Welcome to the Algonquin Power & Utilities Third Quarter 2013 Analyst and Investor Call. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session and instructions will be provided. (Operator Instructions) I would like to remind everyone that this conference call is being recorded today Friday, November 15, 2013. And I will now turn the conference call over to Chris Jarratt, Vice Chair. Please go ahead.

Good morning everyone. Thanks for joining us on our 2013 third quarter conference call. With me on the call today are Ian Robertson, our CEO; David Bronicheski, our CFO; and Kelly Castledine, our Direct of Investor Relations. For your reference additional information on results is available for download from our website algonquinpowerandutilities.com. I’d like to note that in this call we will provide forward some information that relates to future events and expected financial positions that should be considered forward-looking and Kelly is going to add some more to this at the end of call. This morning Ian will discuss the highlights of the quarter. Then David is going to follow with a review of the financial results. We will then open the lines up for questions and I’d ask that you restrict your questions to two and then re-queue if you have any additional questions to allow others the opportunity to participate. Before I hand things over to Ian, I would like to this opportunity to also inform everyone of our upcoming investor morning on November 29th. We will spend the morning outlining our plans for the continued growth and strategic direction of our regulated and non-regulated utilities businesses. Institutional investors, financial analysts, and members of the financial community can register by emailing registration@algonquinpower.com. The event will also be webcasted, so retailer investors and people outside of the Toronto area can also benefit from the information. Details of the webcast can also be obtained by emailing the registration@algonquinpower.com. And with that, I am going to turn things over to Ian.

Thanks Chris. Good morning everyone and thanks for taking the time on your day to join us on our Q3 results call. And thinking a little about the quarter, I’m pleased that the integration of our growth initiatives over the past year continues to [indiscernible] with increases in our revenues, earnings, and cash flow. Let’s put our growth in prospective. By the end of this year, we will have invested over $0.5 billion in accretive investment that I think position us well to deliver continued earnings and dividends growth over the coming years. We do remain focused on building and maintaining a well balanced diverse geographic and business mix within our portfolio. A little more on the growth front. We’re well into construction of our 10 megawatt Cornwall Solar Facility and expect commercial operations early in Q1 of next year. We were pleased that improvements in layout, module capacity through the design phase led to approximately 7% increase in the expected annual energy production from the site. The facility is our first solar project where we’re looking forward to the diversification benefits that the new and low volatility modality will bring to our portfolio going forward. On the utility side, the acquisition of New England Gas Company, which allowed us approximately $75 million utility assets and approximately 50,000 natural gas utility customers in Massachusetts to our Liberty Utilities family is progressing through regulatory approval process. We’re hoping to get this completed by the end of this year. Before I hand things over to David, I’d like to touch a little on the solar generation and the role that we think it can play from a growth and diversification perspective. On the growth side, we see falling LCOE or levelized cost of energy of solar coupled with renewable portfolio standards in the U.S. is driving opportunities for us both on the regulated and non-regulated sites of our house. For APUC the non-regulated side of our business, our power development expertise I think positioned us both in Canada and the U.S. to competitively participate in IPP Utility Scale Solar projects. For Liberty Utilities, Utility-Scale Solar provides significant investment opportunity meeting RPS obligations of renewable portfolio and we see the dramatic up take in distributed solar in U.S. not as a threat but actually as providing interesting opportunities to leverage this significant utility customer footprint that Liberty Utilities has created. From a diversification perspective, solar energy’s lower year-over-year production utility and low variability correlation with our other generation modalities provides a key element in continuing to assist us in de-risking of our portfolio. I will turn things over to David to speak to the Q3 financial result, David?

Thanks Ian and good morning everyone. Overall, our adjusted EBITDA in the third quarter was $40.5 million and this is significantly above the amounts we reported a year ago, but nevertheless we’re at still at good expectation [indiscernible] resources compared to the long term average production, but we’ve nearly doubled our EBITDA when compared to the same quarter a year ago because of all of the growth initiatives that we had put in motion this year. Turning to more detailed results, APCo renewal energy divisions, during the third quarter the division experienced wind resources modestly below expectation and as result generated electricity equal to 95% of the long term projected average resources. It however still represents an increase in overall generation against long term averages when compared to last year’s 83%. As the division generated production at long term projected average resources, our EBITDA would have been approximately $3.9 million than what we reported this quarter. Net energy sales totaled $27 million as compared to $14.4 million in the same period a year ago. The increase is primarily due to the acquisition of Minonk and Senate that occurred late last year and the Shady Oaks facility which was acquired effective January 1st of this year. It's also worth noting that APCo continues to show the benefit of its diversified portfolio of generation assets of hydro, wind and soon to be solar with strong hydro energy production partially offsetting the lower production that we experienced in wind. For the third quarter of this year operating profits totaled $19.7 million. In our thermal energy division with respect to the operating results, they were generally in line with our expectations for the quarter. We posted an operating profit of $5.4 million compared to $3.1 million a year ago. Just looking ahead with respect…

Before we open lines for questions, I would like to provide a brief update on some of our growth and development initiatives. On the APCo side of the business, we do continue to advance development of our 177 megawatt Chaplin Wind project in Saskatchewan and have submitted the environmental impact assessment. You'll note the ENA confirms that through our development work, the expected capital cost of the project have dropped by $15 million. To optimize the value of the tax attributes associated with the project and [indiscernible] we're not a very taxable organization, we do replicate the efficiency of the structure which we previously employed for the Red Lily Wind project. Switching to our 75 megawatt Amherst Island project, the extended time being taken by the Ontario Ministry of the Environment in approving our renewable energy application which was submitted in April has pushed out the expected commercial operation date until the second half of 2015. In Quebec we’re preparing for construction of the first 24 megawatt phase of our 125 megawatt Saint-Damase Wind Project. We've entered into a turbine supply agreement with Intercon and commercial operations is expected to occur in the fourth quarter of next year. We believe that the first phases of each of our Saint-Damase and Val Eo Wind Project will qualify Canadian research conservation expense and consequently the projects will be entitled to refundable tax credits of approximately $40 million in the aggregate. As I’m sure you can appreciate, the effective capital cost reductions from the cash refunds we’ll receive from these credits will have materially positive impact on the economics of the projects. We do plan to submit proposals for the second hundred megawatt phases for each of these projects into Hydro Quebec’s current RFP which is under way. Lastly for APCo, we continue…

(Operator Instructions). And your first question will come from the line of Rupert Merer of National Bank. Please go ahead.

It sounds like you might make me wait till the end of November, but I was wondering if you could give a little more color on your opportunities in solar? Do you anticipate you’ll make any large moves in solar or are they more likely to be incremental rate based?

Solar, I think, my comments were intended to convey that we actually think that solar has a place on both sides of the house. In terms of large moves, I think we probably all kind of acknowledged, 10, 20 megawatts are reasonable solar size projects. It’s on the APCo side of our business. That’s where we’re hunting. So with our large moves in the aggregate you can do a number of those things and it could add up to real money. Individually the projects tend to be, as I said in the 10 to 20 megawatt range. I will and you’re right, I don’t want to give away all those secrets for our November 29 Investor Morning. But, if you’ll look at Calpeco’s RPS obligations in California, even today and as you know they’re growing from 20% to 33% in the next seven years, even today we could see $120 million or about 60 megawatts worth of solar generation be created to meet those obligations. So, I guess, Rupert, we like the idea of solar. As I said, I think solar is posed with its following LCOE to meet group parity over the coming years and I think it’s an exciting and meaningful modality for us.

And then just on the same thing, looking at your growth plans in the near term, you mentioned in the MD&A no plans for equity in the near term. Can you give us an update on where you are with balance sheet and your target leverage ratios?

Well, our balance sheet again, remains relatively conservative. We’re pleased that we got our upgrade to BBB flat from Standards and Poor's. So we do have I think significant flexibility on the balance sheet to help fund our growth initiatives. Further I would like to add there is room in our capital structure for another series of pref shares. So that definitely is something that we're considering particularly, given the are relatively low interest rate environment that we're in and our view is perhaps we want to take advantage of that in the short term to medium term, because 12 months, 18 months, 24 months from now those rates may no longer be there.

Your next question will come from the line of John Safrance of Cantor Fitzgerald. Please go ahead.

Question in New England gas transaction, can you maybe describe sort of what remains on the process and if is there any risk of that maybe sliding into Q1?

Well, we're trying now in the black box phase. We have had all [Indiscernible] the record has been fully [indiscernible] if you will with our position, the position of all the interveners and to be frank, there hasn't been many of them. And the way the process works in [indiscernible] is that record gets submitted if you will to the commission, the deliver it to you behind closed doors and we’re sitting here staring anxiously at the fax machine, because frankly that's how this stuff comes out waiting for it to rain. It went to the commission I will say in late September. So it's been in front of them now for 45 days. All of our regulatory attorneys have suggested that a couple of months is a reasonable period for this sort of process to wind its way out. So what I tell you that it can't slip into early next year, no I wouldn't suggest that it can. I would suggest that the precedent would suggest that it won't. I don't know it that's fine John.

No that is fine, thank you. And with respect to Georgia, where you actually were able to identify fairly early on in process actually opportunities to grow the rate base, are you seeing anything with this at all or do you expect to have a fairly modest growth profile on the rate base.

Are you speaking specifically with respect to Massachusetts?

Geez, more like chicken farm or something like that that you were able to…

You are absolutely right, I just said in Georgia even before we bought it and in this respect maybe this is reflective of our interest in putting capital to work for an asset which is strategic to us but perhaps might have been a little bit more orphan to the original owner. You are right we did put I think $6 million to work to serve a large chicken processing plant called Coke Cook [ph] Foods down in Georgia and it's working [indiscernible] from our perspective. In Massachusetts, I think the opportunities are probably more focused on CNG LNG. You may be aware that the natural gas transmission system into the New England area actually suffers from some material constraints, notwithstanding the existence of the Marcellus shale and other gas producing areas right up in that area. It's difficult to get gas directly to the utilities and so we and our energy north utility and frankly in our soon to be New England gas utilities see a great opportunity to put money to work to expand the CNG LNG capacity there, to ensure that customers don't suffer the impact of that constrained supply system. And so again without giving away our Investor Day punch line, across the utility sector over the next three years, as I said we’ve got line of sight to close to $1 billion worth of growth opportunities and that's pretty broadly based. But if you just to be specific with response to your question, in terms of New England it's primarily CNG LNG investments, John.

And just a quick one, and maybe this is an offline question but for the Granite state and Georgia acquisitions, you have given previous guidance with respect to dekatherms along with seasonality. And it looks like you have sort of changed how you report the amount of dekatherms in a given quarter. So if you add the two previous guidance up, it would be around 21.5 million dekatherms. Is that still something that you feel is a valid number or has that changed a little bit?

We'll probably have to discuss that with you offline because I’m quite sure exactly where you are pulling your numbers from there, John. But let me actually just give you a little bit more color to the guidance that we did give with respect to previous acquisitions. You are absolutely right, we did give kind of annual guidance. And I think it is important with assets that have the material seasonality of something like a natural gas utility, to make sure the expectations are appropriately set. We fully expect to do the exact same thing with New England Gas. And then ultimately sort of compare results against it. So John, after the call, happy to kind of walk through the specific question about a methodology change, I’m not sure I totally understand the numbers you’re pointing to but I’m sure we can get to the bottom of it.

Fair enough. Yes, I just pointing off of the M&A documents, you have on your website. So we can follow up later.

Give us a quick call after and we’ll be happy to walk you through it.

Your next question will come from the line of Nelson Ng of RBC Capital Markets. Please go ahead.

Quick question on the resource conservation tax credit. So what’s the general I guess requirement or what’s the -- what do you need to qualify for that? And also are the credits, like is it that cash tax refund or like are you going to be able to use it and I guess your partner is a municipality. So like how does it benefit, does it get shared, is this real cash or is it kind of tax that would have paid kind of many years down the road? So can you just sort of quantify all that?

Your intuition is leading in the right place in that there are some very specific requirements that the project needs to meet to qualify for it. And I guess the broadest is that really only about 20% of the project can qualify under this CRCE expense classification and it’s really intended as a -- under the federal tax regime to provide deductions for equipment which is largely used for establishing the efficacy of a wind resource. And so the type of constraints are that as I said 20% of the total and so the 24 megawatt that we’re constructing in Saint-Damase and Val Eo, we actually have land and plans for the 125 megawatt. So it meets the 20% test. The turbines have to have spacing of at least a kilometer and half from each other and so that obviously influences the layout of phase. The turbines have to be up and operational for a minimum I think of a 120 days if my memory serves me, where you start construction of phase two. So we’re comfortable that the project meets all the criteria. We have spoken with the taxing authorities and NRK about the project. So I think we’re comfortable that the project qualifies. Specific to your question, that the nature of the use of that deduction really is quite province specific. But given that these projects are in the Quebec, let’s focus there. Quebec has a refundable tax regime where we’ll actually get a check. So, to the extent that we record that expense and expense ultimately was not surprisingly a result in a loss for tax purposes given its deductibility. We’ll actually see a check into the project companies in the aggregate as we mentioned some $40 million. And I think either appreciate the materially positive impact that has on the rate of return, which is earned on the balance of the capital even in phase two -- phase one not [ph] alone moving on to phase two.

And then just back on to phase two in terms of the Quebec Wind RFP. Do you feel that you’re able to meet the $95 per megawatts price cap? Like is it economic at that price or do you have any [indiscernible]?

Yes, I think we’ve got the wind resource at both of our sites, probably Saint-Damase stronger than Val Eo but we’ve got reasonably strong wind resource. The price of equipment, as you kind of evidenced the Chaplin experience is the kind of the wane rather than rise and we remain bullish even in the context of that kind of price cap.

Okay, just one more question then. In terms of Amherst Island, can you talk about the like local opposition and the process and I guess how much are things getting slowed down? I know that there has been some press about the local opposition that you’ve been kind of experiencing for that project?

Sure. Let me start by saying is we’re respectful of everybody’s right to have a difference in perspective on whether the installation of renewable energy is a positive or a negative and so we try to be respectful of that in terms -- and try to be responsive to frankly concerns that get raised to us, even if they happen to go over and above the kind of clear letter of the regulations, we try to be responsive and get information back so that people fully understand what the implications are. In terms of the opposition to wind projects I don’t want to say in general, because I’m sure that it’s specifically focused on Amherst Island, I think it is important to note that the Island and the residency are actually divided. Clearly, there are supporters, people who are keen to lease land to the project and see the project go ahead. And I guess I get it that there are resident and some of them permanent, some of them seasonal who would prefer that the project not go ahead. We believe that the project fully is compliant with all of the requirements in terms of setback. We don’t want to be a bad neighbor and so we’re -- but on the other hand, we think that for us and society, the project has values. So specifically to your question, is that likely to be a delay in getting our approvals, I will point out that the timeframe that we’re in, we’re into a thing administrative review by the Ministry of Energy. We’re kind of right in the middle of the pack as to the timeframes that other projects have taken. So it’s hard for me to say and obviously, we don’t work for the Ministry of Energy and we do speak to them on a regular basis and they’ve been progressing through. They have been asking us whether we have been responding to the issues that are being raised by the constituency who are clearly against the project and we have, but I‘m not sure I can say that a delay has been occasion, specifically because people have been vocal about their opposite, some people didn’t vocal about their opposition. I think it is important to point out and sometimes the vocal minority gets the spotlight. In Loyalist County, there is like 15,000 residents who are collectively going to benefit from significant contributions in terms of road, in terms of taxes, in terms of amenities, contributions and so I think it’s the silent majority who we’re not really hearing from and so that you got to keep it all in perspective. As I said, but ultimately at the end of the day, organizationally we want to be responsive and respective of everybody’s perspective. I don’t know if that is helpful.

Your next question will come from the line of Sean Steuart of TD Securities. Please go head.

Couple of questions. Let’s I guess start with HLBV. I think we understand the mechanics of how it supposed to work but I guess we have been caught a little off guard by the quarter to quarter volatility in the income you’re recording there. Can you give a little of context on how we should think about that income relative to generation of those assets and seasonality. I guess, we’re just trying to gauge how much quarter-to-quarter volatility we should be building in there?

The decrease that you saw in HLBV and I believe we’ve mentioned it in the MD&A is a direct function of the lower energy production in Q3 and particularly, generally production does go down in Q3, but in this quarter in particular we were below the long term average production. If you do the math on $23, which is the price of the PTCs and you multiply that by the difference in energy production between the long term average and what we generated, that pretty much gives you the exact I’ll say decrease in HLBV during the quarter, compared to the like previous couple of quarters.

And I guess the question on the Chaplin CapEx guidance reduction and I take it from your comments Ian, that’s just pressure on turbine costs. Maybe just give us a little context on -- you’ve reduced the CapEx budget there but for some of the other wind developments, you’ve kept it constant. Maybe just detail a little bit what’s going into the revisions there and why that hasn’t filtered into some of the other development projects?

I guess couple of reasons is that not every wind site is created at equal complexity. Terrain you could imagine, can have impacts on the balance of plant cost that go into a project and so at size and scale, the overall impact. Above of that, the Chaplin project as I am sure intuitively you could imagine being built in a solid structure for 100 miles, for economies of scale and efficiency of construction, and certainly I have to say the Chaplin Wind had the most improvement. The other thing is that we’re not using the same turbine at every site. You probably aware for instance in Quebec, you have to use turbines that have certain -- meet certain Quebec [indiscernible] confidence and so we have [indiscernible] to have competitive process in terms of our turbine selection that we do for instance at Chaplin. And so Sean, I hope that gives you kind of little bit of insight into perhaps why it’s not across the board reduction at every site in the same percentage.

Your next question will come from the line of Juan Plessis of Canaccord Genuity. Please go ahead.

Just sticking with Chaplin wind, you mentioned you’re looking at a structure similar to Red Lily to squeeze out the value of the tax benefits. Have you already had discussions with a third party or third parties for this partnership structure and when would you have to expect to have an agreement in place?

Well the short answer is as you know, we actually have a continuing partnership structure with a third party who is involved in our Red Lily project and they have actually been to Red Lily, continued their interests in renewable energy projects. I’d say we have an ideal candidate who we obviously maintained almost monthly discussions with because they are our partners in Red Lily. Our intent at our Investor Day, not just try to lure you there, a little bit more insight and color as to what we mean when we say the efficiency. I think it's not a surprise if you look at our portfolio of growth, Chaplin as a project is probably the one that has the biggest challenges as we think about. On the other hand it also has some significant opportunities in front of it and we think this ability to leverage the tax attributes efficiently will certainly allow that project to catch up on its brethren in our pipeline and on investor morning we’re going to give few more details, Juan.

Also, you mentioned in the MD&A that Liberty Utilities will be setting up a services division to manage water heater rentals among other regulated and non-regulated assets. What other assets do you expect the new services division to manage? And what do you expect to accomplish with this new division?

Well I think as you pointed out, we're going to get into the business certainly on the water heater and actually we should probably extend it gas conversion burner business by requirements when we close in doing a gas acquisition, we're going to pick up 14,000 water heater gas burners. I think - and we actually are [indiscernible] in the Granite [ph] states portfolio. So I think it's a great start to our business that allows us to meet to continue to lever that utility footprint, put capital to work, rate of return back to leveraging relationship of trust that the local utility has with its customer. Actually there is an interesting study that shows utilities that provide kind of a broader range of services, the water rental heaters, that sort of stuff into a bigger customer satisfaction over perhaps the utility that justifies the gas. So it will be seen as a way to generate positive relationship, not only with customers but with the regulators, because they look to seeing satisfied customers. Specifically to the response of your question as to which types of assets that we'll be pursuing, really this is quite measured from our point of view and I certainly don't want people to walk away from our MD&A disclosure or even the answer to this question is, oh my gosh look at the utility, is building a reliant platform or direct energy. That's not really where the focus is and frankly it's on the margin in terms of size. Having said that, I’ve mentioned earlier in my remarks that distributed solar is think a growing opportunity for home owners that help manage their energy costs and we think Liberty Utilities, through its services group could participate in that area. So let's start by saying water heater gas conversion burners and distributed solar, perhaps that is where our focus is. And we'll see where it takes us from there, Juan.

Your next question will come from the line of Jeremy Rosenfield of Desjardins Capital Markets. Please go ahead.

Just a couple of follow up questions. On the tax credits for the Quebec wind farms I just want to make sure and I have it clear; the actual tax credits are not dependent on you actually going through with the second phase for either of the projects? So if you don't get a contract you still could get the tax credits.

That's correct.

Okay Just moving to Long Su [ph], you got business interruption insurance proceeds I think in the third quarter. Can you just let us know if the amounts that you received in the third quarter relate to everything for the year or are there still expected to be receipts sort of in the fourth quarter.

To date we now have all the business interruption insurance now I will say recorded in the revenue that we're going to receive. So as you look at the year-to-date the nine months results that now reflects the full amount of business interruption assurance that we're going to receive and is reflective of the actual lost operating income during that outage.

So in other words you didn't necessarily receive all of the cash for it but it's been accrued in earnings?

We actually now have received all of the cash related to the business interruption insurance part but there is also a property part of the claim as well. That’s ongoing but that obviously is going to relate to capital expenditures.

Okay, perfect I understand. And maybe just one other follow up on the permitting process related to Amherst Island. Just curious if there is actually increased cost associated with the ongoing permitting if you have to conduct additional studies that you hadn’t thought and maybe you can just sort of let us know if that’s material or immaterial?

Sure. Let me start with that, with the punch line. No, it’s not material. And let me give you a little bit more color into the process that we stand right now, just so you can understand the basis for that assertion. The renewable energy application is submitted to the Ministry of the Environment and under a two stage review process by them. The first is a sufficiency review, which has no kind of fixed time associated with it and we are simply waiting for the Ministry of Energy to kick the boxes associated with our application, which you can imagine stands two feet tall to make sure that on a prima fascia level it meets all the requirements. The ministry digs in much deeper than that what’s found like it would require it to do. Hence the expansion of that from the original expectation of 45 days, which is kind of what the guidelines suggested to most of the projects were in the 200 day mark and we’re kind of right in that mid zone. But frankly from our perspective we’re really just sitting here waiting. So it hasn’t translated into more studies. We think the studies are exhaustive. I think that, pardon me as I say, the applications stands two feet tall. And consequently it think that’s the basis for right my saying is this the delay shouldn’t seem to be occasioning increased cost journey.

Next question will come from the line of Ben Pham of BMO Capital Markets. Please go ahead.

Just on your comments about the S&P credit rating upgrade, just curious on just how important maintaining that credit is to you? Are you managing the balance sheet now to not slip a notch on the credit rating spectrum?

Being investment grade is extremely important to us and I think it’s also important to our bondholders as well. We like and obviously BBB minus is investment grade and that’s fine. Our preference is to be BBB flat. We do believe that that’s the level which is optimal for our cost of capital. I think it’s going to bode well for the next bond we put out on both the APCo side and the Liberty Utilities side. There are certain bond investors that are basically excluded from your universe if you’re BBB minus. And so at BBB flat we now have essentially access to the entire public bond market here in Canada. So we’re happy about that. And being BBB flat now will l have beneficial effects in all aspects of our business in terms of the amount of unsecured credit you’re able to get from other counter parties, reduction in LC [ph] costs and so on. So we’re quite pleased with the credit rating upgrade.

Okay, thank for that David. And my second question is on dividend growth just a visibility on that. And I just thought New England closing end of this year and Cornwall coming early next year, do you think you have enough visibility to potentially raise your dividend earlier than when you did this year?

Well, actually arguably this year we raised it earlier than the previous guidance we had given, which is that the Board, while they look at in every quarter, it really get scrutiny at our Q2 Board meeting held in August with just all of our strategic planning session which lays out a five year to 10 year plan to give line of sight to the board. One of them board was considered in Q1 or wait until they are -- I'll say their normally scheduled because it doesn’t sound like, you shouldn’t take it as it being formal process. But the general, that internal guidance, I’m not so sure I think there is probably some value to be gained in the capital markets from of the predictability if you will of looking at that. So let me answer the question. They are the same right now. While it could I think people should notionally think of the Q2 Board meeting in 2014 as the most logical time for us to look at and raise dividend.

Your next question will come from the line of Matthew Akman of Scotia Bank. Please go ahead.

Ian, I noticed that in the back of the MD&A, a lot of the governance stuff, related parties stuff was cleaned up, in the quarter. I’m just wondering if you can comment on kind of the process and the benefits of having resolved those issues.

Sure. Let me start by saying, I’d actually argue that the process of cleaning these up largely was say concluded because that perhaps where part of problem was but agreement had been reached well over a year and bit ago in terms of each of those items. I think really by your question. from the materiality of those individual issues was relatively slow but it had currently taken on a life of its own in some respect and so after this quarter I think the events of early -- in Q3 where people raise this as a potential, [indiscernible] concern for continued self-healing which was just so completely the [indiscernible] that the way the Board looks at it. We said, let’s just get this thing finished. And so there was a bit of push on and we won’t say it was very hard because it was it a little bit spread between management and the company in terms of revolution moment it was really just completing the paper work. So, well, I would say it was nothing to ask as the agreement was already done. I was hoping that the capital markets views us as being responsive to a concern that gets raised because even if we don’t think it’s valid, to the extent the capital market thinks it is, it is.

Just one other question, I don’t know if it’s for David or Chris but it has to do with the energy form waste facility. I think the guidance was looking to maybe finalize that in the first quarter. I’m just wondering what stage you’re at? Do you have kind of offers or it is just kind of preliminary discussions or where we are in the process?

It’s Chris, Mathew and yes, we are well down the road with primarily one and possibly two people and its well beyond the preliminary discussion phase.

Good. And you’re feeling comfortable that it will result in an outcome that’s consistent with the financial impact that you’ve recorded.

Yes. And we still stand by that and we’re as I say just trying to finalize things now.

(Operator Instructions) Your next question will come from the line of Robert Catellier of Macquarie. Please go ahead.

Mostly questions are answered but I did want to have a follow up on the Liberty Utilities Services Division. Specifically I’m wondering some of CNG LNG initiatives, investment by occur in that segment. I think there has been circumstances with other utilities where that’s actually recorded outside the utility and in a business services division?

Well, it’s certainly depends on which state which utility. To be frank for, in our phase in New England, energy north would likely be recording those assets as included in rate phase simply because they are primarily there to reduce the volatility of winter constrained gas supplies and so think of them as the alternative to a pipeline if you want to think of it that way. So, we’re generally heading toward more regulation, rather than less regulation. As you know Ro, our business proposition is sort of the trade away, that the speculative upside that comes from merchant assets for the stability and downside protection of regulated or contracted assets and so our general focus and again as a little bit teaser that come to our investor morning, that $1 billion of growth that we’re eluting to over the coming years, is just the preponderance of it is focused on regulated assets. So please don’t take the discussion of our [indiscernible] division as a strategic shift from that orientation.

The strategic shift that was invented -- to be honest it just some of those assets have on occasion attracted much high returns and you’d ultimately get in a rate base methodology. Of course it does open you up to I guess less stable cash flow streams than the utility would generate but for the incremental returns, it might be worth it.

Well, isn’t that always the teaser and this is where I think we have to disciplined and stick to the way we think of the world and I know you didn’t ask the question but I’ll give you a little bit of insight that again another teaser for our investor morning, you know there was unhedged energy at our Camisa project in the U.S. and we intend to actually enter into a variable quantity fixed price hedge for all of the un-hedged energy at those projects. We'll obviously give you some details in terms of the pricing a bit, but I think you should, the take away from that is, we very much are focused on, as I kind of in my closing comments said, building a business that uses very conservative assets but levers our entrepreneurial experience to generate double digit earnings and dividend growth. But that doesn't mean we need to start to step out to change the risk profile, but I get it.

Okay, just to follow up on that, in your presentation you have about, call it roughly $300 million over the next few years to invest in rate base and I'm just wondering how much of that is actually approved under rate cases and how much is still open to requiring approvals?

Well let me start by saying that that $300 million as you are aware, was a '13, '14 and '15 estimate. It was about a $100 million in '13 and we closing in on getting that done and pretty much every dollar that we put out is in projects that don’t have, if you will regulatory risk associated with them. It's not speculative as to whether those assets are used and useful for regulated purposes and so we don’t really take that kind of regulatory risk. As we look forward to the '14, '15 and '16 period and as I said I think we have surfaced substantially more investment opportunities totaling over that three year period close to $1 billion, most of it kept back end loaded to '15 and '16, but again it's about ensuring that we would never put a dollar out if we thought there was risk of imprudence being determined by the rate payers, by the regulators. I'll give you an example of that type of assets. In our '14, '15 and '16 investment plan, automatic meter reading infrastructure, which has general support across the regulatory spectrum is something that we’re going to pursue. I don’t anticipate any regulatory risk as to whether those assets would be included for rate making purposes. Obviously we’ll have and it's different in different states, the normal lag, the regulatory lag that comes with that investment going forward. But again in general the focus is on things that has a near term recovery as well, but we're going to give you lots of details of that on the 29th, Rob.

Okay then can we conclude that none of the CNG or LNG is included in those rate base investments you're planning in the $300 million but might be included in the larger $1 billion figure?

I say that yes, in the first $300 million it's pretty nominal. I think that's an area that has developed since we since our, that initial CapEx forecast had been released and so consequently it's a much more significant part going forward. But I will add in regulated transition assets are also a significant part of that as well and this you know they are FERK regulated rather than state regulated, but again are regulated returns.

And Mr. Robertson, there are no further questions at this time. Please continue.

Great well, in wrapping up, thanks everyone. We, I'm looking at the clock on the wall and Nicky's big hand hasn't hit the 12 and so we're out in less than an hour. And so thanks for taking the time. I do hope you can join us on the 29th for our Investor Day and if not, it will be webcast. So please join us via the web and you can stay on the line, you can listen to Kelly's always riveting disclaimer.

Certain written and oral statements contained in this call are forward-looking in the meaning of certain securities laws and reflect the views of Algonquin & Utilities Corp. with respect of future event based upon assumptions relating to among others, the performance of the Company’s assets and the business, financial and regulatory climates in which it operates. These forward-looking statements include, among others, statements with respect to the expected performance of the Company, its future plans and its dividends to shareholders. Since forward looking statements relate to future events and conditions, by their very nature they require us to make assumptions and involve inherent risks and uncertainties. We caution that although we believe our assumptions are reasonable in the circumstances, these risks and uncertainties give rise to the possibility that our actual results may differ materially from the expectations set out in the forward-looking statements. Material risk factors include those presented in the Company’s annual financial results, the annual information form and most recent quarterly management’s discussion and analysis. Given these risks, undue reliance should not be placed on forward-looking statements, which apply only as of their dates. Except as required by law, the Company does not intend to update or revise any forward-looking statements, whether as a result of new information, future developments or otherwise.

Thank you. Ladies and gentlemen, this does conclude the conference call for today. Again we thank you for your participation and you may now disconnect your lines.