energy.
Chris, what do you have land for the boards from my governance perspective? Are there any changes that we can expect in the future?
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Chris Jarratt, Algonquin Power & Utilities Corp. - Vice Chair [14]
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Sure. I would say the major catalyst for the recent Board additions is that we have a strong belief that strong boards make better decisions. Obviously, the Board's key responsibilities are to ensure it's got the right skills, the right people, the right experience and quality. And part of how the Board has done this is by expanding the Board. And I should mention this process of expanding the Board -- while we've added two members fairly recently, we started it in 2010 with the addition of Chris Huskilson, who has been with us several years now.
And what this does is expands the skill sets that we have. We've strengthened the financial capability. We have brought on utility experience. We have also brought on transmission experience.
So, and I think the other thing that it also serves as I guess as boards take on more governance, the workload just grows and grows. And so having more people on the board allows that workload to be more adequately handled. One of the things we've done fairly well, I think, is we wanted to get our Board members up to speed and contributing as quickly as possible. So, we have pretty robust director orientation program that includes all the stuff you'd normally expect, the documentation; but it also includes a site visits, access to management, participation in the strategic plan, things like that. So, we think we bring Board members up to speed fairly quickly.
And I just want to touch on, too, on the diversity issue. And I think we believe as a Board that having a diverse board brings a much broader range of perspectives when making decisions. And so obviously our two newest Directors bring a US diversity to the Board as well as gender diversity.
And in terms of what's next, which I think was the end of your question, we're commencing a process with director succession that -- what that will likely lead to is that the director recruitment process will be an ongoing process. It's something that's very important for the sustainability of the Company.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [15]
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Okay. Thanks, Chris. And it was quite timely; The Globe and Mail published their Board Games annual publication just yesterday, I guess. And happily, Algonquin is showing an improving score, and I think it's largely due to a lot of these activities.
So on the governance themes, can you talk about some of the -- Chris, can you talk about some of the initiatives that you are working on and things we will see in the future?
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Chris Jarratt, Algonquin Power & Utilities Corp. - Vice Chair [16]
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Yes. No; I have already mentioned some of the changes we've made at the board level. But some of the other things we've done are a strong focus on risk management. It's been a priority of the Board. We've significantly enhanced the risk oversight process through having a dedicated risk management team as well as internal audit, as I mentioned earlier. And both these functions have high visibility at the Board. As a matter of fact, every board meeting we have, we have dedicated space for that.
Some of the other initiatives that we've done are focused on evolving the skills of the existing Directors and strengthening the board leadership through continuing education. Comprehensive board assessment processes is a big things that we've done fairly recently. It's a pretty robust process where we have enhanced all the questionnaires and the process that we go through. It's a very formal process and has been designed to enhance the quality of the feedback as well as make the process as constructive as possible.
The Board has also spent time making adjustments to agendas so that more time is dedicated to talking about strategic and business direction. We have a number of policies that have been implemented recently -- Director share ownership guidelines. We hold in-camera meetings at all committee and board meetings. So those are the types of things that we've done in the last little while to enhance that, Kelly.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [17]
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Okay. Thanks, Chris. Let's switch back to discussion of the business. And we'll switch to Ian again. Over the past three years or so we have publicly established targets for growth in the business and the ability to deliver shareholder value. How, from your perspective, have we fared against those targets?
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [18]
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Well, you are correct. We do make very public statements about a number of the metrics by which the organization gets measured, specifically growth in our assets and EBITDA and in the infrastructure business. I hope everybody in this room would agree that assets and EBITDA are really intricately linked. It's hard to get more out of a particular generating station or utility asset without taking more risk. And that's really not where our heads are at.
We look at earnings per share and cash flow per-share. We get it that everybody in this room owns this company one share at a time, and that's what counts. But really, it all comes down to total shareholder return. And we try to put sort of a threshold that feels right from our perspective in terms of the type of assets we've had.
But the tale of the tape is told by the numbers here. And I think we are pleased that as we sit here at this 10 seconds, looking back 12 months, the assets have grown significantly in excess of our 15% target. EBITDA is definitely up more than the target, almost double the target. Most importantly, and I know that we will talk about bit about dividends and what drives the dividends, but our earnings per share are up by 31%. In some respects this is a bit of a threshold year for this organization. We are crossing the threshold where our GAAP earnings are now exceeding our dividends. We will talk about the significance of that.
But lastly and I guess most importantly from our shareholders' perspective, the total shareholder return is definitely in the excess of the 10% target. And while we are unabashedly proud of what the organization has done over the short-term, I think it's clear that this is not a flash in the pan from our perspective, that the organization has been on the right track to deliver favorably against broader industry benchmarks. And you can see on the slide there as you think about a reasonable benchmark for how this organization might be measured, I like to think that we fared pretty well.
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO [19]
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I think just to add a bit to what Ian said, I think what is particularly impressive for me is that we've actually been able to achieve very impressive growth using relatively conservative building blocks, and that being regulated utilities and then long-term contract and power generation.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [20]
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Great. Thanks, David and Ian. David, I'm going to ask you a question now, in case you were feeling a little left out. We hear -- well, part of the success of the Company is based on good financial management, of course. And so one of the things we hear from a cost of capital perspective is the emergence of the US yield cos in the US energy space. From your perspective, how do you view the Company's ability compete the US yield cos and even perhaps some of our Canadian IPP peers?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO [21]
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Well, we are laser focused on our cost of capital because in the game that we are in, we are competing against other companies and cost of capital is everything. And we are, I think, very pleased with the fact that over the last several years we have consistently been able to lower our cost of capital in each of the last four years. So as we look at our cost of capital today, and we do compare ourselves against our peers both here in Canada and in the US, and I think based on our analysis our cost of capital is somewhere, depending on the model that you use and some of the assumptions, somewhere in the 5.5% to 6% range. And as we apply that same metric to our IPP peers here in Canada and even the US yield cos, we find that we are competitive and can compete with any of our peers here in Canada or in the US as well.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [22]
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Thanks, David. Ian, you just were talking about our performance targets. And I wonder if you could comment on as we grow how you view our ability to continue with the current growth trajectory.
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [23]
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There's no doubt about it. As the organization gets larger, I'll say the bar gets heavier. We understand that one needs to lift the entire bar and every time one undertakes a development project you think about it in the context on a fully diluted basis or as a percentage of our total assets.
But I think we are comfortable and I am hoping the conclusion of everybody in this room in the next 2 1/2 hours is that as you look forward at the pipeline of identified and I'll say secured opportunities that we have for growth over the next we'll call it midterm, three to five years, that these growth targets that you saw in the previous slide are both achievable and realistic. And there's a couple of charts there on the screen that really forms the basis for this assertion. So let me give you a couple of observations from them.
First, if you look at the asset chart, the upper chart on there, I hope you conclude that with those opportunities that we have in front of us over the next three to five years, asset growth is going to continue to be robust. You're going to hear more today about our near-term identified pipeline, over CAD2.5 billion worth of growth opportunities right on the fairway from our perspective, CAD800 million of them in the really near-term, I mean in the next 12 months. And so when we complete the work that we have in front of us, this organization is going to be cresting CAD6 billion in total assets. And I know that doesn't make us large by some measures. But I think when you think of the -- that we are just headed for CAD4 billion today it really does feel significant.
And I will mention that that growth is without taking into account any further success of the business development group. So Jeff, you can head home; we don't need you anymore. And we will save his salary, which will make the EBITDA even higher. But I think, given the history of this organization and given the entrepreneurial spirit which is alive and well, that probably feels like a pessimistic assumption.
The second one is growth in EBITDA, I would like to think, is profound as well going forward. Compared to the CAD285 million that we are trending in for 2014, and there's 4 1/2 or five weeks left of the year, I think the CAD580 million in EBITDA which the current growth initiatives are really targeting at delivering in 2018 feels like a CAGR over four years of 18%. And that's against our target of 15%. So that feels like the pipeline is going to be able to deliver against the objectives that we are publicly setting.
And lastly, the observation I'll make -- and people always ask us, well, tell us about the split between your generation and distribution business. And I would like to think that if, again, you look at the chart on either an asset or an EBITDA basis, that generation and transmission are going to continue to grow in reasonable lockstep with the whole transmission group starting to gain scale. And so I'd say, specifically responsive to Kelly's question, when you look at those publicly identified targets in the previous graph, the current pipeline of existing initiative seems to be sufficient to continue to satisfy that commitment, certainly over the near to midterm.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [24]
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Thanks, Ian. And a growing company often means growing costs. So David, we saw our G&A costs rise. In particular, there's a bit of a bump in 2014. Can you provide an overview on why that happened and what we can expect in the future?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO [25]
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Well, there's no doubt that a company that's growing as fast as ours needs to make sure that its support services are really keeping up, that really we are tooling the machine appropriately for the growth that we have before us. And it really started back a little bit before 2012, but 2012 in particular was a real year of inflection for us. That was the year, as many of you will recall, we were planning for the transition to bring Granite State, EnergyNorth and the Atmos Gas utilities into the fold, almost CAD600 million of utility operations coming into our business within basically a couple of months. And that was also the year that we were bringing in almost CAD800 million of wind assets in the US, and it was our first big foray into the US as far as wind goes.
So we did have to make a fairly sizable investment in our infrastructure. And we did that in 2012, basically slightly in advance of that. So you did see that as a percent of EBITDA, relatively strong spike in our costs.
But as that EBITDA washed through the organization through 2013 and now into 2014, I think you can see on the graph as a percent of EBITDA, although our admin and support costs have been rising, as a percent of EBITDA we are actually getting more efficient as an organization. And the other thing that I would like to point out is with all of these operations now within our fold we have taken steps to further centralize some services that previously were being provided in operations. And that's represented there by the gray bar. So as you actually just looked at the raw administration costs on the face of the financial statements you will see it rising yet again, I say, in 2014.
But I think it's important to keep in mind that that is really just a repatriating of some services that were previously done in operations that are being done centrally within our organization. I will say I think we really have a strong operation now to continue to fuel the growth of the business.
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Chris Jarratt, Algonquin Power & Utilities Corp. - Vice Chair [26]
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And I think I would also add that all these administration costs include costs associated with the governance initiatives and all of the controls and risk management, all the things that we've implemented over the last few years are embedded in those costs as well.
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [27]
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And then maybe lastly, as we look forward to 2015, I think the costs that we are going to see are probably close to about CAD38 million. And so while there's a slight rise, perhaps, over 2014 I think it's generally consistent with the growth that you are seeing in assets and EBITDA.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [28]
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Okay, thanks. Chris, you talked about board succession earlier. And now that Jeff's been told he can go home, I guess focus on succession planning for the senior management team. Can you talk a little bit about how the Board and management team are thinking about succession planning as may be some of our more senior folks move on to the next stage of their careers?
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Chris Jarratt, Algonquin Power & Utilities Corp. - Vice Chair [29]
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Yes. I was going to say, notwithstanding Ian's comment about Jeff's succession planning, the Board takes it --
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [30]
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Take a mint on the way out, Jeff.
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Chris Jarratt, Algonquin Power & Utilities Corp. - Vice Chair [31]
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-- The Board takes it very seriously. We see it as the orderly succession of senior management, and a plan for nurturing strong leaders is a key component of our long-term success and sustainability.
Succession planning, too, is one of those things which is truly a win-win. It's a win for the employees. It's also a win for the Company and is a win for the Company on a financial basis through reduced training costs, reduced recruitment and, obviously, the benefits of having a highly motivated workforce.
The other thing that succession planning is quite useful for is risk mitigation. Hiring new people is always risky. It always comes with risk. And the other risk that any organization faces is key employees leaving suddenly, for whatever reason. So those are two risk areas where having a strong succession planning will help you.
And I talked earlier about some of the benefits that we've had with Emera. And I think succession planning is one of those areas where Emera has a very well advanced succession planning tool in place. And they have certainly been able to help us a lot of the last few years with that.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [32]
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Great. And just to continue on a little bit on sort of the same theme, let's talk a little bit about executive compensation and, again, how the Board is looking at that and how they are incenting the management team to achieve Company goals and how -- if we are going to plan to evolve it in the future, how that may happen.
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Chris Jarratt, Algonquin Power & Utilities Corp. - Vice Chair [33]
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Sure. And I should point out at the beginning that compensation -- it goes right through the organization. It's not just at the executive level; it goes right through the organization. And it's built on some principles -- transparency, fairness, consistency, motivation, and attraction and retention of key individuals are the principles that guide us.
There's a couple of key features of our compensation plan. Firstly, we like to see a clear link between the Company performance as well as compensation. And I think you can see on the graph that's shown there that think we have maintained that.
There's also alignment issues as well. But there's also a significant and appropriate pay-at-risk component that is important to have. We also spend a little bit of time on controls for compensation, and what I mean by controls on compensation are things like we worry about unintended consequences of compensation. We don't want perverse consequences. We have caps on our payouts and we also have the ability to retract long-term compensation under certain circumstances.
We also have a guideline for executive share ownership. And we think that's an important component of the compensation plan. And so, I think our compensation plan, just in summary, is based on alignment. We align ourselves with our peer group in the industry. We align ourselves with the shareholders. And once again, that graph kind of shows that. And we also -- as I started today with about our corporate strategy and our compensation is aligned with that.
And probably it warrants mentioning that compensation also applies to Director compensation. Our Directors get paid in -- 50% of their base fee in DSUs. We have a movement towards a fixed plan bike reduced meeting fees but more fixed fee basis, and making sure that our Directors, our compensation is aligned with the industry and their peer group.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [34]
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Thanks, Chris. Let's talk about financing for a minute, David. You and your finance team have managed the financing requirements to grow the company from about CAD980 million in 2010 to over CAD3.5 billion today. We have some future growth we are discussing today which includes Odell wind, which we announced a little while ago, and Park Water acquisition. We made two announcements yesterday. So what are your plans for financing? How are you going to manage the growth?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO [35]
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Well, there's no doubt when you are growing the business to the extent that we are, and that is like putting on anywhere between CAD500 million and CAD1 billion of new investments every year, access to capital is critical for the organization. So we've established for ourselves two platforms for debt. On the distribution side of our business we access the US private placement market, where we have been repeat issuers down there -- very effective tool for raising low-cost debt for operations.
Here on the generation side of the business in Canada, again a very successful debt platform. I think earlier this year we issued a CAD200 million bond. It was well oversubscribed and a really successful outing for us in the debt capital market. So raising the debt, I think, is well established now with those two platforms.
Then when it comes to equity, we really have three tools in the toolbox that we look at. First of all, for US wind projects, because we are not a very efficient utilizer of tax attributes associated with wind farms. In the US there is something referred to as tax equity, and I think you will be hearing a little bit more about that later in the morning. But tax equity is a really effective source of equity for us for wind power projects in the States.
Preferred shares are now in our capital structure. We are well established now with two series of preferred shares in the market. We do have room to add more preferred shares to the mix going forward. And then, of course, plain old common equity, which we generally access last in the order of priority, if you will.
And as we issue equity, I think our view of that -- it's really we issue equity in response to the opportunity set that we see before us in the marketplace. And we really have two principles that we do guide ourselves with. One, we want to make sure that all of our capital needs for the coming year can be met without really needing to go to the equity capital markets. And I think the chart here, the various sources and uses of capital, I think, demonstrates that clearly. And we always really want to make sure that our equity does stay ahead of our actual needs so that we never have now back up against the wall in terms of needing to access the equity capital markets.
And then the last thing I will say is free cash flow is a tremendous tool that we have and, I think, one that really differentiates us from our peers here in Canada and in the US. We are really only paying out about a third to 40% of our cash flow as a dividend. And so that really allows for significant reinvestment of free cash into our business. So even if the capital markets for some reason closed to us and, let's say, for everybody, it wouldn't end our growth program. It might slow it down, but it won't end it.
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [36]
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And I would say just to emphases. One is that low payout ratio, I think, is a very distinguishing and, I would actually argue, a competitive advantage that this organization enjoys when you think of some of the rest of the peers certainly in the IPP space. And the other comment I'd make is, just to follow on David's comment, is about the equity. I would hope everybody in this room sees an equity issuance as a good thing. We are funding accretive growth going forward. To the extent that we issue equity, it's because we have projects that are going to accrete to earnings and cash flows and, therefore, dividends. And so I hope that everybody thinks that's a good news story, even though David kind of positioned it as the end of the -- as the last thing in the financing toolbox.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [37]
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Thanks for that. I think the burning question the audience might have is what do you see, David, for the next 12 months or so, given the growth that we have in front of us?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO [38]
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Well, again, we are going to be adding anywhere between CAD500 million and CAD1 billion of new assets and investment over the next 12 months. So we are going to be, I think, quite active in the capital markets again this year.
On the generation side of the business I think people can expect us to be accessing the Canadian public bond market again. We are probably looking at issuing a bond sometime in 2015 in the CAD150 million to CAD200 million range. We've got a number of projects that now are reaching COD. And so we definitely will be looking to secure long-term fixed rates for that.
On the distribution side of the business, again, I think we will be back into the US private placement market, again with an offering size probably in that CAD150 million range. And really on both sides of the business I think one of the things that we will be looking for even more so than in the past, we are really down going to be focused on trying to get the longest tenor possible that we can on the debt that we are seeking in the marketplace.
And finally I'd say that, just given the recent announcements, I think following our equity offering in September we announced the acquisition of Park Water. I think people saw the announcements last night. Bakersfield II is another solar project for us. And then our investment in the Kinder Morgan pipeline. And so, we are starting to look at those in trying to assess what's the best way to lock in the accretion on those investments.
And really, I think, as we always say, we really look to size the amount of equity that we look for really in the context of our capital structure as a whole. And I think people can see that we have a very strong capital structure with our long-term debt being about 45% now of our total cap.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [39]
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Great. Ian, you talked earlier about the growth trajectory for assets in EBITDA. But can you give us some view on earnings and cash flows per share and how they impact the payout ratio?
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [40]
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Yes, sure. I'll start by saying if there's one slide from my perspective that should summarize everything that you are going to hear in the next three hours it's this. This is we understand, and I mentioned earlier that everybody in this room owns this Company one share at a time. I get it that the debt guys are interested in EBITDA and they are interested in collective numbers. But really, ultimately, at the end of the day, to the extent that you are a shareholder in the common equity of this Company, you really care about how we are managing this organization on a per-share basis.
If a particular investment is dilutive or neutral or accretive to value, it has to be done on a per-share basis. And I'll say right off the bat that we obviously only will pursue things that, in our best judgment, are going to be accretive to value. And so there's a chart there. And as I mentioned, there's a thousand assumptions behind a chart like that. But I think directionally there are some really important takeaways from a chart like that.
And the first, I think, is with respect to accretion. And we look at accretion both on a GAAP earnings and the cash flow per-share basis. The lines are upward sloping. And so that means that as we look forward and we think about the growth in earnings and cash flow, as we build out the portfolio of assets that you have heard about, read about in our MD&A, the stuff we talked about in our press releases, as we forecast that forward and look out to 2018 or 2019 we are seeing an upward slope in our cash flow per share and earnings per share. And you will have to trust me on it in terms of the slope. But it's high single-digit, low double-digit growth in both of those metrics going forward.
Specifically, Kelly, you asked about dividend. And then clearly it's an important element of anyone who makes an investment in infrastructure business. This is really all about show me the money. And we understand that that's what the thesis behind an investment in long-lived infrastructure assets is all about.
And so there's a couple of observations you can take from this slide. And the first is that the solid orange block represents our dividend history over the past few years. And I like to think we are now establishing a trend of continuing to increase the dividend as the earnings per share and cash flow per-share have continued to rise.
But the takeaway I'd offer up in the first instance is that we have a relatively conservative payout ratio, if you think about payout ratio as a percentage of cash. And that's a metric by which most of the IPP's have largely measured their payout ratio. And for those of you who have the same gray hair and can think back to the income trust era, it was all about cash available for distribution, and many organizations paid out 100% of that. And in some respect, some of the guys in the IPP business still find themselves there.
But frankly, I'm not sure that -- let me turn it into an affirmative. We don't believe that that's a sustainable proposition. The investment thesis we have for the assets that we are acquiring is multiple decades of line of sight to a value proposition. If you are going to pay out in excess of your GAAP earnings, ultimately you are going to erode the equity of your balance sheet. That's just how GAAP earnings were. And so if you say, well, I'm going to be here for the next 30 years, well, if you are paying out -- as I said, if you are eroding your balance sheet, I don't know what that's going to do to your boring metrics. But I'm telling you S&P are not going to be very happy with you and it's going to change the dynamics of that organization as it goes forward.
So consequently, I think we look at dividend payout in the context of GAAP earnings per share. And as I said, a couple of thoughts on that one -- as I said, I think this is a threshold year for us as our GAAP earnings have crossed through our dividend. You might think, and obviously I'm a little presumptuous here, but you might think from the Board's perspective that GAAP earnings per share might represent an upper bound on how the dividend might rise. And two pieces of good news -- as I said, we are already -- our GAAP earnings are trending above our dividend.
And second of all, as I mentioned, the upward slope of that line is high single digit, low double digits. And so consequently, as you think about the dividend going forward, are those earnings per share and those cash flows per share going to support the kind of high single-digit, low double-digit growth in dividends that we have largely spoke of? And I like to think the answer is obviously yes. And so, as I said, this would be the punch line if this -- but this is hardly a joke. But that -- this would be the conclusion from my perspective of everything we're going to talk about for the next two hours.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [41]
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Great. So before we move on to our generation segment this morning I'm going to ask the three of you to, in 30 seconds or less, give us the top three things that are on your mind, given your role with the Company. Ian, we know upward sloping lines are definitely on your mind. But let's start with David and then go to Chris and then Ian.
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO [42]
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Well, I think, as we touched on, clearly keeping a laser focus on our costs of capital and making sure that we are as competitive as anybody on the Street, I think making sure, given the intense capital nature of our business, that we have robust access to both debt and equity capital markets here in Canada. And finally, just making sure that our equity actually does stay a little bit ahead of our needs.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [43]
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Okay. Chris?
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Chris Jarratt, Algonquin Power & Utilities Corp. - Vice Chair [44]
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Great. Well, I think one word that got mentioned a lot today is sustainability. And so I think that's probably one area that I believe in. Succession planning is obviously a big part of that. Rightsizing the governance best practices, recognizing how much growth we are doing. And speaking of growth, I would say undertaking that growth in a manner that doesn't materially change the risk profile of the Company.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [45]
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Great.
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [46]
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Well, that was four things. But I'm not counting. So from my perspective, I think we need to deliver on the annual financial commitments that we explicitly make to the capital markets. I think, while I like to believe this organization is past the show-me mode, if you want to think of that, this organization has obviously gone through a significant evolution from its transition from an income trust to corporation. But I'm hoping that people look at the history. But having said that, you need to say what you are going to do and do what you are going to say, certainly from an annual perspective.
The second thing is we totally believe that the thesis that people look to this organization for, in addition to obviously stable earnings in the particular year, is that ability to grow this organization going forward accretively. And so that's the thing that certainly sits on my mind.
And lastly and maybe most importantly, that everything that we do should be done with respect to environmental, health, and safety processes and procedures. If we are not going to do this safely, then we can just go home right now. But, having said that, I think there's a certainly an opportunity for this organization to do good as well as doing well. So those are the three things that are on my mind.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [47]
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Great, thanks. We can open up to some questions now. If anyone has one, you just raise your hand and wait for the microphone.
No questions? Okay. Well, we can move on to our generation --
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [48]
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No, Rupert has one.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [49]
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Rupert has one. Sorry, I didn't see you, Rupert.
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Questions and Answers
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Rupert Merer, National Bank Financial - Analyst [1]
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Rupert Merer from National Bank. Looking at your uses of capital, can you talk about how it's involved since the analyst day last year? You've got a couple of big acquisitions that you are looking at this year. Will you slow down on the organic growth, then? It looks like there might be a little less organic growth in the plan.
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [2]
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I think the nice thing about the organic growth -- as everybody acknowledges, it comes without premium. It comes with the timing which is within our control. It comes generally without regulatory risk, to the extent it's managed. And so, I think we will always manage organic growth within the distribution sector prudently to maintain the integrity of the system. We were obviously pleased that our ability to add Park Water to the portfolio going forward. And I think it's probably not an unreasonable observation that as we looked at our capital plans for 2015, if there were opportunities that perhaps the recovery might not have started until 2016, we might delay that until the end of 2016 or 2015/2016, to shift that capital. But really, it is all about recovery, speedy recovery on that capital you will hear later today.
So it wasn't a huge initiative, Rupert, in terms of shifting that capital to accommodate the Park Water. I think we are comfortable that the 2015 capital needs of the organization can be accommodated in the context of our access and sources of capital. So I don't feel the organization is being stressed, if that's perhaps the basis of the question.
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Rupert Merer, National Bank Financial - Analyst [3]
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Well, it seems like you have some flexibility in your sources of capital that you could still go after some organic growth in addition to your (inaudible).
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [4]
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Yes. I think, as David said and maybe just that the risk of repeating his comment, I think it's important that we always lead, if you will, any announcement of an opportunity with a capital structure that everybody in this room goes, I get it, those guys can do it without necessarily coming to the capital markets. The worst thing that we could do is have an opportunity that we thought we were going to create value for shareholders, announce it and have people say, oh, it creates an overhang, beat the heck out of the stock, and, in fact, destroy shareholder value.
So, we always need to position the capital structure. If we have growth aspirations, and we obviously do, we need to have a capital structure that, as we announce things and announce initiatives, that people are confident that that can get done without stressing the organization in such a way that we put ourselves really in jeopardy of someone saying, oh, how are they actually going to finance this?
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Rupert Merer, National Bank Financial - Analyst [5]
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Thank you.
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Unidentified Audience Member [6]
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How do you determine your cost of capital, particularly in the context of a 15% or 18% growth rate?
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David Bronicheski, Algonquin Power & Utilities Corp. - CFO [7]
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Well, the cost of capital calculation that we shared -- we actually used two methodologies to establish the range. One is the traditional cap M model, and one was the dividend growth rate. And so we did try to, I guess, triangulate where our stock is being priced in the market currently to try to establish what the market is perceiving as some of the assumptions because you can imagine that it is fairly sensitive to the growth assumption when you are using those formulas. But those are the two methodologies that we used to establish the range.
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Nelson Ng, RBC Capital Markets - Analyst [8]
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Nelson Ng from RBC Capital Markets. So just touching on the cost of capital and the sources of capital, given that most of your assets are in the US and your dividends in US dollars, can you comment on a US listing? And roughly what proportion of your shareholder base is currently in the US versus Canada?
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [9]
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Right now, I think Kelly might actually be able to answer it a bit more accurately than me. We don't have large US investment following in the US.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [10]
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10%.
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [11]
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I think we are about 10% --
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [12]
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Yes.
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [13]
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I was going to say. I think that now that we have changed to a US pay dividend, I think we are starting to see more interest from US investors, that's for sure.
As far as a US listing goes, that may be inevitable. We are already an SEC registrant. So for us to obtain a US listing, it's really writing a check for a couple hundred thousand dollars, and in 30 or 60 days we would be listed on an exchange in the US. So, I think that's something that's definitely open to us and something that we do actively consider from time to time.
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Chris Jarratt, Algonquin Power & Utilities Corp. - Vice Chair [14]
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And then maybe just to add a few more words around that, I think everybody in the room is familiar with the hold yield co phenomenon in the US. And while it does hark me back a little bit to the income trust days here in Canada, what I would mention is that the characteristics behind those yield cos are clearly constant dividends from secure sources with a thesis of growth. And I can't think of two characteristics that more aptly describe Algonquin. So the hope clearly is that the US pay into dividends, the residence of 80% plus of our assets being in the US, this interest in probably arguably renewed interest in yield in the US -- I think the expectation is that we would have a continued growth in the holdings by American investors.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [15]
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Matthew, we have time for one more question. So please go ahead.
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Matthew Akman, Scotiabank - Analyst [16]
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Matthew Akman, Scotiabank. Ian, I noticed one thing that was not top of mind for you is geographic diversification. And you have rejigged the segmentation to include transmission. But I noticed that you didn't add other geographies. And unlike a lot of your peers that are now looking proactively at more actively investing in especially Europe and Mexico, I'm wondering if these geographies appeal to you guys and whether that's on the radar screen at all. I guess you guys are closer to Mexico already than a lot of your peers.
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [17]
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A nine iron from Rio Rico will actually get you in some serious trouble, if you know what I mean.
Thanks for the question, Matthew. I guess the way I'd start by looking at it and saying is CAD2.8 billion with the growth in North America ain't enough? But perhaps more seriously, I think our investor base is comfortable with -- I'll even characterize it as the country and currency risk that comes with being in the US. We don't see the need right now to bring real country risk, real currency risk, maybe even technology risk, operational risk -- you speak of some of our peers are a little bit off the fairway, at least from our perspective. As I said, I hope you walk away today with seeing CAD1 billion worth of contracted wind and solar projects here in North America and CAD1 billion of US utility assets and CAD500 million of US pipeline assets, and that people go, okay, they are going to be able to deliver on growth, the commitments they are making.
Having said that, we obviously keep our eyes open. And to the extent that there are utility assets in Europe, I think you mentioned, we would certainly be interested in going there. I think we would be hesitant about introducing, I'll call it, real country risk into the proposition and frankly don't see the need for it right now. And so, yes to the we want to keep our eyes open. But we don't feel the necessity. I hope that's responsive to your question.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [18]
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Okay. We have to move on to our generation group now. So I will ask our esteemed executives to leave the stage. Take a mint on your way out.
So I'll just quickly give you guys introduction of our three members of the generation team. Mike Snow, to my immediate left, joined Algonquin in 2011 as President of the generation business. He has led both industrial and consumer organizations, focused on growth in international operations in Mexico, South America, and Asia.
He has a Bachelor of Science degree in math, a Bachelor of Engineering degree in mechanical engineering, an MBA, and also has his Charter Director Designation.
Jeff Norman, next to him, joined us in 2003 and is the VP of Business Development for the generation group. He's focused on building a portfolio of energy-based investments in North America.
Jeff has over 22 years of experience, having reviewed the merits of hundreds of renewable energy projects. He's a CPA and holds a Bachelor of Arts degree and a Masters of accounting.
And furthest on the stage is Todd Mooney. He joined in 2012 and he's the VP of Finance and Admin. He's responsible for the generation group's financial operations, including the planning and analysis, accounting, production reporting, and administration. He spent 11 years leading finance teams in Europe and North America. He has a Master of accounting degree and is also a CPA.
So with that, I'm going to hand it over to Mike to kick off the generation section.
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Mike Snow, Algonquin Power Company - President [19]
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Thanks, Kelly, and good morning, everyone. It's a pleasure to be back here for investor day again and as president of the generation group.
I think it's part of the excitement about being back here -- it's another opportunity to update everyone on the continuing success story of our business. And today as your sitting there listening to our group for the next 40 minutes or so, Jeff, Todd and myself, we want to make sure that you leave with what I'm calling four key takeaways about the generation business.
First that our current CAD500 million project pipeline is on plan and on track. And it's also, as Ian has been mentioning, going to deliver earnings and cash flow accretive growth into our business.
And just to be clear that our entire pipeline is actually CAD1.2 billion, which includes the CAD500 million and of course, that is all fully contracted with long-term PPAs.
Secondly, our development team -- and you'll be hearing about this today -- continues to deliver on accretive opportunities. And next, we are aggressively pursuing wind and solar growth projects.
We've got -- really, I would describe laserlike focus in our organization on these two modalities and we are particularly excited about them. And as you'll see in our upcoming slides, because of the declining levelized cost of energy of these forms of generation and what we see keeping them as competitive generation sources for the future.
And lastly, with the growth of our assets and particularly wind, we'll want to talk about the benefits of portfolio diversification, something known as the portfolio effect, where we are actually seeing an increase in our production -- energy production certainty.
So we have a full agenda, as you can see. We'll be discussing some of the market dynamics, the outlook for renewables in North America. Talking about our portfolio and then getting into strategy.
And then with Jeff and Todd, kind of drilling down into our development plans and then a look at financials for the business in 2015 and going forward.
So as you just heard with this theme of accretive growth, I want to take a minute to, I guess, remind you and review for every one of our track record that we feel we have in delivering on value creation. With EBITDA growth in 2013 reaching CAD129 million and a capital spend of little over CAD600 million between 2010 and 2013.
And that was across five projects. St. Leon II, our Gamesa assets, Sandy Ridge, Minonk, and Senate, as well as our Shady Oaks project, you can actually see on this slide a material improvement in the capital efficiency over this period, growing from 13.6 times EBITDA down to 11.1 times in 2013.
This is a pretty important metric for us around value creation and you should know that it forms part of our decision-making process around new investments.
And further to our value creation story, the generation group has 4 highly accretive projects ready for near-term COD that make up this CAD500 million in investment that I mentioned earlier.
Now if you want to focus on the five-year average EPS, the accretiveness on each of these projects, I'll just mention that this is really a metric that we use kind of notionally internal for our own review of projects. There's no actual equity being issued here for each project, but we evaluate them as if they were standalone entities. And then we attach a share quantity based on debt -- 50-50 debt to equity.
And just to touch briefly on each of these projects, we are pretty excited about the 24 megawatt St. Damase project in [Gas] Bay. It is now complete. So right on target. Our 23 megawatt Morse wind project in southeastern Saskatchewan will COD in the first quarter of 2015 as will our 20 megawatt Bakersfield solar project in central California.
And as you heard, our most recent wind announcement was the 200 megawatt Odell wind farm in Minnesota. That will go COD before the end of 2015, in Q4 next year. And these four projects are making a significant increase in our overall generation capacity, increasing it by about 24% to over 1,360 megawatts from our 1,100 megawatts to date.
So you've heard me talk that wind and wind projects are really a significant part of our value creation strategy going forward. And we are excited in large part about wind and its opportunities really because of what you're seeing on this slide, which is this declining levelized cost of energy for wind and what's happened over the last 4 to 5 years, with wind now touching at the low end of a range on LCOE at CAD37 in 2014.
So as you could guess or you may already know, this has wind competitive with combined cycle gas turbine tech technology. And in some locales where there's actually a high strong wind regime, this actually has us below the LCOE for gas turbine technology. So this gives us a pretty positive outlook for the competitiveness of wind going forward as a generation technology that we want to invest in.
So what's driving this LCOE downward? Well, I would say at the top of the list is the increasing rotor sizes and rotor diameters that are hitting the market, improving both net capacity factor as well as the energy delivered.
We see this evolution in our own fleet, with St. Leon I back in 2005, where we had an 80 meter rotor, to our Morse Wind project that I mentioned a minute ago, that'll have 113 meter rotor on a Siemens unit. This is about a 56% increase in the swept area.
Higher towers, part of the future. Trying to get the higher velocity and of course, higher energy output. We are already seeing towers in Europe reaching 140 meters.
And on the software side of things in turbine control, the OEMs are coming out now with the ability to control turbine-to-turbine function in deep array wind farms. So these would be wind farms, say, 200 megawatts or larger in an effort to control wake losses and really improve yield.
And then of course, the -- we like the look of the emerging technology of direct drive units. Our success at our Shady Oaks wind farm has been very positive with these on our gold wind units.
And it's the same kind of story with solar on a declining LCOE, except the drivers are different than wind. In this case, it's about sustainable cost reduction and not necessarily technology improvement.
And again, this has our interest in looking at solar as a long-term investment. We like to think of solar that it's really coming of age as a generation technology. You can see the LCOE has moved down quite significantly from 2011, where it was CAD157 down to this range of CAD72 to CAD86 and that's on an unsubsidized basis.
So -- and we look at solar, I think, with maybe 3 to 4 years away from grid parity. In fact, in some US jurisdictions with high power prices, you might even say it's there today. So it's well on its way.
And the compelling part of this cost-reduction about solar -- it's not about supply and demand, which is driven a lot of the falling solar cost in the past. This is now about good old manufacturing technology and people looking at innovation across the supply chain in solar.
So things like improving their manufacturing efficiencies. So looking at Lean manufacturing. Substituting lower cost materials and in some cases, doing a bit of redesign on the solar panels themselves.
And as you can see, it's interesting. If you look at the numbers here, one Chinese manufacturer out the door in China, so they are all-in costs. They've taken the per watt costs from CAD1.31 back in 2011 down to CAD0.53 a watt in 2014.
So with LCOE as the underpinning, really, for future growth in renewables, we see wind and solar adding significant capacity over the next 20 years in North America. We are quite bullish on these two forms of generation. And we would say this even in the absence of government subsidies and also the end of the step up for the RPS, or the renewable portfolio standards, in 2025.
In fact, we don't believe that PTCs are even needed to get wind, for example, or solar to grid parity. Whereas a US utility in the Midwest today might offer a PPA in the low CAD20s, you'd have the PTC around CAD23. In a post-PTC world, we could see a PPA at around CAD50 to maintain the economics and the continued investment in wind going forward.
Bloomberg is even forecasting wind investment continuing at somewhere between 6 to 8 GW a year in a world without PTCs.
So let's turn to our own portfolio. And with the future positive outlook for wind that we have, I think it's important to discuss a couple of positives about our growing wind portfolio and this entire area of production certainty.
You're looking at a map of North American wind speed variability here. And the legend and how to read this. The dark blue represents the areas of greatest wind speed certainty and the areas of orange and dark red represent those of lower certainty.
And it's interesting to note that the triangles representing all of our existing assets as well as the ones that we are going to invest in in the future are all strategically located in areas of greatest wind speed certainty.
And this matters for a couple reasons; one in terms of production consistency as well as revenue generation. And secondly, I think as well and maybe even more importantly, the diversification of these assets. So where they're located geographically results in a very low production correlation between these wind sites and this actually increases the overall production stability or certainty.
So this is something known as the portfolio effect, which for our sites and the dispersion across North America, actually produces, if you want to look at a P90 energy number, that's about 5.5% in aggregate greater than the sum of the individual sites themselves at P90, so quite significant.
So if you want to think of this concept as comparable to a diversified portfolio of stocks, where you have reduced variability or a greater certainty on returns. And so we think this portfolio effect is pretty significant in our wind business and especially as we continue the strategic buildout of our assets across North America.
While I've been discussing, I guess, our assets on a portfolio basis, it's interesting to consider the returns for wind, solar, and hydro, which are really a reflection of the supply and demand for each of these asset types. And I guess the first question you might ask is the market efficiently pricing these assets?
And in our view, we believe the answer is yes. And that the returns that you are seeing up here really reflect the market's view on relative risks. So resource risk on wind, for example, on a single asset basis is much higher than for solar.
However, as you saw earlier in my presentation, with this portfolio effect, there's a significant amount of that that can be mitigated because of this low correlation between the assets.
Recurring CapEx, as you might think, would be much lower for solar than would be for wind or hydro, but in our case, we mitigate this risk through entering in the long-term O&M agreements with the wind turbine manufacturers, anywhere from 10 to 20 years.
So relative to these risk mitigations, we actually believe our portfolio of wind assets does in fact warrant a higher return than a portfolio of solar assets. And while I don't want to leave out hydro, because as you know, we're big fans of hydro, but development opportunities are pretty rare in the hydro space above 20 megawatts, given the long development cycle and the high capital costs, which really on an LCOE basis make it pretty expensive compared to wind and solar in North American markets today.
So I'll now conclude my portion of this presentation on the generation group with just a brief overview of our wind and solar strategy. Overall, we have a target to grow our portfolio to 2,500 megawatts by 2019 from the 1,100 megawatts we have today, driven primarily by onshore wind and utility scale solar.
And we think we're well on our way to this target. As I mentioned earlier, the four near-term projects that will be COD by the end of 2015 will take us to 1,360 megawatts.
Wind specifically; we want to grow from 650 megawatts today to 1,600 megawatts over this 5-year period. Now the 1,600 megawatts may seem like a daunting number, but if you think about the six wind projects that are in our pipeline fully contracted, by the time they all reach COD at the end of 2017, we'll be at 1,175 megawatts of wind.
We think there's abundant opportunities to grow our solar portfolio. And while we're starting off with 10 megawatts in operation today at Cornwall, our objective is to get to 300 megawatts by 2019.
And if you want to think about what the strategy implementation would look like, think about our Bakersfield 1 today and then the recently announced Bakersfield II, where we were able to learn and leverage from the infrastructure of Bakersfield I to go ahead with another development adjacent to it. Not unlike what we did with St. Leon II, building off St. Leon I in southern Manitoba.
So this concludes my presentation. And at this time, I'm going to call on Jeff Norman, our VP of Business Development, for an update on development plans. Jeff?
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Jeff Norman, Algonquin Power & Utilities Corp. - VP of Business Development [20]
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Great. Thanks very much, Mike. I have to admit that I really enjoy investor day and I've been reflecting, trying to figure out why that is. And I think I've come to the conclusion that each one of the development projects that we undertake, they have a fairly long cycle. They start smaller or even conceptual.
And we manage to evolve them and bring them to these EBITDA-generating facilities that are almost like growing children of Algonquin contributing to the EBITDA.
But unlike my children, when I go home and talk to my wife about these projects -- she's getting a little tired of them -- but here today is a group that I think is actually interested in learning, because probably because I only talk to you once a year, but also these projects have a direct impact on your outlook for Algonquin.
And I think you've got two overall questions. One, have we managed to grow this portfolio of development projects and have any of them stumbled along the way? And I can answer both of those a high level right now before going into the details.
And the answer on the growth is we've managed to add, as Mike has indicated, Bakersfield at 200 megawatts as a material project into the pipeline -- sorry, Bakersfield at 10 megawatts of solar and Odell at 200 megawatts of wind.
So the pipeline is growing. We're pleased with that. I'm also pleased that none of the projects have fallen off the rails. They are all moving forward through the normal development cycles and I'll give you a bit more details as we go through.
My presentation is really broken into two sections. The first section is how do we keep that pipeline full? What do we look at in the market for drivers to drive our activity and where we should be placing new investment? And the second part is an overview of the portfolio that we have.
And so I'll start with a picture that everyone has seen. This is the North American wind market and it's color-coded by the amount of capacity that's being built in the various states and provinces.
And I wanted to look at this, not because it's new information, but because the industry is about 10 years old now. If we would've had this picture 10 years ago, we could have perfectly placed all of our investments in the right markets and been really given a strategic advantage. And the question is what will this look like five years from now, because that's what we need to do in terms of investing our new develop capital.
And I think there's a number of drivers that are pushing this. And some of them a very obvious, like wind resource. Some of them are the technology changes as we see the dropping LCOE and the impact it has on different markets and the dynamics in those markets. Some of them are transmission capacity.
And just to take and see how these different drivers play out, you look at Texas, which is over 5,000 megawatts. It's actually 10,000 megawatts of wind, almost 25% of the US installed base in wind in one state.
And that is a state that doesn't have a renewable portfolio standard. And you go, what's going on in Texas and how can we see the next Texas evolving. And it really was pure economics.
The PTC is meaningful; drops the cost of the LCOEs that Mike was talking about by probably CAD20 a megawatt hour. It also -- there's a massive wind resource; there's great transmission capacity. There's a very reasonable permitting environment.
All those things come together to take and make it very economical for projects to evolve in Texas. And we want to look for is where else that's going evolve. But that's not the only way those drivers play.
Take Ontario, a market that we're all familiar with. Ontario has a different set of facts. Ontario doesn't have a great wind resource; it's got an okay wind resource. But when the Dalton McGinty government came in in 2004, they launched a war on coal. And they came up with a number of initiatives that drove renewables and the adoptions of renewables in the Ontario market.
So watching for that political move that essentially that renewable push in Ontario is what would have given you the incentive to invest in Ontario back in 2004, 2005 and being well positioned to be a big player in that market today.
Obviously, each market is little bit unique, but the drivers that we're watching are essentially a group of key drivers and they impact wind in one way. They actually impact solar, which is the next map, a little bit differently.
You can see on the solar map, as Mike pointed out, the LCOE for solar is just now approaching grid parity. It wasn't there. So you don't see a big Texas market, but you do see a big Ontario, California, Arizona, and New Jersey market, which is where the RPS programs or the FIT program was strongest driving that.
As we roll forward into the future and we watch one of the drivers being the LCOE for solar, as it declines, what is going to do the market? Where is that going to open up new opportunities? One of the opportunities that you see really taking off in pure economics is always the greatest driver is in California on distributed solar.
The LCOE for solar now is below the retail price of power and so that's why we're seeing massive adoption in rooftop solar within the California marketplace. Will we see that take place at the utility level and in which states will that take place?
That's really the question. Where we go to next is how do we staff the organization? We've got a lot of markets, number of drivers. We not only have to watch the drivers, we then need to be prepared to act on those drivers and secure a position to move forward.
So this is just a rough breakdown of how the development group at Algonquin is organized. And we think of it as three key functions. The origination function, which is really the most entrepreneurial spirit, looking to try to find which drivers should we follow, which markets should we enter, how do we secure land and sites, and then how do we take and turn that into a contracted facility? That's the five people in the origination group.
And to put this in perspective, in 2008, when we formed the development group, we actually only had 5 people on staff in total. That group has brought this portfolio of CAD1.2 billion together.
So I'm confident that a group of five people dedicated to looking at these drivers and securing our position moving forward will be able to grow that pipeline even further than we have historically.
Once the origination team is done, it really moves down to the development team. Now that's about 10 people at this point in time. And their job is to de-risk these projects.
As you move forward, if you've got revenue certainty and you've got a site locked up, how do you take and turn your queue position for interconnection into a signed interconnection agreement? How do you turn your permitting and your baseline studies that tell you don't have any permitting or species issues into full permits? How do you take and continue to advance the project to have enough engineering that you are confident in your VLP estimate?
And that's with the development team does. They effectively take out almost all the risk before turning it over to construction. And that's a critical step, because the dollars involved at the construction are obviously, for our portfolio, CAD1.2 billion and you have to take and make sure you de-risk it before you turn and make those major construction commitments.
The construction phase is a bit more boring, but it takes a lot of resources. And so we've got 20 FTEs here. We've got 3 projects, as Mike indicated, that are under construction, and we need people on-site monitoring to make sure the contractors are doing what they are obligated to do under the contract.
We need project managers to make sure all the moving pieces are synchronized and we that hit COD on time, like we did for St. Damase and like we expect to do for Morse and Bakersfield.
And it's this group that takes all the great pictures. They get a lot of the glory, but it's the origination group that actually starts everything off and that we need to make sure we stay focused on.
So switching gears, I've talked a lot about the fact that we've got geography. Where do we invest? But the other thing is when do you invest. And this is a concept which has risk-adjusted returns over the lifecycle of when we could invest right from early development through to operating assets. And it's from the perspective of the three main players in this market that you are competing with.
One being financial investors, which are typically looking for risk-mitigated projects that are by and large are operating. But the group has moved forward and we've seen them and we are competing with them for projects that are moved into the construction phase.
And that's because most of the risk is gone; it's been allocated to the main contractor. And they're driving down returns a little bit in the construction and the operating end of the cycle.
The other group there is obviously strategics like us. We'll invest anywhere in the cycle and we do invest right from early stage greenfield development through to partnering with junior developers part way through that process.
And we see a bit of an apex in the curve between early and late development in that risk-reduced curve because we understand the development risks. When we go and meet with the junior developer, we go and secure a project on our own. We don't just look at the IE report that might say they've succeeded in getting some permits, but not all. They are missing the following permits.
We then taken to the permits that they are missing. We might drive to the root of where the permits going to be. We get into the community and understand the community support levels and we can make a very calculated decision on whether the project is going forward or not going forward. And that's where we feel we can get the best return and the competitive advantage for Algonquin.
On the very left side of this curve is the junior developers. And these are the guys that might have a really good understanding of one local market or a few local markets, but they are generally undercapitalized and so they are normally looking for partners part way through the process.
And so if you compare the geography where we want to be, watching the drivers to make sure we're keeping track of those, and the time cycle it takes and allows us to pull projects together and move forward. But Chris mentioned the entrepreneurial spirit and how do we take and make sure that that entrepreneurial spirit is measured?
And what's measured is what's delivered in life, generally. So we look at two things: strategic campaigns for the origination team and regional campaigns. And I'll just briefly touch on these. And these aren't meant to be the magic sauce in any way; they are just examples.
But Southeast US Wind. There's very little wind in the southeast because the wind resource isn't very strong, but there's currently a war on coal and declining LCOE costs for wind turbines. Larger rotors, taller towers, better software.
Are we going to see an intersection where because of the drive to get away from coal, because of potentially new renewable portfolio standards in the southeast, is it time to go and lockup projects in the southeast because their time is coming?
So we would set a strategic campaign that would say nice hypothesis, it's a good thing to bounce around, let's put some resources to it, figure out whether we think it's real. If we do think it's real, then we bring it to a regional campaign.
And on the regional campaign we say okay, we think Florida is going to be the next market, for example. Let's go lockup three sites in Florida that are strategically located. And then we assigned resource to that and a budget to take and make sure that all these things are done in a disciplined manner.
The other regional campaigns are -- obviously, we all know that Ontario has an RFP coming up, so identifying and making sure that you have sites in Ontario that are going to be competitive. Saskatchewan is expected to have a new RFP coming up and we've been very successful in Saskatchewan, so we're watching that market. Same with Nevada Solar.
That actually wraps up the strategic component of the presentation in terms of how we think about investing and when we think about investing. So the next number of slides is all on the development portfolio.
And so this is the CAD1.2 billion that we are so proud of, that my wife is tired of hearing about, and that we are advancing. And obviously, this is divided between solar and wind. It's also divided between construction projects and development projects. We think we've got a healthy mix of both.
But the most meaningful thing about this is the size. We have over CAD115 million in EBITDA growth that is attributed to this. To put that in perspective, APCO's EBITDA growth -- or APCO's EBITDA was CAD155 million in 2014. So this portfolio represents two-thirds of what we've been able to develop in APCO through its entire existence from a generation perspective.
Although this portfolio is impressive, I think we have to talk about how are we continuing to grow it? So this is a funnel. And just to demonstrate how we have things moving through the funnel, we have two meaningful projects that we are very proud of that have come out of that funnel this year.
Cornwall, our first solar project, which is up and operating, has been for a number of quarters now. And the St. Damase project, down on the bottom, which was generating 18 megawatts of power yesterday and all the turbines are up and commissioned. So we are very proud of that.
At the top is the introduction of Bakersfield and the introduction of Odell. And both of those projects are going into this funnel and allowing us to continue our growth.
I'll move to a little bit of specifics on the project Damase. Since it's complete, it's not in that development pipeline, it's not part of the CAD1.2 billion, but it's a project that because it's recently achieved COD, we wanted to run by you.
There's a couple of things to point out here. And that is that the project came in at a very attractive capital cost of about CAD50 million, because we were able to take advantage of some tax credits that made a meaningful reduction in that cost. When you compare that to the EBITDA of CAD6.4 million annually, it's obviously a great driver, which has helped drive that EBITDA to EV ratio down.
The seasonality is also important and you see obviously a strong Q1 and Q4. And we are providing that information to help with understanding the quarterly profile for earnings from Algonquin.
I'm going through the projects in order of achieving COD, so the next project is a Q1 COD for 2015. It's Morse. We've disclosed a lot of information on this project over time.
It's an exciting project. It has a (technical difficulty) capital cost, with an expected EBITDA of just under CAD10 million. And once again, it's got a profile that is typical of wind, with Q1 and Q2 and Q4 all being relatively strong, with Q3 in the summer months being a little bit lower.
Moving next in line is Bakersfield. This is our introduction into California solar. You can see from the photo down on the bottom that a lot of panels are up. We actually have 75% of the panels in place. This project is got a final capital cost of CAD66 million, but net of the tax equity contribution, which is about 40% of the capital, we are looking at CAD40 million.
The other thing to point out here is the seasonality and how well it fits with the wind portfolio, if you look at Q3, with 43% of the EBITDA expected in Q3. And the reason for that is the time of day adjustment in the California PPAs, at least in the two that we have, they've got a massive on-summer peak to take and offset the air-conditioning load that you would see in California.
And obviously, that really drives Q3 results. And you'll see similar in the Bakersfield expansion, which is the incremental 10 megawatts, which has actually a bit more emphasis on Q3. The PPAs are different, they're with different utilities, they have different time of day adjustments, so even though the two projects are located side-by-side, you see a greater concentration in one than the other.
I think the other thing that's exciting about Bakersfield II is, as Mike's pointed out, you'll see a number of our projects are planned in phases. St. Leon I moving to St. Leon II was an important step. Bakersfield I moving to Bakersfield II was an important step. We believe St. Damase and Val Eo are just the first phase of two-phase projects. And you really do get to de-risk and it's a lot easier doing the infill than it is doing the original project.
And so that takes us to Odell. Odell is -- we disclosed a lot of information on Odell in September, but this is an overview. I'd like to point out the strong wind resource as you look at the LCOE calc that Mike went through and you think about what's driving that.
That bigger swept area, that net capacity factor is going way up. It wasn't that long ago that a developer would come in with a 40% net capacity factor and people would be skeptical. And now you're seeing real 50% net capacity factors coming out of projects. And obviously, that drives the revenue up 25%. It does magical things to LCOE.
Once again, we've put out the EBITDA here as well as the quarterly profile. And if there's any questions on these, I'm happy to answer them during the question-and-answer period.
That brings us to the end of the construction projects. We've got three quick development projects which I'll take you through. The layout is a little bit different.
For development projects, it's about four main things. What's your offtake agreement, which is easy. How are you refining that resource estimate to de-risk the project? How are you moving forward through the permitting milestones to get risk out of the project? And then on your construction costs, have you locked it down with contracts, have you done enough engineering to lockdown those prices?
And with Val Eo, we are moving through the permitting progress. We pointed out that we -- the decree from the Environment Ministry is expected in December of this year. We are expecting a Q4 2015 COD. And so we are happy to report that Val Eo is moving along.
Amherst Island, same four categories, same types of work going on. The offtake agreement is obviously locked down. The resource analysis -- it is worth pointing out that we installed a 100-meter met tower, because these will be 100-meter hub heights, so to help reduce the resource risk and understand that resource better before you commit to construction.
We've got over a year of data now from that 100-meter met tower as well as a LiDAR campaign, which is just using essentially laser and radar to take and pick up on wind speeds at higher altitudes than you can do with a met tower.
Permitting status is moving forward. The REA is expected in January or February of 2015 if we pursue some technical changes. We have, based on feedback from liaison committees and documentation and discussions with people on the island.
There's a couple of changes that we could make to the project if we wanted to. We are in discussions with the MOE and the OPA to see whether it makes sense to pursue those. If we did, it would delay construction and delay the permitting a little bit, but they might be worthwhile changes to make and it's something that's under consideration right now.
The final project is Chaplin. And Chaplin, when done, was going to be our largest project until we announced Odell, so things continue to grow. With Chaplin, Morse, and Red Lily, we will be the largest single wind generator in Saskatchewan, which we're proud of. The four same categories are here in terms of offtake agreement, the resource analysis, and the permitting.
And I'll just comment on permitting quickly, in that we finished some baseline studies in the fall. Stantec is finalizing the package for the EA. We expect that to be submitted in December of this year and therefore we'll be moving forward and hopefully have our environmental approval in the first part of 2015 for Chaplin.
That's a summary of the projects. I apologize it gets a little long when you do project after project after project, but I think what I wanted to make sure people were aware of is the entrepreneurial spirit; those five originations staff are dedicated to growing this portfolio and moving it forward. The development team is dedicated to taking the risk out.
And I'm going to turn things over to Todd, who can show in a bit more detail the financial impact that these projects are going to have as we move forward. Thank you.
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Todd Mooney, Algonquin Power & Utilities Corp. - VP, Finance and Administration [21]
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Thank you, Jeff. I like your analogy about developing projects being like raising kids. However, whenever you mentioned all your development projects, I think I'm the kid who is getting thing on his Christmas wish list. Especially when you see the financial impacts that bringing these projects to fruition will provide to the generation business of Algonquin.
These growth initiatives over the next few years will entail capital expenditures of about CAD1.2 billion. With this CAD1.2 billion of capital expenditure, EBITDA over the intervening periods to 2018 will achieve a compound annual growth rate of 21%.
With the development team's ability to unlock value with these growth initiatives, the efficiency of our investments will increase, decreasing our EV to EBITDA ratio over the timeframe from about 10 in 2014 to just over 8 in 2018.
As Jeff highlighted, wind is the key driver of growth in that timeframe. And taking a look at the EBITDA mix for the generation group, you can see that in 2014, wind highlights -- wind accounts for about 66% of the generation group's profitability. In 2018, that will increase to about 81%.
Now it's also important to note that over the next five years, solar will contribute to growth as well. Albeit starting from a smaller base, that growth might not be as evident visually on the charts.
Now with wind being such an important driver of the generation group's profitability, it's important to note that the generation group at Algonquin has carefully selected the location of these investments to enhance geographic diversification. By 2018, geographic diversification will increase to the point where no single state or province will account for more than 25% of the wind group's profits.
To reiterate why this is important, the point that Mike made earlier, the wind resource in each of these geographies is not correlated and hence, the increased geographic diversification will reduce the variability in the generation group's earnings over this timeframe.
Moving into a more detailed look at 2015. As you all know, the wind -- the generation of profits from wind is highly seasonal, with Q1 and Q4 being the highest quarters of EBITDA generation, at about 27% or 28%. Q3, naturally, being the lowest quarter, with about 19% of overall EBITDA from the generation group being generated during the summer months.
Now over the year, for the entire year of 2015, the Algonquin generation group is expected to achieve EBITDA from its generation facilities of about CAD187 million. This is based on P50 production estimates and it's also based on a foreign exchange rate of CAD1.10 per American dollar. And it excludes administration costs, which David highlighted earlier.
With the addition of the new projects, Bakersfield I, St. Damase, and Morse, depreciation is expected to increase in 2015 to around CAD68 million.
Now with a highlighted increased investment in wind and solar in the United States, HLBV, or hypothetical liquidation at book value income, will be an increasingly important element of the generation group's income over the next four or five years.
HLBV represents the accounting method to record the transfer of equity from tax equity partners in these facilities to Algonquin. Tax equity transfers its equity to Algonquin through the monetization of production tax credits, in the case of wind, or investment tax credits, in the case of solar, as well as through the monetization of losses caused by tax depreciation.
Similar to last year, for wind, HLBV income is a function of production, since production leads to production tax credits, with which Algonquin pays the tax equity partner its return.
Starting in 2016, Odell will be a material contributor to the HLBV income that Algonquin is currently earning with its facilities Minonk, Senate, and Sandy Bridge that were acquired from Gamesa in 2012.
In 2015, Algonquin's first American solar project, Bakersfield 1, will add a new element to the HLBV calculation. Based on the ITC, which is monetized upfront by the tax equity investor, however, earned over the first five years of the project, Algonquin will earn approximately CAD18 million of HLBV income for Bakersfield I over that five-year timeframe.
Now in the handout, there is additional detail on the estimation of HLBV income for Algonquin's generation group from 2014 for the next few years.
Now that's a lot of detailed financial data to absorb, but it's important not to lose sight of the big picture. By investing in growth initiatives, Algonquin will reduce risk and increase its geographic diversification. This will drive significant value creation for Algonquin shareholders.
And with that, I'd like to pass it back to Mike for a quick summary of the generation group.
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Mike Snow, Algonquin Power Company - President [22]
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(technical difficulty)
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [23]
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(technical difficulty) raise their hand. We got one in the back from Sean.
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Sean Steuart, TD Securities - Analyst [24]
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It's Sean Steuart from TD. With respect to the solar and wind growth aspirations beyond your contracted pipeline, can you speak to how the PTC and the ITC in the States factor into your longer-term expectations and how you feed that into your strategy?
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Jeff Norman, Algonquin Power & Utilities Corp. - VP of Business Development [25]
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Sure. The PTC and ITC obviously have a direct impact on lowering the competitive cost of either solar or wind. And so they will have an impact on the size of the market. But we believe wind is going to move forward, even without PTCs. It's just the size of the market and the location of the market.
ITCs for solar are here until December 31, 2016, so we still have a reasonable horizon with the ITCs and we'll see whether they get extended. But solar is making tremendous headway in terms of bringing down that LCOE.
So I think no matter how you cut it, both of these modes of generation are going to be significant players over the next 10 years and we'll be watching the PTCs and ITCs to see where we target geographically.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [26]
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Down here.
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Ben Pham, BMO Capital Markets - Analyst [27]
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Ben Pham, BMO Capital Markets. Just a follow-up on a question on the incremental wind capacity that you are baking into your longer-term plans. In addition to the PTC topic, what about the tax equity market? What are you baking in your longer-term plans on tax equity?
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Todd Mooney, Algonquin Power & Utilities Corp. - VP, Finance and Administration [28]
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In terms of return for tax equity or in terms of the availability of tax equity?
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Ben Pham, BMO Capital Markets - Analyst [29]
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It's more on the availability and robustness of the market.
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Todd Mooney, Algonquin Power & Utilities Corp. - VP, Finance and Administration [30]
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Okay. So we certainly see a very robust tax equity market for both wind and solar. There is a number of players -- there's probably 30 tax equity providers of substance in the North American market or in the US market.
We'd love to see more players come into that market and we think the returns are high enough that it should attract additional players, but currently, the returns are sufficient to bring in major players, like JP Morgan and Bank of America, who are contributing and funding the significant projects.
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Ben Pham, BMO Capital Markets - Analyst [31]
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Okay. And then on the solar strategy, the goal to get to 300 megawatts you've highlighted on slide 33. I'm just wondering you've mainly focused on building and developing 10 megawatt, 20 megawatts projects in the past.
And just wondering, is your development team ready to take on larger projects, such as the 100 megawatt context? It seems to be that your sweet spot in wins growing increasingly higher over time in the 200 megawatt size.
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Mike Snow, Algonquin Power Company - President [32]
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Yes, I think it will come down to the market, but building a 100 megawatt solar project would be no problem at all for us to take on from a technical standpoint. Solar projects are relatively easy to construct. They are very repetitive.
The reason I think we're seeing -- that we're playing in the 10 and 20 megawatt area is really trying to take and get the best returns. So there's not as much competition for those smaller assets.
And unlike wind, there's not the challenges in operating a small solar project that you would have with wind. There's a lot of synergies in going big with wind. That's not so much so with solar.
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Ben Pham, BMO Capital Markets - Analyst [33]
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So this path to 300 megawatts, you're likely to take the 10 megawatt to 20 megawatt steps, the smaller steps, than take on 100 to 200 megawatts just to get to that quicker?
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Mike Snow, Algonquin Power Company - President [34]
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I think it's probably more probable that there will be a handful of 10 megawatt and 20 megawatt projects as opposed to 200 or 300 megawatt projects. I think it ultimately will play out in terms of which markets evolve and what transmission capacity is available.
We've certainly participated and looked at 50 megawatt, 60 megawatts, and 100 megawatt projects and portfolios of projects, but I suspect what you'll probably see is a cluster of 10s megawatt and 20s megawatt as the most likely outcome.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [35]
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Any other questions? Matthew?
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Matthew Akman, Scotiabank - Analyst [36]
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Thanks. Matthew Akman, Scotiabank. Jeff, you had a slide that showed different return projections for different types of renewables. And one of the things that is embedded in there, I guess, is some assumption about terminal value.
And I'm wondering how you guys thinking about terminal value now in wind and solar when you do your return assessments? I guess going back a few years for wind, most of the pro formas assumes that wind had pretty much zero terminal value after, say, 20 years or so. Have you changed that? And again, what's your assumption for solar, please. Thanks.
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Jeff Norman, Algonquin Power & Utilities Corp. - VP of Business Development [37]
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Sure, Matthew, thank you. Our view depends on the market that you're in and the robustness of the market, but we believe if you have land control and you have your interconnection access for the long term -- 35 years for a wind or solar project -- that post the expiration of the PPA, if there's a robust market, that asset will still have value.
We don't like taking the rule of thumb that you see a lot of people in the industry do in terms of just applying a cost per megawatt as residual. We like to take and say we know what the resource is, we know what it will cost just to repower it, and we can get forecasted what the market price would be. So we actually run the model out to the full 35 years.
Obviously, some of those assumptions are pretty big estimates, but I would rather estimate them and do that then take a rule of thumb for the residual value.
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Matthew Akman, Scotiabank - Analyst [38]
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Thanks. If I could have one follow-up. You mentioned in development picking a region and tying up property and land. And I guess in places like Florida, that can be -- maybe it's a good time to be buying land in Florida, I don't know.
But it makes me wonder whether the risk is worth that investment relative to tying up something like Odell, where it's basically a go already and you're not taking similar types of development risk.
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Jeff Norman, Algonquin Power & Utilities Corp. - VP of Business Development [39]
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Yes, and I think the answer is somewhere in the center. And that risk-adjusted return, the apex of that risk-adjusted return was between mid and late development. So it actually aligns very much with the Odell project.
And the Odell project, we've been heavily involved with since the spring and we committed to funding some development costs through the summer in exchange for exclusivity. So we took some risk off the table in terms of getting a major T-line permit in the summer, which is what happened before the market saw the announcement.
But I agree that somewhere between locking up sites and working with junior developers, there is a sweet spot. And it varies a little bit by region and even technology. Solar is much cheaper to lock up than wind and a lot more new territory on solar than wind. And so we're constantly kind of looking for the best and the sweetest spot to invest.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [40]
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We've time for one more. Mac, go ahead.
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Mac Whale, Cormark Securities - Analyst [41]
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I just -- I'm curious. You get involved in technologies well before they're at grid parity. What your thoughts, what are your team's thoughts on storage opportunities?
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Jeff Norman, Algonquin Power & Utilities Corp. - VP of Business Development [42]
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Sure. I'm happy to answer that, but I also think people might be getting tired of my voice. I know Mike has got views on storage.
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Mike Snow, Algonquin Power Company - President [43]
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Well, I think, certainly as we look at portfolio with intermittent assets, intermittent generation, storage has to be a part of the future for us. And by looking at where it is today in terms of the capacity in the market for meaningful storage, whether you want to do a peak generation supplement or something on pricing in peak periods, whatever it might be, it's not there yet on a wholesale level and I think our focus at this point is certainly to monitor it and understand what's out there, whether it be flywheel, less gas, or pump storage. We certainly have an eye to it.
And I think during our lunch time presentation with our [BTF] technology, you'll hear it in more depth. So that'll give you an appreciation of I think of where our mindset is at.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [44]
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Okay, so we're going to take a quick break now, just under 15 minutes. Be back at 10:45 and we'll start with our distribution group. Thanks, generation team.
We are going to get started. We have our distribution team on the panel now. We have David Pasieka, Peter Eichler, and Gerald Tremblay. I will do a brief bio for each of them.
David Pasieka joined us in 2010 and is the President of our distribution group. He is responsible for acquiring and managing the portfolio of regulated water, natural gas, and electrical distribution companies across the United States. He has global experience in sales, marketing, integration, operations, and customer service. He has a Bachelor of Science degree, an MBA, and also holds a charter director designation.
To his left, Peter Eichler, who joined us in 2009, focusing on the development of rate case strategy for our utilities in the US and fostering relationships with the regulators across the country. He recently moved into a new role as director of strategic initiatives, where he is focused on the development of alternative fuel strategies, including the development of a virtual pipeline platform, which you will hear more about. Peter holds a Bachelor of Commerce degree, an MBA, and is also a CPA.
And, furthest on the stage is Gerald Tremblay. He joined us way back in 2000. It has been almost 15 years now he has been with us. And he is the VP of Finance and Admin. for the distribution group. He has over 20 years of experience in senior positions with the retail, energy, and utilities space, and has a Bachelor's degree in Social Science with honors in Economics and is also a CPA. So I am going to now turn it over to David Pasieka.
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David Pasieka, Algonquin Power & Utilities Corp. - President of Distribution [45]
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Thank you, Kelly, and good morning to everyone. It is a pleasure to be here for our fifth investor day. It gives me an opportunity to present our distribution story. We will talk about our strategies. We will talk about our tactics and we will also talk about what that all means from a financial indicator perspective.
You know, this is my favorite time of the year and it is not because the snowflakes start to gently drift down. It is not because the kids are getting all excited about Christmas, and it is not about Santa just around the corner. It is about the fact that the temperature is dropping quite significantly and, as you can appreciate, in the gas business, we are moving into our two biggest quarters. So, that is very exciting from a distribution perspective.
Speaking about making money, the goal today will be to talk about a number of things. First of all, we will talk a little bit about utility dynamics. We will talk about our state prosperity, the ROE trends, and some of the mechanisms that we are currently working with, and how we are focused on achieving our returns. We will then shift gears and Peter Eichler will talk a little bit about our growth strategies. And we will wrap it up with a financial summary.
As we think about the North American utility market space, there is probably four key dynamics that are quite important for us. First of all is the abundance and the price of natural gas feedstock and its implications for both the power business and also our generation business.
There is lots of talk about aging infrastructure and, of course, a recognition from the regulators that this plant does need to be replaced and it does need to be reimbursed in a timely manner.
Low interest rates, of course, have led to a lower cost of capital, as David Bronicheski has described earlier. And, of course, that has increased the quest for growth for utilities across North America and fostered a robust M&A marketplace.
And, finally, customers are certainly being influenced by the efficiency programs out there. And this is putting pressure on us to work with our regulators to make sure that we have the appropriate regulatory support and that, internally, we are also focusing on figuring out how to get our operational efficiency up.
In the next 45 minutes, we're going to spend some time talking specifically about these four dynamics and how we are able to capitalize on those in the distribution space.
The US remains a very desirable sector for us to grow in distribution. We have built, over the years, a very solid portfolio of utilities across 10 states, and soon we are going to be operating in the 11th state of Montana. We are clearly diversified by commodity, we are diversified by state and, of course, that helps us increase our earnings predictability. Why is that? Because we haven't put all our eggs into one basket and we are not in one regulatory jurisdiction. So, we have a complete diversity across those two sectors.
Specifically, if you look at 2015, the EBITDA from gas will be about 59% of the total, 19% for water, and 22% for electricity. As we forecast into the future, with the acquisition of Park Water, those numbers will change into a more balanced view -- 47% gas, 21% electricity, and 32% water.
I am pleased to announce that our plans in 2014 are unfolding exactly the way that we described them to you at last investor day. We have put more than CAD190 million of capital to work in our utilities. We have completed two acquisitions, specifically the announcement -- or the announcement of Park Water most recently. And, at the beginning of the year, we bolted on the New England Gas transaction in Massachusetts to our utility fleet.
We have also completed two tuck-ins, one in New Hampshire and another one in Arkansas. And there has also been some progress as we think about trying to put generation into our electrical utility in California. We have made some great progress there from a solar perspective.
The economic conditions in our operating states is definitely improving, but not all of the states have the same economic prosperity. We actually see the state governments aggressively competing with large business for jobs and job creation.
As a gas, water, and electric utility owner, housing starts and getting folks back to work are important indicators and important elements of our central services.
On our two charts here, we have graphed the 11 states that we will be operating in through the next four years. And you can see that the total housing starts are expected to rise over the five-year horizon. At the same time, the unemployment rate has been going down in these 11 states, and it also is expected in the five-year horizon to continue to drop.
From a connection count perspective, we have seen individual utilities grow between 0.5% and 2%, and the customers that operate in our natural gas distribution utilities are obviously showing the most promise or have the most growth potential as there are cost-effective ways to fuel switch off heating oil onto national natural gas. So clearly, being diverse by commodity and state reduces our risk of our distribution portfolio.
S&L notes -- the average ROEs in 2014 have levelized about 9.79% with electric being stable around 10% and the gas down slightly to 9.5% from previous years. This ROE stability happens in the backdrop of those low and sustained low interest rates.
Liberty has averaged throughout 2014 a 9.79% across the portfolio with an average equity thickness of some 56%.
Now, as utility owners, we are putting special emphasis on the impact of customer rates -- on customer rates. We have increased our focus internally on looking at the cost and customer productivity so as we can create some headroom within our utility to invest more capital and not experience excessive rate shock. Our localized model emphasizes a regular and proactive discussion with each one of the regulators to make sure that we remain in sync with their thoughts and comments. Our focus, obviously, is to increase our ability to earn those authorized ROEs through decoupling and tracker mechanisms. These mechanisms are obviously quite critical to allowing us to achieve our authorized returns. The two biggest factors are regulatory lag and inflation. And these are impediments that we have to deal with on a regular basis in our utility to get these returns. We need that constant dialogue with the regulator so as to close the gap of -- close the effect of those two factors to allow us to get to that authorized return.
From last year, you will notice a couple of new diamonds on the chart. Specifically, we have negotiated an accelerated capital recovery mechanism for capital in our Arizona utility. You will notice in the top right-hand corner, in New Hampshire, we have an open dialogue right now on decoupling mechanisms with the commission there in our currently -- in our current rate case in EnergyNorth.
And you will also note the addition of Massachusetts. We have got a full bag of tricks there, all sorts of decoupling tracker accounts and accelerated recovery mechanisms in Mass. And this obviously makes that particular state one of our most attractive from a mechanism perspective.
The decentralized operating model is one of the key enablers for us to increase our earning predictability, and we have long believed that that localized model is one of the key differences in how the regulator treats and looks at our utilities. We have got lots of examples in several states where the commission might actually have a question or a comment or want to have a dialogue with us about a particular customer or a particular complaint. And it is so easy for us being local to actually hop in the car drive down the street and solve the issue real-time as opposed to sending an email or a file or playing some telephone tag. This has worked quite well for us.
After we acquired our portfolio, as many of you have followed the story, it is a portfolio of orphans that we initially had. The regulatory complaints in our utilities has gone down quite significantly in a post-distribution world. And why is this important? Well, it is the regulator who set the rates. So if we can actually demonstrate that we are actually improving the caliber and the quality of service, they will treat us in a fair manner.
One of the side benefits of this local model is having those local eyes and ears on the ground so as we can uncover additional growth opportunities to put organic capital to work. And this is how these two tuck-in acquisitions, the one in Keene, New Hampshire, and the one in Whitehall, Arkansas, actually came to fruition. We had the local team on the ground and said, hey, I heard at the last chamber meeting that this particular utility may be up for sale. And, as a result, we were able to jump on it and do a negotiated transaction in both cases.
Strategy, of course, is developed here in Oakville, and we do execute it consistently across all of our states. So if you showed up in one of our states and went to the adjacent state, you would see the organization is set up exactly the same way with that localized focus on regulatory customer service and local organic growth.
I thought it would be useful to maybe spend a couple of minutes talking about the original orphan in the portfolio, and this is the Calpeco electrical transmission -- electrical distribution company in Lake Tahoe, California. The transaction was done in the 2009 timeframe and we closed it in January of 2011. We filed our first rate case under the distribution brand in 2012, and we were able to actually achieve an ROE of 9.89% with 52% equity thickness, a significant departure in a positive way from the previous owner.
We also were successful in putting in a rate decoupling mechanism, and we also have an accelerated future CapEx mechanism so that we can invest CapEx in the future and still get recovery in the current timeframe. What has this allowed us to do? It has allowed us to put more capital to work in California than the previous owner had been using. We have lowered our risk and we also boosted our returns. It also gave us an opportunity to spend some time with the regulator talking about transmission upgrades in that particular state and also talking about utility-owned generation. And both of those initiatives are well underway.
As an added bonus for California, we were successful in improving both the system reliability, and that ultimately translated into a very solid boost in customer satisfaction.
I am here to say, too, that I think, as we went through the Park Water acquisition process, it was a fairly frothy process with a couple of other players at the table. And I think it was our California relationship with the regulator that we could point to and it actually gave the seller, in this case, Carlyle Infrastructure organization, some comfort that we had the ability to actually close this transaction and we could do it in a time efficient manner.
And, finally, just a little comment on acquisitions. They are a part of our growth strategy, and Peter will describe the three components of our growth strategy in a couple of minutes. But, just to remind everyone on how we get to these acquisitions and what filter do we put on these acquisitions when it comes to the board. Well, there's four filters. The first one is it must be accretive through the first rate case under our watch. It has to be in an attractive regulatory jurisdiction. There has to be some favorable demographics in that state or in that town or in that community so that the organic growth can continue to happen. And there has to be opportunity for us to continue to invest CapEx into that utility. I am pleased to say that the Park Water acquisition hit all four of those criteria -- 74,000 customers, three locations in total, based in two states.
From a modeling perspective, we are anticipating -- we filed the application with the California Commission yesterday and we plan on filing the Montana application in a week or two. And we are anticipating that this transaction will be completed in the fourth quarter of 2015. Clearly, our competitive cost of capital allowed us to acquire this at a little bit of a premium, a bigger premium than we are normally used to, but we were still accretive through that process as a result of that cost of capital.
It is now time to talk a little bit about focused growth and I am going to turn it over to my colleague, Peter Eichler. He is going to lay out the complete plan for the distribution story and you will see how all three of the pieces fit together. It will be focused and impressive. Peter?
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Peter Eichler, Algonquin Power & Utilities Corp. - Director of Strategic Initiatives [46]
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Thank you, David. Good morning, everyone. I am pleased to be talking to you today about our distribution business and our CAD1.1 billion of focused growth opportunities through 2018.
I think if there is two things I would like to leave you with today, it is that this growth strategy is built on mostly organic growth, meaning while we obviously have the Park Water acquisition, approximately $740 million is through investment into our own systems. And secondly is that acquisitions themselves are becoming less and less of an important factor in terms of driving our growth. We obviously continue to look for them, but we feel that there is enough headway within our own distribution systems to make significant growth inroads.
A little bit more about the three types of growth that we are specifically focused on. Firstly, system improvements, which really focuses on rate-based investments.
And, as David touched on, we are focused on two things. Firstly, we want to make sure that anything we invest in has reduced regulatory lag, meaning the returns can start within a 12-month period. And secondly, we want to make sure that we are minimizing rate impacts to our customers. We're also focused on growing our customer base, both by expanding our pipe network, and that is our on-network customer growth, and also, because of the availability of natural gas in the US, we are now also able to capitalize on off-network growth by delivering natural gas to customers who may not yet be on our networks but will be at some point in the future.
In terms of acquisition, we continue to look for opportunities where we can invest at least CAD100 million in any new jurisdiction with supportive regulatory jurisdictions and demographics. And, also, we are continuing to look for opportunities to increase our growth by utilizing tuck-ins such as the Keene Gas acquisition in New Hampshire and our Park Water acquisition in Arkansas. I am going to give you a little bit more detail on each of these.
And so, again, in summary, CAD1.1 billion expected to translate into CAD124 million of EBITDA.
Firstly, on organic growth, as I just touched on a moment ago, we don't view all our rate base investments equally. We pay particular attention to two types of investments, one is where we can invest capital in place of current operating expenditures. And a great example of this is in our California utility. We are looking at investing into a solar farm there which would replace costs that customers currently pay through our PPA with in NV Energy. This is expected to have no impact to rates, but gives us the headroom to invest significant capital.
The second is targeted infrastructure, and targeted infrastructure is really coming on lately with regulators encouraging utilities to make investments in distribution systems that can enhance safety. And I will touch on that a little bit more in just a second.
I think the take-away from this is that this organic growth strategy also comes without the premium of M&A and is also something that is clearly actionable within the context of the current portfolio. Nearly 80% of our capital plan from now through 2018 comes with this low regulatory lag profile of earnings recovery commencing within 12 months.
A little bit more on some of the targeted infrastructure programs. I mentioned this a moment ago. Regulators are really starting to encourage utilities to make investments in their distribution systems to avoid aging infrastructure issues. In our gas portfolio, we currently have these types of programs available in Massachusetts, Missouri, New Hampshire, and Georgia. We were recently able to receive approval for this program in our sewer utilities in Arizona. And we also have a program for large capital investments available in our California utilities. In all of these programs, when you make investments in targeted replacement, you get to earn your rates of return that were authorized in your previous rate case using surcharge mechanisms and you get to implement them without the necessity to go in for another rate case. In other words, your regulatory lag is reduced to typically within a six-month period where you get to commence returns. Over CAD90 million of our CapEx program through 2018 is focused on investments in targeted infrastructure.
Switching to the second type of organic growth that we are focused on, our customer growth, we have two types of growth. In on-network, we are focused on connecting customers that are either currently on our distribution system or can easily be connected through main extensions. Our view is we can add 5,000 customers a year through on-network connection, which roughly translates to about 1% of the Liberty Utilities portfolio in terms of customer growth.
The second exciting opportunity is in off-network growth. And you heard David talk a little bit about the abundance of natural gas with obviously the shale boom. And we are now finding it economic to use compressed natural gas and liquefied natural gas to reach large industrial customers or pockets of residential customers that currently cannot be served by nearby pipelines but at some point in the future may be served when new pipes come through. And this opportunity allows us to plant our flag a little bit early and lay claim to what will eventually be a regulated utility.
We see a potential for 10,000 new customers from off-network growth. And this off-network growth is sometimes called the virtual pipeline as well. And if you can think of the Kinder Morgan project that we announced yesterday in the Northeast direct line, that cuts through approximately 22 communities in northern New Hampshire. One of the proposed routes cuts through 22 communities in northern New Hampshire that currently are not served by natural gas a conservative 50% penetration rate would give the additional 10,000 customers that I just mentioned a moment ago.
The other important element there is the economic benefit to customers. And if you think about a CAD3 or CAD4 gallon of heating oil, that roughly translates to a CAD20 to CAD28 dekatherm of natural gas. That gives a lot of headroom for us to be able to take the gas off our system, compress or liquefy, and deliver it to customers.
Finally, a few comments about acquisition growth. We are continuing to see a strong M&A market persisting in North America and in Q3 of 2014, the average deal size was actually about CAD1 billion a transaction.
We think that the market is persisting due to a few reasons. Obviously, the low cost of capital we have touched on, but, obviously, utilities are also looking at it as a way to continue their distribution growth.
If you think about a company the size of APUC being able to complete a transaction about a third of its size, that would mean that we would be able to complete a transaction somewhere in the CAD1.2 billion to CAD1.5 billion range. But, we feel that, because of our competitive cost of capital and our strong relationship with Emera, we are actually able to compete with acquisitions that are much larger than that as well.
In any transaction that we complete, our focus continues to be on accretion. And what that means from the context of a distribution utility is that an acquisition must be accretive after the first rate case under our ownership. This typically occurs within a year or so.
And, finally, our approach also allows for transactions with larger multiples, such as the Park Water transaction to be completed, because of the follow-on investment opportunities that we see which allow for averaging down of our rate basis investment.
So, in summary, these three focuses of growth are both secured and will allow for CAD1.1 billion of investment through 2018 with an anticipated CAD124 million increase in EBITDA.
And I am now going to turn it over to Gerald, who is going to give you a little bit more detail about the financials.
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Gerald Tremblay, Algonquin Power & Utilities Corp. - VP Finance & Administration [47]
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Thank you, Peter. Good morning, everyone. Today, I wish to provide you with some guiding information on the distribution business 2015 plan as well as some forward-looking information to 2018. I will also be discussing some capital initiatives that we are going to be undertaking over the next four years, along with a status update of our current rate filing and I guess the timing of future rate filings.
The commodity mix for 2015 EBITDA is expected to be 59% gas, 22% electric, and 19% water and wastewater. Earnings for 2015 have been adjusted to accommodate for several rate increases, so we have many of our facilities going in for rate increases. They include EnergyNorth, Missouri, Illinois, Georgia, and Arkansas. So you can see five of those major facilities have rate increases in 2015, of which many of those facilities is their first rate increase since we have acquired them. This amounts to an annualized requested revenue increase of CAD36 million. You could expect for rate increases for these facilities in Q1 for Georgia, Illinois, and Missouri. In Q2, you can expect the rate increase for Arkansas. And, in Q3, you can expect the final increase for New Hampshire EnergyNorth facility.
And, just so everyone understands, we just received approval at December 1, 2014. We have our internal rates for EnergyNorth going in. And the difference between the internal rates and the final rates in Q3 2015 will be retroactive back to January 1, Q4, 2014. So, you can expect that we will have a full year worth of revenue for EnergyNorth based on its final rates in Q3 2015.
We included in the appendices some margin information as well as volume information based on our net revenues.
We estimate the distribution EBITDA for 2015 to be CAD176 million. This translates into an EBITDA increase, based on our 2014 estimate, of 13%. Keep it in mind that the depreciation and amortization expense for 2015 distribution is approximately CAD56 million.
Looking at our EBITDA seasonality for 2015, you can expect 74% of the gas commodity EBITDA to come in in Q4 and Q1, while the remaining with electric, water and wastewater, to be relatively consistent across the four quarters with a slight peak in the warmer months. You could also expect that 38% of the entire EBITDA for Liberty Utilities for all three commodities to come in in Q1.
So, to ensure that we can achieve our 2015 targets, the distribution business continues with its strategy to reduce its risk exposure to temperature changes. And how do we do that? By consistently trying to increase our decoupling mechanisms.
Remember that the cost of electricity and the cost of gas is a 100% flow-through to our current customers, so we have 0% risk on the commodity charge. Georgia, Massachusetts, and Calpeco have further full decoupling mechanisms in place on their distribution charge, which is wonderful for us.
When you take into account the fixed component of all of our facilities across the distribution business, which in essence is like a decoupling charge on its own, and add that to the decoupling mechanism that we have in our three facilities I just spoke about, you can expect that Liberty Utilities on a whole is decoupled at 63%. This is a great news story also because considering that in 2011 we were decoupled at around 46%.
If you take into account the month of November as a prime example, earlier this month or just last week, I think the United States, 50 of their states were below zero with the exception of Arizona, which is good news for us because we have a lot of wastewater treatment plants there and water treatment plants. So, you can see that this week, now that the temperature has kind of want up a little bit -- and right now, just as I talk about it, my heart starts to flutter because I am saying, oh, gosh, I have this variability in weather that is causing our revenues to go up and down. It is really good for us as a company because it reduces our predictive -- it increases our predictive earnings and it is also good for our customers because they don't get huge bills on their decoupling -- on their distribution charges at the end of every month.
And when we decouple, if we are at 63% now and we continue to move that ratio up more and more, if we move up to 80% or 90%, that is a gift that keeps on giving. It is not just for 2015 that we have this decoupling and predictive earnings, but it is for the next five, 10, 15 years.
Slicing and dicing the information in another manner and looking at the decoupling from a commodity point of view for Liberty Utilities, as you can see, it is relatively evenly distributed across all three commodities with 66% decoupling in gas, 60% in electricity, and 64% in water and wastewater. So this further emphasizes that not only do we have predictive earnings across the distribution business as a whole, but we also have predictive earnings across each one of our commodities.
We continue to discuss with the New Hampshire regulator for our Granite State and EnergyNorth facilities are in currently that state we have the most exposure to weather fluctuations. And you will notice that in our EnergyNorth rate filing, as David pointed out earlier, that currently we have asked to increase decoupling over there.
So, moving forward to 2018, you can see that we continue with our diversification strategy. The acquisition of Park Water, along with increased capital spend in our existing facilities to grow the business organically, is shifting the EBITDA mix away from gas and more into water and wastewater.
Gas decreases from 56% in 2014 to 47% in 2018 while water and wastewater increases from 19% to 32%. This allows the distribution group not only to diversify its footprint across the entire nation with further penetration into California and now into the new state of Montana with the acquisition of Park Water, but also across all of our three commodities. This enables us to reduce our seasonality fluctuations, our risk exposure to jurisdictional risk, and also the exposure within a particular modality.
So, in order to grow our business to 2018, Liberty Utilities is constantly trying to find opportunities to grow its business organically. Capital expenditures from 2014 to 2018 is expected to be at CAD1.1 billion with the inclusion of the Park Water acquisition. And we constantly ensure that we are trying to maximize our returns from these capital dollar investments. How do we do that? We ensure that not only do we prioritize our capital spend around rate filings to ensure that we are reducing the regulatory lag as much as possible, but now we begin to spend our capital dollars between rate filings through these accelerated rate mechanisms that was discussed earlier today.
Major capital project initiatives are to maintain our assets, to improve service levels to our workers current customer base, and to grow our current customer base. They include pipeline replacement programs, plant expansion opportunities such as our Lichfield Park Wastewater treatment plant out in Arizona, the Calpeco solar project that Peter had spoken about earlier today. We're constantly looking to upgrade our systems all across all of our facilities to improve service levels to our current customer base, and new customer growth initiatives all contribute to a 79% increase in EBITDA from 2014 to 2018 for an overall CAGR increase of 16%.
We understand the importance of investing capital dollars into our business. It is who we are; it is how we make money. But we do understand the importance of ensuring a rate impact to our customer base. It is for this reason that, from 2015 to 2018, approximately 32% of our capital spend relates to improving service levels to our current customer base, while the remaining 68% really relates to replenishing our capital and also growing our capital for future customers. And when you think about that, the 68% has little to no rate impact on our current customer rates.
And, finally, in order to achieve the increase in EBITDA that we want to get to in 2018, the distribution business will be filing several rate cases in the next four years. As you are aware, and continuing with our strategy, the distribution group plans to file rate cases no more than four years apart from the last rate increase. Some of our facilities may be going in every year, some of them every two years or three years, but none of them will be further out than four years between rate filings. We do this for two reasons. One, because we want to make sure that our customers don't have a rate impact shock. And the second one is we want to make sure that we are constantly replenishing capital into and reinvesting capital into our existing facilities.
Looking at the chart, you can see that Georgia is in every year. We have a wonderful rate mechanism in Georgia of the annual grant where not only every year do we go in to have a rate increase and obtain the return on and of our capital invested dollars with very little regulatory lag, but it also provides for inflationary components built into our operating costs and receive that also. The mechanism there is wonderful, and I wish we could have every one of our states to have that exact mechanism. And it is for that reason that, every time we file a rate case and every time that our local leadership team is speaking to the regulator, that we are constantly looking at increasing our decoupling mechanisms in order to reduce the fluctuation of weather patterns and increase the accelerated rate mechanisms in order to reduce regulatory lag not only just on capital investment dollars but also on operating costs.
So, if there is one key take-away today from my presentation is the distribution business is here to grow its business organically, and we will find opportunities to spend capital dollars to grow it to get it there. We expect to spend CAD1.1 billion by 2018, translating into an EBITDA increase of 79% from 2014 to 2018. And by 2018, our EBITDA should be at about CAD284 million.
So, thank you for that. And now I will pass the baton over to David Pasieka for a summary.
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David Pasieka, Algonquin Power & Utilities Corp. - President of Distribution [48]
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Thanks, Gerald and Peter, for joining me on the panel today to talk about the focused growth in our distribution business. I think, I hope that you feel as excited as we do about the CAD1.1 billion. It brings a tear of joy to my eye as I think about that number. And I also think about the fact that the growth actually comes in three forms.
So it comes in system improvements, it comes in customer organic, and it comes through acquisitions. And we use all three of those mechanisms to deliver on those results. And, as Gerald has previously noted, that if you look at, on a run rate basis, between now and 2018, we are going to add an incremental CAD125 million to the distribution business here at Algonquin. Quite impressive, I would say.
And with that, I will hand it back to our moderator.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [49]
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We're going to move on to our Transmission section next. So, today, we're going to have Ian Robertson and Dick Leehr talk to you a little bit more about our Transmission segment, and to give you a little more color on the Kinder Morgan -- you've waited all morning to hear more about it. So they're going to give you some information about that.
Ian -- obviously, we've introduced him already. I'll give you a little background on Dick. He was recently appointed the President of the Pipeline and Transmission Group, and previously served as our New Hampshire Utility President before that.
Prior to joining us, Dick served as a consultant for utilities developing Northeast infrastructure projects, drawing from the Marcellus and Utica Shale region; and as President of two joint venture pipelines in the Northeast. He has also served as a senior executive in senior executive capacities in the interstate gas pipeline industry over his 40-year career. Dick graduated from John Carroll University with a degree in accounting.
And so I'm going to just pass it off to Ian now.
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [50]
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Thanks, Kelly. For those of you who attended last year, you will recall that we talked about transmission as an element of the Liberty Utilities investment proposition that we had. And we are obviously pursuing our California -- we call it the 625/650 line investment.
We had looked at other opportunities. And I think we have spent the intervening year since we were in front of you last, exploring the sector a little bit more, and determining an appropriate strategy for our organization. And I think we are pleased to, today, be in a position to kind of talk about that strategy, talk a little bit about the opportunities that sit before us, and to give you kind of a formalization of the discussion that we started last year.
So the agenda for the next -- and we are going to try to keep this one a little bit shorter -- the next 35 minutes or so, is I'm going to provide a little bit of background on the sector, the rationale for our interest -- I'm hoping it's self-evident to you, as it is to us; but that's -- we'll talk about it for a little bit -- and our strategy for investment of capital into the sector.
I'll follow-up with a few comments on the electric transmission specifically that we have in front of us. And then I'm going to turn it over to Dick to talk about the natural gas environment; more broadly talk about the congested Northeast region, in which our focus is on; and specifically, I give you a little bit more insight into the recently announced arrangement with Kinder Morgan.
So first, a couple of comments about the sector and our rationale for it. As I said, I kind of hope it goes without saying, but we think it is a logical and aligned investment for us, which is completely consistent with the existing business proposition. I mentioned earlier we are clearly in the generation side of the business. We are in the distribution side of the business. And Lord knows it makes sense for us to connect the two together across the utility value chain.
Our focus is, in this business group, on both natural gas transmission as well as electric transmission. And there are really two objectives behind pursuing these. The first, which is actually common to electric and natural gas, is, to be frank, to earn an attractive risk-adjusted return, which is consistent with the business that we are in already. And we will touch a little bit on it. But the return on equities that are generally granted by the Federal Energy Regulatory Commission, or FERC as it's known, with respect to electric transmission, are at least as high as the ROEs that are being provided on a state regulatory basis for our distribution business. So the returns are attractive.
But the second -- I think the second -- and maybe it's more subtle; maybe not, since we've already talked about it -- is really about planting additional regulated utility distribution flags. And you heard Peter touch on it, but I think it's worth repeating -- which is, to the extent that we can facilitate a natural gas pipeline, which exposes customers who are currently denied the benefits of what's an undeniably compelling economic story because of a lack of pipeline access, what a great win for both sides.
We get to invest in a pipeline which will actually serve new customers, who will get the benefit of a cheaper, plentiful, cleaner fuel. And we'll -- and our distribution group will get the benefit of expanding its business footprint.
With respect to the physical assets -- because you might ask yourself the question is, well, do these assets feel different than the type of assets you have right now in the portfolio? And the short answer is, no. An electric transmission line, to be frank, is really very little different than a high-voltage distribution lin. And Lord knows we've got thousands of miles of those in our system already. And so, we are very comfortable with the physical assets that comprise the sector.
From a regulatory and business model perspective, the electric transmission is a socialized business model. What I mean by that is, it's the exact same as our distribution business. One presses assets into public service. One earns a return on and return of that invested capital, and has one's operating costs reimbursed. It is the utility compact, and it's exactly how the electric transmission business works -- which I will add, with the one added benefit that, in general, it is completely volumetrically decoupled.
You don't track the electrons; you don't know where they are flowing. And your return on -- and your return of your capital is really irrespective of the actual use that the electron makes of your transmission line. And so to the extent that your transmission project is approved for construction by an RTO or an ISO, and you earn your return based on the contributed value of those assets to the model.
On the natural gas side, it tends to be a bilateral business model. And so I mean by that is, one builds a pipeline, and one enters into long-term 20-year contracts with creditworthy shippers, and one earns a return off of those creditworthy shippers. And FERC, who is the regulatory agency that has oversight over the natural gas pipeline, establishes rate constructs under which one needs to operate. But that sounds -- I'm sure it's going through your mind -- a very similar business model to our generation group, where we have long-term power purchase agreements with creditworthy shippers -- or creditworthy offtake customers.
And lastly, operationally. As I said, the group and the team of individuals that we have operating our current assets are completely skilled and capable of operating transmission assets -- though I will point out, obviously, you might ask your customer, well, what do you know about the natural gas transmission pipeline business? And the short answer, well, in this case, we've teamed up with a global leader, Kinder Morgan.
And so, man, I guess we are at school. And -- but I have every confidence that the group will be very fast learners in terms of how to manage the -- a natural gas pipeline. Keeping in mind, of course, that we have thousands of miles of distribution lines all running through our service territories. So it's certainly a core competency that we have.
So let's talk about Algonquin's specific investment strategy for the Transmission and Pipeline sector. Really, it is all about supporting the commodity needs of our existing customers within our existing service territories. I'm sure TransCanada is quaking in their boots as we made our announcement. But, to be frank, they're safe; we're not taking them head-on from a competition perspective. Kinder might be, but we're not.
Our focus is really about -- I call it a niche player. It's about taking advantage of our first-hand knowledge of the service territories we serve right now, and being able to expand our presence in there, investing capital to support those needs. And I think the Northeast Energy Director, or NED, as we refer to it, is a perfect example of that type of investment. Energy North has a significant need for natural gas. The NED is the perfect solution for it. And we are very supportive of the initiative.
With respect to our natural -- or our specific electric focus, California is where you will probably see most of our activities. And two or three reasons why -- California has a significantly growing renewable portfolio standard, one that I'm not sure they are absolutely going to be satisfy with just in-state renewables. And it's important to mention that California has expanded its state borders, if you want to think of it that way, by the CAL ISO now actually bridging out into Nevada.
And so, California -- there's pieces of Nevada that are electrically within California. So to the extent that Nevada has solar opportunities, there is opportunities to build transmission to bring that energy into California.
The second point would be CalPeco's needs. CalPeco is our electric utility on the California side of Lake Tahoe; 50,000 customers need electricity right now. We source all of that electricity actually, frankly, out of Nevada. So we are actually electrically in Nevada. But here is an opportunity to invest capital in transmission to bolster the ties to the West, to connect us more strongly into the Cal ISO.
From a natural gas perspective, we are focused on interstate and intrastate pipelines. So, think of them as pipelines that are within the state as well of those which cross state boundaries. But you will hear that our primary focus is on the congested Northeast. When you think about the Utica and Marcellus Shale fields, they represent the second or third largest natural gas formation in the world.
So think about that -- we've got the Saudi Arabia of natural gas 300 miles to the south of us. And even better than that, we've got 250 miles further down the road from that, a load pocket, which is in desperate need of additional clean-burning fuel. I can't overstate, from my own personal perspective, the significance that shale gas, its availability and its price will have on America's -- I guess arguably resurgence. So maybe that sounds a little grand. But I think, certainly, when you look at the stats for natural gas and shale gas, I hope you come to the same conclusion.
With respect to our focus on investment, how are we going to do it? Right now, we arguably have four ways to grow. In our generation business, we do development and we buy things. In our distribution business, we buy things and we invest organically. And arguably now in the transmission business, we have a couple of other ways to grow. We can go out and buy things -- but to be frank, I will say that if the electric transmission business -- I think Warren Buffett showed us what AltaLink was worth -- that's probably not the best way for us to grow.
But we still have the opportunity to develop pipelines and transmission lines. And that is a core competency of this organization. So I spoke earlier about part of the value of the representation of this business, and the transmission distribution and generation sector, and the opportunity to take advantage of the core competency -- which, up till now, has really rested exclusively within the generation group. Well, here is an opportunity to deploy that core development competency across the Pipeline and Transmission business group.
And lastly from the expected capital investment perspective. It's always nice to start something new with CAD0.5 billion worth of opportunities in front of you. And so while compared to the rest of the business, I get it. We're starting from scratch in the Transmission sector, but man, there's lots to do.
And it's an attractive opportunity set, if you want to think of it that way. And we are thrilled -- arguably maybe even a little bit humbled -- that we have been able to bring CAD400 million worth of investment in the natural gas sector with a partner like Kinder Morgan.
So, a couple of words about the electric transmission space before I turn things over to Dick. The electric transmission space is a socialized business model. I mentioned earlier it's about you invest capital; the RTO says we need the transmission line; you contribute it to the network, and you get to earn a return on and return of at rates established by the FERC. And their ROEs, as I mentioned, are in excess of what we are getting right now. So a great business model -- love it.
The industry underwent a relatively significant change. In 2010, the FERC published for -- a notice for rulemaking purposes of the introduction of something called FERC Rule 1000. And FERC Rule 1000 really set about revitalizing and perhaps introducing competition into a sector that had, up until now, been completely dominated by the incumbent utilities -- who, not surprisingly, after I've described the business characteristics, you can understand they jealously guarded and didn't want anybody playing in their backyard from the transmission perspective.
FERC said, no, I think we should introduce some competition into this sector -- introduced FERC Rule 1000. One of the most significant aspects of it is it introduces the concept that we should have nonincumbent utility participants in generation. And what a great opportunity for us. In some respects, we're a little schizophrenic here. We are the hometown team, from a utilities perspective, in California and New Hampshire. But there are other jurisdictions where we don't own the utilities, so FERC Rule 1000 has significant implications in terms of our ability to participate.
And then lastly, you will hear a little bit about our focus on electric transmission being really specifically focused in and around our existing utilities. And that means California and New Hampshire. But I will say that Ontario, interestingly -- and if you followed it all -- has got a bit of a fledgling investor-owned utility industry underway. They've announced one project so far. There's a couple of others that are being pursued.
And we've certainly got our stick on the ice in that game, with the ideas that, to the extent that the model of investor-owned transmission starts to get some ground in Ontario, we want to play in that game. We've got a couple of projects that we've mentioned on our earnings calls in the past.
But specifically -- I won't go into these, but really, it suffices to say, here's three or four projects; you can see, not surprisingly, they are all centered in and around our California utility on the -- near Lake Tahoe, California. And so they are things that you'll hear about more as time progresses.
So, with that, I'm going to turn things over to Dick to kind of walk you through the natural gas sector and our Kinder Morgan opportunity. Dick?
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Dick Leehr, Algonquin Power & Utilities Corp. - President of Pipelines and Transmission [51]
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Thank you, Ian, and good morning. The purpose of my presentation this morning is to address the natural gas dynamics, the transmission market focus, and to discuss a little about the Kinder Morgan project that was announced yesterday. Just on a vocabulary issue, I know the generation folks used the word pipeline a lot earlier in the presentation. I just want to clarify that when I use the word pipeline, it's hard steel, buried in the ground, running at about 1,000 pounds of pressure.
I'd also echo Ian's remarks that TransCanada is safe. I have a lot of good news to share with you this morning. Let's first talk about natural gas dynamics.
Any North American discussion about natural gas has to address the impact of shale discoveries in North America. As you can see by the chart behind me, the forecast for natural gas production in the United States is expected to exceed 100 billion cubic feet by the year 2040. Natural gas today provides almost 25% of the energy consumed in the United States.
There's some very promising gas facts to take away this morning. There is over 2,700 trillion cubic feet of natural gas recoverable, giving the United States a reserve life index of over 100 years. The United States is the largest producer of natural gas in the world, and Canada follows closely behind in fifth place.
And there is more good news -- the forecasted price of natural gas for the next five years is expected to be below CAD5.00. The NYMEX forecast for the forward curve average is CAD4.03, and Bentex shares that optimistic estimate with a price about CAD0.19 higher. In addition, natural gas is the preferred fossil fuel for reducing greenhouse gas emissions.
So we've talked about the abundant shale gas supply. Let's talk about the market. The pipeline environment, as you know, serves a variety of diverse demands. We have utility customers; we have industrial feedstock customers; LNG exports; and producers. Gas, however, has its big disadvantage in the heating fuel market.
As you can see in the graph on the right-hand side of the slide, we've captured a slide from the EIA that shows the average consumer expenditures between gas and oil heating in the Northeast. The average household is incurring heating costs of less than CAD1,000 when on natural gas; but when using fuel oil, the prices more than double. And this relationship has occurred for several years, and will continue for several years to come, until infrastructure is put in place.
Turning back to the pipeline business model, most of the pipelines are FERC-regulated pipelines. Some are built under state regulation, and have more lax environmental standards and less intrusive in terms of oversight. But for today's discussion, let's focus on the FERC-regulated pipelines.
FERC controls the certification and construction of these projects, and it grants imminent domain under these certificates that it awards. In addition, it ensures the open access to the pipelines under the FERC-regulated tariff that the sponsor accepts. And the rates are set by FERC regulation, unless the market enters in at negotiated rate contracts. And noteworthy to this group is that FERC provides for the recognition of the funds involved in projects that take several years to develop, and provides an allowance for funds used during construction.
Let's talk more about the natural gas pipeline environment. There are expectations that the capital expenditures by the industry will exceed CAD800 billion. And this is caused by the substantial shift of supply sources from traditional basins to the shale basins. This enormous shift is causing tremendous growth opportunities for pipeline investment.
Let's consider the Marcellus Shale formation. It represents the largest single gas field in North America, and it's the second-largest gas field in the world. Estimated reserves are over 1,500 trillion cubic feet for the Marcellus and Utica recoverable reserves. And to add to that, the Haynesville Shale is the third-largest field in the world located on the Texas/Louisiana border.
Given the size of Marcellus, we focus on the Northeast. The Marcellus Utica reserves are 300 miles from the largest consuming region in the United States, the Northeast. Yet prices continue to soar in the Northeast.
As you can see by this chart, the green line represents the Marcellus prices during the last winter period, 2013 and 2014. It ranged just about CAD4.00. Yet the orange line represents the monthly gas contract prices in the Northeast, climbing in excess of CAD30 for one of the months. And if you were to buy spot price gas, you could pay as much as CAD70 during last winter for gas in the Northeast. That differential on that chart is the value of the capacity that this pipeline being built to the Northeast can command.
A number of experts agree there's a shortage of capacity to serve the Northeast. Black & Veatch in 2012 did a study for the Nesco Group, which is the six Northeast states. In addition, ICF International provided a study to Nova Scotia. And the six New England governors signed a joint letter all acknowledging the need for additional infrastructure to serve the Northeast gas demands for the future.
Another significant factor to consider, that most people aren't aware of, is last winter, 8,000 megawatts of gas-fired generation were curtailed during the peak winter period out of 11,000 megawatts of gas-fired generation. That's a startling fact when you consider that that 11,000 megawatts of gas-fired generation represents half of the total electric generation capability in the Northeast. And it's being curtailed during the peak.
More startling is with the retirement of nuclear facilities, like Vermont Yankee, and coal-fired generation in the Northeast, the replacement generation, over 63% of the new generation being constructed is gas-fired. This shortfall in capacity in the Northeast will be exacerbated by any development of LNG export facilities on the Eastern Seaboard, and additional demand by Nova Scotia that currently relies heavily on Canadian production, which is declining.
So with these opportunistic demands in the forecast, what about Northeast supply? This is why we focus on the Northeast.
An important takeaway for you this morning is this slide. This slide shows that the forecasted production growth in the Northeast is expected to reach an additional 10 Bcf a day over the next five years, while all the remaining basins in the United States are only expected to increase 5 Bcf a day. And if these forecasts are accurate, by the year 2019, 30% of the natural gas consumed in the United States will come from the Northeast Basin.
We believe there is four good reasons to invest in infrastructure in the Northeast -- the long-term economic supply available within 300 miles of the largest consuming market; the capacity-constrained corridor with waves of demand we are seeing in the future. We see the continuous displacement of traditional gas supply with Marcellus reserves due to the economic advantage of price and location.
And lastly, we are seeing regulatory initiatives of various states fostering infrastructure development. The state of Maine has an ongoing docket to review surcharging electricity customers to support the development and commitment of infrastructure to serve the state of Maine through pipeline initiatives.
These are all good reasons to invest in the Northeast. So where are we putting our chips?
On the perfect market solution -- the Northeast Energy Direct Project. This is the centerpiece of my presentation today that provides for sponsorship of a landmark project to serve the Northeast, and a great solution for bringing affordable energy to the region. This project will bring firm long-term capacity of over 0.5 Bcf a day to nine Northeast utility customers under long-term creditworthy contracts.
But it also provides a crucial link to serve the Atlantic/Canada markets, the potential for LNG development on the Eastern Seaboard, and desperately needed power generation loads currently curtailed during the winter periods. More importantly, this is the only cross-regional pipeline proposal made by the market.
It has the capacity potential of 2.2 Bcf a day, and it also has long-term parallel expansion opportunities along its path. Most importantly, as Ian referenced, it provides an opportunity to expand our utility footprints in the region. And as you can see from the map, the project originally was going to traverse the red dot -- dotted line on the northern border of Massachusetts.
And due to outreach programs and other concerns raised about the route, Kinder has proposed a reroute and a preferred route turning north to New Hampshire, and then coming east across the New Hampshire service territories that would pick up the 22 communities that Peter referenced. So it provides an opportunity to expand our LNG and CNG businesses in anticipation of a pipeline coming through the region.
And speaking about our customers, how will this project benefit them? Substantially. Had we had the 115,000 decatherms of firm capacity on the system today, the graph on the right shows the pricing advantage that our markets would have enjoyed as a result. The first three columns show the average monthly New Hampshire residential customers' prices over the winter periods for both the gas and electric utility customers. And substituting Marcellus gas and the new capacity, the far right-hand column shows a significant pricing advantage, reducing their cost by not only offsetting the increases over the last three years, but further reductions in energy prices.
In addition, it's the best priced option for the region. The Kinder Morgan project is the most economic proposal of the competitive alternatives we reviewed. Adding these additional residential customers will lower our fixed costs to our utilities. Therefore, we see tremendous upsides for all the utility companies as well as the transmission division.
So what's involved with the partnership with Kinder? As Ian mentioned, we've aligned our interests and our investments with that of Kinder's. Our initial investment opportunity is 2.5% of the project, and we have the ability to ramp that up to 10% prior to certification. This 2.5% participation limits our exposure during development to less than CAD7 million. The upside is, as the project moves forward, and depending on the commitments of the market for long-term capacity, our investment potential is CAD400 million.
The General schedule for the project is development and permitting in 2015 and 2016, with actual construction in 2017 and 2018, with a targeted in-service date of November 2018. The returns on this project are accretive to earnings. The lower end of earnings forecasted is 10% and the high is in excess of 20%.
In addition, there is follow-on expansion opportunities both with the system, extensions of the system, and as I mentioned, with utility expansion potentials as well. From my perspective and experience, this project is about as solid as they come. You've got a permittable route. You've got committed creditworthy shippers long-term to anchor the project. You've got considerable demand for the future forecasted, and you've got an industry leader leading the development and construction of the project to bring substantial energy benefits to the northeast.
This is both an exciting project for the Northeast, which is drawing a lot of attention, and it's a landmark investment for Algonquin. And I am proud to be a part of it. Thank you.
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [52]
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Thanks, Dick. I'm just going to wrap up with a couple of comments here, and we'll -- I'm mindful of Mickey's hands going a little bit overtime here. But just in terms of a couple of comments on the whole transmission sector, I'm hoping that you share my perspective -- it's a logical investment opportunity for us. It is completely consistent with the assets and businesses, and risk profile that currently are associated with the CAD3.8 billion of assets we have right now.
We have an interesting -- and you can see the slide; it says pipeline, but I guess it's, in both senses, both a pipeline of opportunities and actually an investment specifically in a pipeline. And as I said, I think we are humbled and pleased that we've been able to associate with a global leader like Kinder Morgan for the Northeast Energy Direct.
But I will point out that while a crown jewel for the transmission group, it is not the only thing that we intend to pursue in here. And that we will have set our sights in the same way as we did when we got into the distribution business on building a presence in the transmission pipeline business, as well.
So, with that -- questions?
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Unidentified Audience Member [53]
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I just want to clarify the CAD400 million on Northeast Energy. Is that based on 10% ownership?
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [54]
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Correct.
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Unidentified Audience Member [55]
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And that 2.2 Bcf a day?
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [56]
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Yes. So, just to put a little -- a few words around that, the pipe is either a 30-inch or a 36-inch pipe, built out to the 36-inch pipe with the full compression, gets them to 2.2 Bcf a day. That project is around the CAD4 billion total investment mark. Our 10% would be CAD400 million.
And that's spread primarily, from an investment perspective, over 2017 and 2018, since that's the construction window. 2015 and 2016 is the permitting window. As Dick had mentioned, because of the investment structure that we have negotiated with Kinder Morgan, our exposure during that development phase is limited to our 2.5% interest, which, prior to certification of the project by FERC, will limit our exposure to about CAD7 million.
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Unidentified Audience Member [57]
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And what are your thoughts about regulatory constraints with you being a customer as well as an investor? Has there been past cases for this --?
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [58]
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Well, it's interesting you mention it. Obviously, the regulators are generally sensitive to you owning equity in an opportunity that is also used as a -- to serve regulated customers. There's three things -- well, two immediately -- that I see mitigate that issue.
One, specifically in the state of New Hampshire, they look at affiliates as beyond 10% interest. And so to the extent that you own less than 10%, from their perspective, almost by statute, it doesn't create the same affiliate rules.
The second of all -- and I think it's important to put into context of how this pipe came to be, and the shippers that are on it -- currently, there is about 0.5 billion cubic feet committed to the project so far by a collection of nine utilities, I think it is, in the Northeast US, of which Energy North -- which, as you know, is one of ours -- is but one participant.
That negotiation was undertaken as a consortium, and so not done on an individual basis. And so Energy North had little to no influence, if you want to think of it that way, because it was done as a collective. And all of the utilities negotiated the rate together.
And the third point is, it's a socialized rate. The rate that Energy North pays is the same thing that National Grid pays. And so there is really no opportunity through the entire negotiation to influence this in a way that should cause consternation on behalf of the regulators.
And then very lastly, we very much adopted the FERC code of conduct in terms of how the negotiations took place. The negotiations on behalf of Energy North were undertaken by Chico de Font, who's our Vice President of Commodity Procurement. The negotiation of the equity interest for Algonquin was undertaken by Dick. And the two did not share any information. So I think we are highly comfortable that this has been structured in a way that would fully address any affiliate relationship concerns that could arise.
Is that --? Matthew. (multiple speakers) Go ahead, I can hear you.
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Unidentified Audience Member [59]
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(inaudible - microphone inaccessible)
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [60]
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Well, let me start by saying yes to your first question. Obviously, I think we have to manage our exposure on entrepreneurial investment, sort of across the organization. You heard about Jeff talking about -- and I don't know if it was your question about how much money do you really want to put into investing in farmer's fields and greenfield stuff? And how much money do we want to commit to the development of pipelines?
And I totally get the concern that we need to manage that. And we do address it across the whole organization. So I think we need to have at all times an envelope that we are comfortable with from a missionary investment perspective.
I will say, and I'm hoping that there is a recognition on the part of everybody in this room, that we were very motivated to manage our exposure under the Kinder relationship prior to reaching for a certificate. Because I think your past experience, business experience, says that like those things can get out of control quickly. And so you need to make sure that it doesn't pull you in a place that you didn't plan on going.
And I think the relationship of, A, only having 2.5%, and then having a relationship on top of that with Kinder that we could exit our interest, if we so chose, and sort of head -- and say, thanks but no thanks. So we have that opportunity. I think it's been a way to totally limit our exposure. But your comment is absolutely correct -- we need to look across the entire organization against that risk.
The second part of your question, of course, was -- how do you feel about greenfield risk versus tagging on to developers? I think it sort of comes down to scale and opportunity. The case of California, where we are building that 625/650 line, man, we are the right guys to do it. It's kind of being done largely by our distribution group.
But as you start to scale up in size, and you start to think of things like the Northeast Energy Direct, I think it makes total sense that, man, we should be participating and supporting that rather than leading it. And I think the needs of our customers and supporting the needs of our customers is a great entree into opportunities like the Northeast Energy Direct, for which we would look for more of them.
So, I'm hoping that gives you kind of a little bit of comfort that, man, we ain't taking -- Keystone XL ain't on our horizon next (laughter), if that was your next question, so.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [61]
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Nelson, go ahead.
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Nelson Ng, RBC Capital Markets - Analyst [62]
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Ian.
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [63]
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Yes.
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Nelson Ng, RBC Capital Markets - Analyst [64]
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I just wanted to better understand the likelihood of the pipeline progressing. So, I think, currently, you have 0.5 Bcf contracted, and the base volume is about 800,000. I just wanted to understand -- or [8.8].
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [65]
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Sure.
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Nelson Ng, RBC Capital Markets - Analyst [66]
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I just wanted to understand whether you need to wait for it to be fully contracted? Or whether there's any uncontracted risk you are willing to take?
Thus -- sorry, the second part of that question is, I believe Spectra has a project where they are looking to, I think, expand or build out pipelines, so that's technically competing in a sense?
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [67]
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Yes. Yes.
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Nelson Ng, RBC Capital Markets - Analyst [68]
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So I was wondering if there's room for both pipelines to move forward? And how do you kind of look at things from that perspective?
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [69]
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Sure. And let me talk about the go/no-go decision, if you want to think about it on the NED first. Nelson is correct, that when you look at this type with a 30-inch pipe with limited compression, the capacity is about 800,000 a day in terms of -- for that pipeline. And I think we share the perspective of Kinder that a significant portion of that probably needs to be contracted -- I mean, like 7-plus needs to be contracted before people will feel comfortable moving ahead.
The way I think Kinder looks at it, we probably share their perspective. Between now and, let's call it, this time next year, before the FERC certificate is actually filed, gives basically another year to continue the marketing, to lock up not too much additional capacity. If the dynamics that Dick laid out are correct -- and we have every belief that they are -- that this capacity definitely is needed in the Northeast, all one has to look at is the basis that existed last winter.
And with the price differential between heating oil and natural gas, demand is going up; it's not like it's going down. And so that kind of brings me to the second part of your question, which is, does the AIM project -- the Algonquin Infrastructure -- whatever Spectra call it -- is it competitive? Yes. But it's a bit of a different project. As you are probably aware, that Spectra project actually comes from the South, and snakes its way up through Massachusetts up past Boston.
They sort of end up at the same place, but they start in a different locale. And so the dynamics are a little bit different. This one is obviously specifically designed to service Marcellus.
The other thing -- and there's lots of kind of rhetoric that goes back and forth between Kinder and Spectra as to whose pipe is more pricey, and whose one is suffering more risk. I think it's an undeniable observation that the Spectra pipe is traversing more high-impact areas than frankly the Northeast Energy Direct pipe. We obviously are not -- we are supporters of the NED project.
But then that brings me to the third point, which is, to the extent that the differential between heating oil and other fossil fuels and natural gas continues on. The demand for natural gas in the Northeast is only going to increase. So the question would be, is there room for both of those opportunities going forward?
And it's hard not to look at the demand dynamics and say that, could the region use not only the [800,000] a day from the NED but the [650,000] a day from the AIM project and the answer is likely yes. And so, of course, everybody is competing for that creditworthy customer right now; but in the fullness of time, if you look at the congestion on the Tennessee gas pipeline system right now, it's fully contracted. And so I think there's opportunity for more.
Dick, I don't know if you want to add any more to that, or is that --?
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Dick Leehr, Algonquin Power & Utilities Corp. - President of Pipelines and Transmission [70]
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(inaudible) -- and it leads to more costly expansions.
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [71]
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So, I don't know if that's helpful, Nelson?
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [72]
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We have time for one more question, if there are any. No? Okay.
So what we're going to do is -- just one thing to mention before you can go and grab some lunch and then come back.
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [73]
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No, my summary.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [74]
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Oh, yes. We have Ian's summary first, too. But before I hand it over to Ian, (multiple speakers) we had a really nice notebook for you today, which get stuck in the truck under a bunch of snow in Buffalo. But during this morning, they've arrived. So, remember to pick one up on your way out.
I'm going to hand it back to Ian to actually do the summary for the day. Then we can -- you can grab lunch, come back, and Charlie will do his Energy Storage presentation.
Sorry, go ahead.
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Ian Robertson, Algonquin Power & Utilities Corp. - CEO [75]
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The summary. Well, actually, let me just start by, first of all, thanking everybody for coming and giving us this 3.5 hours of your life. And I hope it was useful. And really, there's obviously three things that were thematic from our perspective, and it's probably worth touching on.
First, I hope you walked away today with a perception that we continue the commitment to a strong balance sheet, a conservative balance sheet, a balance sheet with headroom in it, in terms of growing going forward. I totally understand the angst that growth unto itself can generate. And the last thing you need is to exacerbate that angst by having a balance sheet that people start to ask the question of how you're going to finance it.
And I think this is a -- this is certainly fundamental to the way we think about managing our exposure going forward, and this idea of making sure that we don't announce something that we don't have the capacity to finance at the time of the announcement.
The second thing I'm hoping that you walked away comfortable with is the ability of this organization to deliver on the financial commitments that we make. The dividend is sacrosanct. I'm sure I'm speaking for the rest of my fellow Board members -- we understand why people invest in infrastructure. And I'd like to think that the security of our payout ratio, of the ability for this organization to generate EBITDA in 2015 -- if you added up the numbers, that, as the guys were saying, at CAD325 million going forward -- CAD176 million from the distribution, CAD153 million from generation, and less the CAD38 million that David had mentioned from an administration point of view -- it represents significant growth over 2014.
And therefore, I think it is consistent with that 15% target that we've established. But perhaps more importantly, I'm hoping that what my highlight a little earlier is the EPS and FFO per share growth, and the focus that we have on them is consistent with growing the dividend going forward in a way that you all have built into your models.
And then very lastly, we stood here last year -- well, as we stood actually technically across the hall, maybe down a few floors -- talking to you about our pipeline of growth, and that the organization has continued to not only take things out of the bottom of the pipeline, if you will -- finished projects, Cornwall, Stano Mas -- but also add stuff into it.
And the total quantum of that pipeline -- CAD2.8 billion now to answer -- reiterate kind of Matthew's question is, have you guys been looking further afield? Well, we'll always keep our eyes open. But we're kind of hopeful that people look at the size of this organization, the capacity it has to grow, and say, man, these guys are doing the right thing, and they have the opportunities in front of them, and that -- and you can see that the growth is pretty evenly spread across our businesses, with the exciting addition of the Transmission sector.
So, there's the big summary -- I want to say, there's the big summary. But we -- I guess if I had to put a word behind it, it's sort of focused growth, but the same old/same old from our perspective, that we haven't introduced new risks that are causing you pause or giving you pause for concern going forward, and that you feel is comfortable with the proposition we are advancing, as do we.
So, with that, thanks for your time; grab lunch, and you can listen to Charlie's lunch-and-learn right after. So we'll pick that back up. So, thanks much.
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Kelly Castledine, Algonquin Power & Utilities Corp. - Director of IR [76]
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Okay, so, we are going to get going with Charlie's presentation. I'll give you a little background on him. He was with us previously and then rejoined us. When you ask him where he went, he's pretty secretive about it, but -- just kidding. He came back to us in 2012. Couldn't stay away. He is the VP of Technology, providing advisory and oversight support to the senior executive team.
His background includes providing strategic consulting and technical advisory services to a portfolio of alternative energy clients. He has a degree in marine engineering, an MBA, and formerly served as a Lieutenant in the U.S. Navy Reserve. So with that, I will turn it over to Charlie.
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Charlie Ashman, Algonquin Power & Utilities Corp. - VP, Technology [77]
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Welcome, everyone, and thanks for attending this lunch and learn. The subject of today is a little bit about energy storage. And there has already been a question about it. But I have been heavily chastised about this topic, because there is a lot of talk and excitement out there, and yet we are not here talking about the kilowatts or a few megawatts of development that we're going to deploy.
As Kelly said, a little bit about me. I have a marine engineering background. When you are out in the middle of the ocean, when things break, you have to fix them; and you can't run off to Home Depot and buy a case of duct tape, so you have to be quite entrepreneurial.
I spent my first years out of college in Navy nuclear propulsion with General Electric. Kind of went back to the shipping business and built a 125,000 cubic meter LNG tanker, and then served on it as an engineering officer, bringing LNG into the US from Algeria. When things broke on it in the middle of the ocean, it broke really bad.
After leaving, we ended up with a price dispute back in the early 1980s, and I ended up in combustion engineering back in nuclear and took combustion engineering into the robotic and digital age -- again, fixing problems and finding solutions. Then with the decline of the nuclear business, I ended up in traditional power generation, eventually building a facility in California called Sanger Cogen, and that's the facility that Ian bought in 2002.
And went my merry way -- and, as with most projects, it had some issues. And I came back to Ian as a consultant and fixed problems again, and then came on board and repowered Sanger to a modern gas turbine.
I got enticed or seduced, if you will come into joining a biotech firm in Boston in 2008, so I went my merry way and moved from the model of a disciplined, conservative approach to investment to betting the farm on the CEO's ego. Our technology was bacteria. We produce bio-based chemicals.
And I immediately went to business trying to solve the CEO's problems, trying to explain that sugar doesn't cost $0.04; sugar costs $0.25. And you can imagine the issues you would find in a pro forma when your feedstock is -- in the pro forma is one-fourth its actual cost, and half the cost of the capital equipment to build the plant isn't even there.
He didn't really appreciate my honesty and candor in trying to correct the issues. And he did -- he bet the entire company on his ego. The monthly or the daily discussions were our burn rate, which were may be about $5 million a month. And there was no end in sight, and about a couple hundred million dollars, later the Company was finally sold to a foreign national for pennies on the dollar.
And anyway, I made my way to Washington DC and started helping a number of high-tech firms apply for these loan guarantees and grants, if you will, and included Babcock & Wilcox small modular reactor, some of the battery manufacturers. So I got heavily involved in a lot of this technology that is supposed to provide us some solutions going forward in the energy industry.
Being chastised for not being able to stand up and talk about the projects that were actually under construction involving energy storage, as Jeff indicated before, we are somewhat highly disciplined in our approach. We don't take lots of market risk. We don't like to take technology risk.
As Jeff and I talk about this discipline, it is really a code word for risk management; and when I mean risk management, I am talking career management. Because if we were to walk into the Ian's office and say, hey, I've got this great idea. There is all this excitement about energy storage, and I've got a deal to pitch for you, it would take about 15 seconds for the questions to come out.
And when Ian said, well, what is it? Well, we don't quite know yet, but there is a lot of excitement. Well, how are we going to make money? We're not sure yet. There's no way to measure the electrons.
What risk am I at? Well, you can imagine, within about 15 seconds Ian is going to ask me to follow Jeff out that door. And he's going to tell me to leave the mints in the bowl. Then they are going to implement their succession plan for their new Vice President of Technology.
So the purpose of the presentation today is to talk a little bit about what's going on in the market with regard to energy storage, a little bit about the technology and the role that it may or may not play, and what Algonquin is doing to either participate in an opportunity or to understand how these opportunities that other people take will impact our business. One of the things I've been doing ever since I was a whiz kid in high school is teaching, and I always like to put things into some practical aspect, so everybody understands what we are talking about.
With smart grid and time-of-day metering at the house, a typical house in New England uses, perhaps, 900 kilowatt hours a month of electricity. And our typical kilowatt hour costs CAD0.10, and that doesn't include the distribution charge.
But they are talking about time of day metering now, and so maybe in the afternoon during high peak, I may have to pay CAD0.40 or CAD0.50. And I just don't want to pay that kind of money to the utility, so I've got a great idea. I am going to use some of this energy storage knowledge and make my house a little bit better. I decided I'm going to go get me some batteries from Home Depot, and when the prices are high, I'm just going to power up my house and avoid paying that CAD0.40 or CAD0.50 a kilowatt hour.
So I went and got myself a little AAA battery, and I don't know how many of you ever think how much energy actually costs for one of these little devices, because when you looked at our levelized cost of electricity, we are talking, what, CAD0.10 a kilowatt. When you take this little device, the price of electricity from this little AAA battery is about CAD900 a kilowatt hour. And if you were to power your house with this for a month, it would take 642,000 batteries and cost you about CAD800,000. So that idea didn't work, so I figure I would move on to the AA battery.
The AA battery is going to cost me about CAD300,000 to power the house, but I got the number of batteries down to 300,000. So that's not working so well. So I need to get to the rechargeable type. So I figure I will turn to the lead acid battery in my car. I fare a little bit better. I probably need to buy about a couple hundred of these batteries, put them in.
Not only do I have to buy the electricity to charge it, but just to convert that electricity when I need it is going to be about CAD7,700 a month, and that's CAD8.50 a kilowatt hour. So from an energy storage standpoint, I am not doing so well right now. And I'm perhaps going to have to wait until I get that Tesla in my garage, but that's going to cost me another $90,000.
So how do we take all these numbers and start talking into -- put it in the context of: how can you make money, or how is this going to affect our business? Electricity is not like gas. You could hear Dick talk about the pipeline being compressed at 1,000 psi, so the pipeline gets packed. It's nice and compressible. So if you need more gas in your system, you just compress it into the pipeline. If that's not good enough, you get yourself a big cavern or a cave, and you pump it into the ground. And in the worst case you liquefy it and store it as liquefied natural gas.
But electrons aren't compressible. It's one of the things you learn in school. So we have to take those electrons and convert it into another form of energy -- either chemical, mechanical in the form of potential or kinetic, or even thermal. And that's what we are talking about, energy storage, today.
Today we want to talk a little bit about what's going in the market that's driving this thing called energy storage; a little bit about emerging technology, which is different than energy storage that has been around for decades; and what Algonquin is doing to leverage this opportunity, if there is an opportunity. When I first gave this presentation, I think it was to a Board strategy meeting. The title of it was The Next Big Opportunity -- but, really, it ended with a question mark.
We don't know if it's a real business opportunity, but we know that it's an opportunity for someone that is going to affect our business. And we just want to make sure that we are positioned on the right side of that equation, so we benefit one way or the other.
Energy storage has been around for decades. It was in the form of pumped hydro, and I will show you an example of it in a little while. But basically in the old power curve, it looked like a bell curve. As demand went up during the day, you would turn on your more expensive generation as demand got higher until you satisfied all the need. And then folks figured out, well, I've got all these baseload plants.
I grew up in -- my adult life, anyhow, in Connecticut. So we had Millstone Point. There was a couple thousand megawatts of nuclear there that ran baseload, because you couldn't turn it down, and you couldn't turn it off over the weekend or at night.
If you couldn't find enough streetlights to give a discount to to stay on at night, what do you do with all this electricity? They built Mount Tom, and so at night they would fill up a reservoir on the top; and during the day, when you hit those peak curves, that they would discharge the water and generate electricity. And then they wouldn't have to put on those very expensive oil-fired peaking plants to make up the difference.
But things have changed. I use this as an illustration. The upper left-hand corner is perhaps a traffic sign you saw out the middle of nowhere, and you had these PV panels on it. And that was kind of novel back then. It was very expensive to do that.
I can even remember -- it was a banker for Credit Suisse when I sold Sanger to Ian. He was asking me to help him justify putting PV on his house, and this -- he lived in New Jersey. The cost then was about [$]38,000. No matter what you did, the payback was 40, 50 years. And we just don't make business decisions like that when there is not a quick payback.
But about five or six years ago Silver City showed up at Home Depot, and you noticed, gee, my neighbor had a 30-foot level, perhaps. I can see all my neighbors putting up these PV systems. Something is happening.
If you fly over San Francisco today or you are in the International Space Station, and you can color every photovoltaic cell in San Francisco, you can see there is a dramatic number of PV cells on the top of roofs in San Francisco. This concentration of distributed solar and utility solar in certain regions is having a dramatic affect on the network, the electricity network.
As I indicated, their traditional demand curve was a parabolic curve or a typical bell curve that went up and came down the base -- probably somewhat like the yellow line that you see. This is a California ISO curve that was -- which is known as the duck curve, as people refer to it. But it's basically to show the impact on the network. This is projected out to 2020, but of this dramatic amount of solar coming on in midmorning and dropping off in late afternoon, and the dramatic affect it is having on controlling the generation that Cal-ISO has control over from a standpoint of dispatch.
The green line is wind. The yellow line is solar, and this is actually a curve on a spring day where there is a lot of hydro. If you have been to California lately, there is no hydro. They are in a severe drought, so the curve you see is even more dramatic.
What is happening is at perhaps a macro scale, you are seeing a ramp-up in the morning of traditional generation quite rapidly, 8,000 megawatts in two hours. That's quite a bit of power. And then as solar comes on, it's declining, about 6,000 megawatts in two hours. So now generation has to come on and off -- instead of once a day, now twice a day.
The evening demand is going up, so the rate of increase is now 13,500 megawatts in two hours. That's an awful lot of gas turbines or other generators coming on in a very quick period of time. And the actual maximum rate is about 7,000 megawatts in one hour.
The other thing that is happening is as the generation is declining, there is a risk of over-generation. And when you have over-generation and your system isn't compressible, you can't increase the pressure, if you will, of the pipeline, you have to get rid of it. In many cases you have to pay somebody to take it, so you end up with negative pricing. And that's not a very good business model, when you have to pay somebody to take your product. You really want it the other way around. In the last -- this spring and summer we saw a significant increase in the occurrence of negative pricing, probably because of the impact of the drought that's going on.
The other thing you really can't see well on this graph, but if you don't look at the hours and the minutes, but you look at the seconds, and we operate at 60 cycles in the US, so 60 full sine waves a second, but literally down to each sine wave, there is significant variation in the generation coming from solar and from wind as the wind speed changes, as the cloud flies over the panels, et cetera. And that's creating quite a bit of problem for both power quality and stability on the system, and energy storage is meant to resolve some of the problems with that.
This is a little bit closer look. This is a typical three-day snapshot of 2-megawatt solar system. And you can see both day to day and hour to hour, there is a significant amount of variation. When we are looking at distributed energy storage, it's to resolve issues such as this.
With a big pumped hydro, we are talking about basic timeshift of lots of megawatt hours. In this case we're talking about perhaps megawatts for fractions of a second as you zero in second by second. Another benefit it could provide is frequency regulation, so instead of having a large fossil plant, and burning fuel, and having more greenhouse gas emissions, it can be done with no emissions.
Certainly behind the meter customers are concerned about quality; nice, steady, even voltages; and power. The other big benefit about energy storage -- it's just as the issue you might have in New England with the gas pipeline is in order to increase a transmission line, it's very hard to go in there and make small, little incremental increases. You have to spend lots of -- perhaps hundreds of millions of dollars increasing a distribution or a transmission line, and energy storage can be used to take care of those peaks in that constrained area to defer the transmission system upgrade.
The reason I picked the Venn diagram is we now have talked about the market; and we have technologies that are going to solve it. And, hopefully, there is a move of the bottom left-hand circle far enough into the market to give us an opportunity to find some technology to take advantage of and develop a business opportunity. At the same time as we work that our business model, the lower right-hand circle, we hopefully can develop a business model and a business case to move as far up into this, so the intersection of these three will give Algonquin an opportunity to participate.
As we indicated before, the electrical grid -- because electricity is not compressible -- has to stay in balance all the time. Large pumped hydro facilities are great for this transition from periods of day of large amounts of bulk electricity, but you just can't build them everywhere. As I indicated, on the -- well, we will talk about -- on the lower end there is smaller technology that will perhaps be used at both the commercial and at the residential level to benefit those customers.
This is an indication of the typical type of technology. The pumped hydro is exactly what it means. It is essentially a hydro generator, much like the turbines that Algonquin has now. And so while it is generating electricity in high demand, it is taking water from a high reservoir to a low reservoir and creating large amounts of electricity. These can be in hundreds of megawatts, if not thousands of megawatts in size and scale.
Obviously, Algonquin is very comfortable with this type of technology. And if a strategic acquisition came that involved pumped hydro, it wouldn't be hard for us to accept that as a technology risk. But we certainly -- we need to understand the market and the market risks involved.
Compressed air storage is another type that is making an entrance into the market, and this is the equivalent of a gas turbine without injecting fuel and heating the air in between. But the compressor takes the air, puts it into a cavern in the ground, just like we store natural gas. And then when electricity is needed, you release the air through an expander or turbine, and you make electricity.
Again, this technology might be in hundred megawatt or several hundred megawatt size, and you can't build it everywhere. You have to have a cavern or some other large volume of porous rock or structure to inject this air into, and that competes with volumes that might be used for natural gas storage.
The other type of mechanical device is the flywheel technology in the bottom right-hand side, and this looks like a large generator rotor. It's just a large, smooth steel rotor that might weigh tens of thousands of pounds and spins at perhaps tens of thousands of rpm in a vacuum, so there is no drag. You spin it up in a motor form until you need the energy, and then it is stored as kinetic energy. Then as you need electricity, then you turn it -- the electronics turn it into a generator. And you extract electricity.
The problem with this, as we will perhaps see, it's somewhat novel from application at this size. It's quite mature for small, uninterruptible power supplies you might have in a telecom system or whatever else. Rather small. A utility-grade flywheel may only be 200 kilowatts, and that doesn't sound like a lot of electricity. In fact, for the average home you would have to charge and discharge this device, the utility-size flywheel, some 16 times just to power your home. So trying to understand how we take that, and operate it, and make money is going to be a challenge.
On the bottom left-hand side is battery storage. And the large containers you see in the back are nothing but containers full of different types of batteries. That's the DC power supports -- power system. The rest of the technology is quite mature, and it's nothing more than the power electronics that we have for both wind and solar to convert DC or another form of AC into 60-cycle AC, and then a transformer to step it up to the market.
Pumped hydro currently is mature and makes up about 99% of the existing storage market, which means 1% of it is what we are talking about with both flywheels, and batteries, and other technologies. The chart -- the table I used on the bottom is to demonstrate just how much of this technology, this new technology, is not even commercial yet. It's either in demonstration phase or is even in basic R&D phase.
Part of the -- maybe the interesting thing of my job is going behind the garage doors, where these things are invented, and a lot of them are invented in people's garages, just like Apple Computer were. And it somewhat looks like a cross between Back to the Future and Star Trek, with a crazy scientist standing over his device, trying to get it to work. And I have to somehow translate what they're saying into reality.
It's not the kind of technology we are comfortable with, so we have to evaluate each of these for its risk. In many cases a battery device, battery companies have come and gone in the last few years after our federal stimulus package. And we have to be cognizant or take a look at the credit worthiness of these entities -- so, wanting to find out, will they even be in business? And what's going to back up the warranty of their technology?
Another thing that we have to evaluate is what role technology plays in the market. And as we indicated, the larger bulk storage is over to the right, where it as high as 1 gigawatt scale, so you are selling hundreds of megawatts over long periods of time and many, many hours.
On the left-hand side you are selling a little bit of electricity, literally down to 1 kilowatt for fractions of a second. Certainly the UPS power quality isn't necessarily an area that Algonquin would be interested in. And the bulk power management may be, if a strategic opportunity came, but for the vast majority of those opportunities, it's market base. You are buying low and selling high, and that just doesn't fit into our business model.
If that opportunity came, we would have to figure out a way to mitigate that market risk in order to provide the stable returns that we are accustomed to. So it really leaves a transmission and distribution support and load shifting in the middle that Algonquin would either participate in or benefit in.
If you look at many of the levelized costs of energy curves that Mike and Jeff have shown, and it shows the cost of wind and solar coming down -- if you look at publications, there is usually an asterisk there. And if you look at the bottom that explains what the asterisk is, that says excluding transmission and grid support or infrastructure. That is either building more or larger transmission and distribution systems, or that's the storage technology in order to provide the system to operate efficiently when it has this intermittent load or intermittent generation.
Another real challenge we face is the lifecycle. Flywheels, pumped hydro, compressed air storage is more mature robust mechanical technology. And you can see batteries can last anywhere from 100 hours to perhaps 15 years.
Again, that's not the type of investment that Algonquin is accustomed to making, so we are having to spend a lot of time evaluating -- does battery technology play a big part? The lead acid batteries I talked about powering my house, after you discharge them 250 times, you have to replace them. So, again, it's not necessarily the best technology relative to what we are accustomed to.
This just goes to show the price of electricity from energy storage and perhaps -- yes, my title is correct -- added costs. So this is the additional cost after I buy the electricity. So I have to buy, hopefully, at a low rate. Maybe I'd buy it at CAD0.05, and then I have to add this cost back to it. And even with pumped hydro -- and you can see that it's at CAD0.07 a kilowatt, if I buy at CAD0.10 and I had CAD0.07, that's CAD0.17; now I have to sell it at greater than CAD0.17 in order to make money. And so that's why looking at the market arbitrage on this is a little bit different than our traditional market of having everything contracted long-term.
You see that no matter what battery I'm looking at over -- and this is just assuming 250 discharges a year -- for up to eight hours a day, the price of using batteries are 3 to 12 times that of using pumped hydro. So something has to be into it when we're adding up to CAD0.70 to the cost of electricity.
You can easily derive that batteries and flywheels are quite expensive. And we'd perhaps say they're too expensive right now. And we have to figure out: when is the price going to be coming down relative to the other technology we have seen, like photovoltaic cells, et cetera?
And if we buy in now, and we build a system based on the price that we see, perhaps in two or three years prices will be half of that. And we will be in a very difficult position trying to operate a business model with costs twice that of our competitors.
So let's talk a little bit about what Algonquin is doing to see if, in fact, there is a business model that makes sense for us to invest in, or what business -- what energy storage as to enable us to deploy our existing renewable technology.
Just to summarize, some of our challenges, although pumped hydro is kind of tried-and-true, it just can't be built everywhere. You need water and an elevation change with the reservoir. The same thing with compressed air. We just can't build it everywhere.
But we can build batteries and flywheels anywhere -- anywhere with or without water. It only takes a small amount of land to build something that's perhaps in the megawatt class. And I think maybe AES just built -- commissioned the largest battery storage facility in the US. It's only 40 megawatts, and it only takes up a couple acres, so it doesn't take up a lot of land.
We believe, based on some of the analysis, that if storage comes down to installed price of about CAD750 a kilowatt, there will be 14 gigawatts of market available for us to compete in. And current prices, the cheapest flywheel technology we see is about CAD1,000 a kilowatt up to about CAD5,000. And batteries -- even the most mature battery, the sodium sulfur, is in the CAD5,000 a kilowatt range.
The notion that business models are just emerging -- certainly for us, we don't have a good business model when it comes to anything that is perhaps merchant in nature, and there is probably a lot of companies that are perhaps willing to bet. But, again, we have to develop a model that we can ensure Ian that even a small bet is not going to have a detrimental effect to our financial results.
We believe that storage is going to play a role, perhaps, in concentrated regions. And as you can see on the map, there are a number of demonstration projects up and going. The average size of these energy storage projects is less than 1 megawatt. We have some initiatives becoming available to us to participate.
One is the California RFP. And we hope that it's going to be -- and we have heard that it's going to be more of a tolling arrangement, because even the regulators understand there is no transparent market now to value the services the energy storage provides from either frequency regulation, power quality, voltage support, et cetera.
Hawaii has high price of electricity and high renewables, so we will see some movement in that market; New York, as well; and I named Puerto Rico. An island community will benefit significantly from storage, especially if they have renewable -- basically for the timeshift, but also as a bridging technology, so you don't have fossil generators sitting there on idle 365 days a year waiting to respond.
Even a flywheel might give them perhaps 10 or 15 minutes of time, if they lost other generation, to bring up a generator. And actually, just the fuel savings alone would pay for the energy storage device. And it doesn't cost anything in terms of fossil fuel or greenhouse gas emission.
This is a projection of the market that may be available in energy storage. And if you look at 2012, it's perhaps a turning point with dramatic growth we will see going forward. It coincides with, perhaps, the end of the investment period of the US stimulus package. They invested about CAD250 million into these various battery technologies. The technologies are ending their R&D phase and starting to move into demonstration phase.
You can see the vast majority of growth is expected to be in both pumped hydro and compressed air energy storage. Even the more mature battery, the sodium sulfur, is not expected to grow too much. The lithium ion and flow batteries and advanced battery is expected to be the greatest part of the battery market growth in energy storage in the foreseeable future.
Now we want to take a little bit more look at the California market. When they announced 1.3 gigawatts of storage, people in Algonquin got excited. But as you start to look at the legislation, what does that mean? That's 1.3 gigawatts over the next number of years to 2020. Pacific Gas & Electric and SoCal Edison were each tasked with procuring 580 megawatts, but that was going to be adjusted for any energy storage that has been approved and built since 2010.
They are going to have a biannual -- every two years there is going to be a solicitation come out for storage, and they have also given PG&E and SoCal Edison the right to own 50% of that. And so by the time we got to 2014, and we expect the RFP to come out next month, there is only about -- take the 78 minus the customer side, we're looking at about 72 megawatts that we might be able to participate bidding on. PG&E could perhaps own half of that, so we're down to about 30 megawatts of small energy storage projects that one might be able to develop.
Given the number, the risk, I think we believe that Algonquin would perhaps take some small steps. One of the things we're doing is we have looked at our existing infrastructure. This is actually the site that we would consider installing our first energy storage project. It's at one of our facilities.
There is land next door that we have a right to acquire. You can see the transmission line -- that's a 150 kV line going right through the middle of it. To the north side of it is a 12 kV distribution line, so it allows us to bid either way into this RFP.
We're actually discussing at least a development joint venture with a Japanese multinational. I can't tell you who they are, but if you go home and look at your TV set there is a high probability that they made it. That's one of the -- and even they themselves don't quite understand how to make money in this proposition, so you can see that we are treading very carefully on this.
We obviously want a site that is large enough, and easy enough, and designed well enough that we can expand. So perhaps instead of being 1 megawatt or 2 megawatts as a entrance project could be a larger project. And that's assuming that we have a model that is risk-averse enough that Ian would allow us to invest that money into.
Obviously, we would want to take the learning knowledge of either development and success of developing the small project or the knowledge of at least participating in the RFP to go on to other opportunities and perhaps be more successful.
The chart on the bottom basically just gives you an idea that although pumped hydro is mature, it can't go out in the middle of a Central Valley of California. It is not good at doing transmission and distribution support and can't really be built small-scale. And that's why we really are focusing on battery or perhaps flywheel technology for our first entrance project.
The other advantage we have, I guess, for this is more of a -- not -- it's a strategic acquisition, but every facility that Algonquin has within its portfolio, be it distribution or be it generation, perhaps could be a location for storage. And we would leverage that without going out and acquiring other property or other interconnection rights. So it does give us some advantage of doing this where we have those opportunities -- if, in fact, it presents itself with the right business model to invest.
I guess, having said that, if there are any questions I would be glad to answer them. And if there is not, I will say thank you for joining. It was my pleasure, and I look forward to seeing you next year.
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Unidentified Audience Member [78]
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Do you think that the biggest barrier is really an issue around policy? Because if you think about your own business, if you went back in what Algonquin was working on in terms of wind, if that was good to go, you could make -- you could make and put -- and people did -- put up the same thing, saying, oh, it's way too expensive; solar, way too expensive. But you yourself put up a picture of San Francisco. So there is a lot of development when some things fill up the market. Do think that Algonquin has moved on to a place where they can no longer take that risk?
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Charlie Ashman, Algonquin Power & Utilities Corp. - VP, Technology [79]
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I haven't seen Algonquin take risks like that. Even when our competitors went out there and did things pure merchant -- and we could do things pure merchant in wind, and it would probably make more money. People didn't like the volatility of it. And we took the safe route of having a synthetic PPA to ensure the reliability and consistency of the earnings.
It doesn't mean that there may be a small shift to some merchanilist that has to be a very small, minority part of our generation that we'd never put at risk. That's why the project has to be quite small, because a small risk on a small project is perhaps acceptable.
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