Ian Robertson – Chief Executive Officer Chris Jarratt – Vice Chairman David Bronicheski – Chief Financial Officer Kelly Castledine – Investor Relations

Nelson Ng – RBC Capital Markets Juan Plessis – Canaccord Genuity Rupert Merer – National Bank John Safrance – Cantor Fitzgerald Jeremy Rosenfield - Desjardins Capital Markets Robert Catellier - Macquarie Matthew Akman of Scotiabank Sean Steuart - TD Securities

Thank you. Good morning everyone.

Thanks for joining us on our 2013 second quarter conference call. With me on the call today are Ian Robertson, our Chief Executive Officer; David Bronicheski, our Chief Financial Officer; and Kelly Castledine, our Direct of Investor Relations.

For your reference additional information on the result is available for download on our website at algonquinpowerandutilities.com. I would 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 Castledine will be back at the end of this call to provide further details of those. This morning Ian will discuss the highlights of the quarter and David will follow with a review of the financial results.

And then we’ll open the lines up for questions. We would request that you restrict your questions to two and then re-queue if you have any additional questions to allow others the opportunity to participate.

And with that I am going to now hand it over to Ian.

Thanks Chris. And good morning everyone and thanks for joining us on the call today.

I like to start by saying that in looking at the financial results of the quarter it is gratifying to see that the stability of our existing assets have combined with the positive impact of our growth initiatives and those are reflected in our cash flows and earnings. It’s probably fair to say that our recent regulated utility and US wind farm acquisitions are delivering the results that we had promised to our shareholders.

The acquisition and successful operational integration of these assets I believe are important evidence of the ability of our company to develop and execute on the successful growth strategy and we believe that these businesses will continue to strongly contribute to our total shareholder return proposition. Continuing on the growth front, the acquisition of New England Gas Company, a gas utility in Massachusetts that allows 33,000 natural gas utility customers to be Liberty Utilities family is progressing through regulatory approval and we expect it to be completed in the second half of this year.

As a bit of a follow-up on our portfolio realignment initiative that I discussed in the past couple of quarters, I want to confirm that during the quarter we successfully completed the sale of 9 of the 10 small hydro facilities that were deemed no longer be strategic to our operations and respectively we’ve received partial proceeds of approximately $23 million. The last of these facilities is expected to be sold by the end of the year.

Before I hand things over to David, I think I’d be remiss if I did not throw a couple of quick comments on the recent weakness in the capital markets, which might be ascribed to concern over the rising interest rates. When we understand the impact of such externalities on investor expectations, it’s probably important to individually assess each company the impact of a higher cost of capital might have on the ability to deliver shareholder value.

In Algonquin's case, the material proportion of our earnings coming from Liberty Utilities participation in the regulated utility sector and the robustness of APCo’s project development pipeline we believe significantly mitigate the potential impact of higher interest rates of our business. To be more specific, for Liberty Utilities interest costs as you’re probably aware are generally a pass-through expense to rate payers.

For APCo, while the interest costs we acknowledge are an important driver in IPP value, there are some important considerations that preserve the value of the existing power development pipeline. Firstly, the economics implicit in the PPAs comprising our pipeline were premise on materially higher interest rates than the current environment.

Secondly, most (inaudible) consumer price indexation which should be positively correlated with higher interest costs. And lastly, the IPP industry has seen a continuing reduction in equipment costs and improvement in energy capture efficiencies, particularly in the wind sector.

All of these factors together worked to ensure that we can continue to deliver accretive value to shareholders from our pipeline. We believe that success in an environment of rising [material] requirements will go to those organizations that can’t deliver such continuing accretive earnings and capital growth to support a rising dividend.

But we do continue to identify new accretive acquisition development opportunities (inaudible) in APCo, we are confident that ApCo’s existing $800 million contracted power pipeline and identified near term utility CapEx opportunities within Liberty Utilities of over $300 million will provide the earnings and cash accretion need to satisfy any market concerns over the ability of our dividend to remain compelling. With that, I am going to hand things over to David to speak specifically to the Q2 financial results.

David?

Thanks Ian. Good morning everybody.

We are pleased to be reporting continued strong operating results from our expanded portfolio of assets from Liberty Utilities and APCo, these results in our view demonstrate the strengthened benefits of our business model. And for the quarter, we had revenues of 148.8 million and that compares to 58.7 million a year ago and our EBITDA in the quarter was 56 million and that compares quite favorably to 21.8 million a year ago.

So now a bit more detail about our operating subsidiaries, beginning with Algonquin Power, or APCo, as Ian mentioned we divested of our small US hydros very near the end of the quarter and therefore their results are now classified as discontinued operations in our financial statements. During the second quarter of 2013 the division experienced very good hydrology and wind natural resources generating electricity equal to approximately 99% of long-term projected averages which is in line with the same quarter last year.

Net energy sales totaled 35.9 million as compared to 19.8 million in the same period a year ago. The increase is primarily due to the acquisition of Sandy Ridge, Minonk, Senate and Shady Oaks wind facilities.

During the quarter a strong long term average resources in Ontario, Quebec, Manitoba and Texas offset lower long term average resources in the Maritimes, Saskatchewan, Illinois and Pennsylvania. This in our view demonstrates the value of the geographic and modality diversification that we have within APCo’s renewable energy portfolio.

On balance we are pleased with the performance of our new US wind farms and the benefits that they are bringing to our overall portfolio mix. For second-quarter of 2013 operating profit totaled 36.4 million as compared to 15.9 million during the same period of 2012, representing a $20.5 million increase.

In our thermal energy division, during the quarter we conducted a strategic review of the opportunities available for our energy from waste or EFW facility and concluded that it is no longer considered strategic to our ongoing operations. As a result, we will now pursue options to divest the facility.

The assets have been written down to their estimated fair value less the cost of sale which resulted in a one-time write-down of $35.7 million in the second quarter of 2013. The operating results from EFW are now classified got as discontinued operations in our financial statements.

With respect to the operating results from the thermal energy division operations were generally in line with their expectations for the quarter posting an operating profit of $3 million compared to 2.5 million during the same period a year ago. Looking ahead to the next quarter, for the third quarter, our renewable energy division is expected to perform based on long-term average resource conditions for wind and hydrology.

Our Long Sault facility has three of four generators back in service as of the second quarter and given the seasonality of production we are now capturing all of the energy production at that facility. We expect to have all units back online in the third quarter.

For our thermal division, we have no planned outages for the remainder of the year. The Sanger facility is expected to perform at comparable levels to historic results, and the repower (inaudible) facility will operate in line with quarterly performance from the latter half of 2012 that we achieved after the (inaudible).

Within Liberty Utilities in the second quarter, Liberty Utilities reported an operating profit of 23.5 million compared to 8.6 million a year ago and the increase coming from our acquisitions. In our West division, during the second quarter wastewater revenue was $10 million in line with the same period a year ago and net electricity revenue was $9 million compared to $6 million US a year ago and this was mainly due to the rate cases primarily at our Calpeco facility that came into effect on January 1.

In our central division, the region’s water distribution and wastewater treatment revenue of US $4.5 million was higher than 2.4 million a year ago due to the addition of the Pine Bluff Water System to our portfolio and also during Q1 our Liberty Utilities central net revenue from the Midwest Gas Utilities was $6.8 million. And in the east net utility sales of gas and electric totaled $22.2 million.

As a result of assets being acquired in the third quarter of 2012, there are obviously no comparable results for year ago. Looking ahead to the next year, we are expecting continued modest customer growth throughout our service territories in the Liberty Utilities west region.

Probably just a short mention of our recent financing activities subsequent to the end of the quarter, we closed our US $125 million long term private placement in the US using Liberty Utilities’ existing investment debt platform. The proceeds were used to repay the US $100 million term loan drawn on April 1 and also for general corporate purposes.

I'll turn things back over to Ian.

Thanks David. And just before we open up the lines for questions, I will provide a quick update on some of our growth and development initiatives.

On the APCo side of the business we did begin construction on the 10 MW Cornwall Solar facility in the quarter and we do expect to complete construction late next quarter. The facilities will be the first solar project within the APCo portfolio and we see it adding an additional approximately 13 gigawatt hours of production to the business annually.

Out in Saskatchewan our 23 MW wind project located near Morris, Saskatchewan has now received all necessary environmental authorities to proceed construction. The completion of the interconnection facilities by (inaudible) Power is actually now the gating items to the commencement of project construction and we expect that to occur mid next year.

Elsewhere in Saskatchewan we continue to advance the development of our 177 MW Chaplin wind project and expect it to meet the initial environmental impact assessment to the Saskatchewan environmental assessment branch this year. We did submit the renewable energy approval application for our 75 MW Amherst Island, an Ontario based wind project in April.

And subject to the receipt of the re-approval, expect the construction could commence shortly thereafter with construction typically 12 to 18 months. And finally, moving east to Quebec, our two wind development in Quebec continued to advance with the St.

Damase wind project scheduled to commence construction later this year and the completion of an (inaudible) for our Val Eo wind project located near Saint-Gédéon held in advance of submitting the environmental impact study later this quarter. Within Liberty Utilities we did successfully complete the acquisition of the Arkansas Water Utility and Georgia Gas Utility and are planning for the closing of New England Gas in the second half of this year.

Our Regulatory Affairs team is diligently through several significant rate cases which combined total revenue requirement increase of $18 million given the significance of this, I would encourage you to review the specific details of these rate cases in our future disclosures. Lastly for Liberty Utilities, I want to highlight that our focus has been, frankly continues to be on growing the utility business through accretive acquisition.

The increased scope of our existing regulated utility businesses is providing opportunities for prudent investment in the system and efficiently growing our rate case organically. We do remain on track with the investment of approximately $100 million of capital in regulated utilities this year and that’s primarily focused on the areas which support such investment with return (inaudible) and other regulatory mechanisms to provide strong return on these investments.

As we look to the remainder of 2013 we will obviously continue to work on finding value creating developments and acquisitions for our business in order to grow cash flow and further strengthen our stable base of earnings all contributing to growing shareholder value. With that, operator, I would like to open the lines up for question and answer session.

Just a quick question on the interest expense at the corporate level, could you provide some color as to how it went from I think $2.9 million interest expense in Q1 to a $2.2 million interest income in Q2. Is it derivatives or slopes, or I am just wondering how did that reverse in Q2?

In terms of the level – I am not sure your comment was interest expense turning interest income, I am not quite sure I understand that. Certainly a contributing factor in our interest rate we had more debt outstanding in the second quarter as a result of closing the Georgia acquisition, so that was certainly a factor contributing to our higher interest rates during the quarter.

I am not sure if that completely answers your question.

No, I can just follow up with here after the call.

I am not quite sure I am understanding your point with respect to I guess interest income or interest expense.

Next question I had was in terms of the admin costs, they were higher in Q2. I was just wondering whether that represents the kind of run rate going forward given the increased size of the business or were there specific items relating to or one-time items relating to – in that 7.3 million?

What you saw in Q2 was actually -- what we did internally was form what we call the central service group, called Liberty [Thomson] business services. And so as a result of that their previously expenses that would've been classified as operating expenses that are now being into the central service function and now classified in admin costs.

So while, yes that the admin costs are close to what you are expecting on a run rate basis I think the other part that you – it is probably less obvious is the fact that within the operating expenses there would've been an offset or a good portion of that step-up in admin costs.

And just one last one question, it looks like there is roughly 22 million of CapEx in Q2 in Liberty East. I was just wondering whether you could provide some color as to what that relates to.

Within New Hampshire we are spending a lot of money right now on the re-tooling of a substation within Granite state. We are obviously also continuing to have a state DSO stated with them, are of the top list.

And so just to kind of put in perspective of the 22 million, 17 of it is this substation re-build. And as you know Nelson, we are right in the midst of a rate case in Granite state and I think our arbitrary expectation is that these CapEx estimates would form part of the rate base for consideration in this current rate case.

And so we are confident near in February.

So you don’t really need to be (inaudible) before spending the 22 or the expected 100 million this year?

No, just to put it all in perspective, obviously generally the regulator doesn’t provide pre-approval for CapEx. I mean it is at the risk if you want to think of us as the utility, the prudency in use and useful nature of the investment, we obviously assess every one of our investment opportunities through the lens of the regulator in terms of that prudency and useful nature.

Things that fall into the reliability category like the retooling of the substation in Granite state generally don’t receive very much negative scrutiny from the regulatory because it’s all about providing reliable service to the rate payer. Just a quick comment on that $100 million in 2013 which we expect to be replicated in ’14 and ’15 as well, all of those projects, we put all of our projects through a filter where we kind of rank them if you will, kind of 1, 2, and I think the category is 8 where safety things obviously go to the top of the list but then as we work our way down through that priority list, we look at things where there is a near term recovery in terms of regulatory trackers for in some cases the (inaudible) pipe replacement where there is an immediate tracker in, for instance in Georgia and so that $100 million reflects a line if you will, that we have drawn on that big long list of investment opportunities and the line we are trying to draw, things that are above the line reflect low regulatory risk of recovery, near term regulatory risk – near term recovery.

And so we are really focused as we think about that $100 million, I guess 300 million if we think of three years, we really thought about finding those opportunities where we could deploy the capital that are needed for rate payers as they are going to get large shareholders in near term return. Is that the kind of the comment you were looking for.

Yes, that’s a good color.

Your strategic review process determined that the EFW facility is not strategic, have you started the sales process for this and do you have a sense of timing and perhaps you can tell us the level of interest you may receive?

We haven’t actually started a formal process yet. And we are just kind of in the early stages of how we are going to attack those things.

The good news is I think the environment and the parties who are interested in the type of asset are relatively small and we certainly know all of them if not – most of them if not all of them. So no, we haven’t started it but we do want to get this process started and conclude with the bottom line.

It looks like your expected capital expenditure plan for 2013 has increased a bit to $260 million in total up from a potential of 144 million that was indicated at the end of the first quarter. And most of that increase appears to have come from spending at APCo and there is a statement in your MD&A which says that most of the $16 million of spending at APCo is for Cornwall Solar.

So my question is, is Cornwall Solar CapEx still expected to be $45 million or has that gone up? If it is still $45 million, where is the other $15 million going to be spent?

We expect to spend on Cornwall Solar remains the same as that 45 million and the increase in the CapEx spend is largely expected to be actually in the utility groups between now and end of the year, it’s some continued capital maintenance obviously on the APCo side but I think it’s fair to say that the additional 15 million is actually within the Liberty Utilities.

Could you discuss where you are in the integration process to your recent utility acquisition, to discuss what the change of some of your cost, operating costs, and SG&A, just wondering if you are seeing any opportunities for efficiency going forward or any challenges you’ve had in terms of just a general on those?

Well let me start by saying yes to your intuition that the reorganization that David was describing to Nelson of some of our business services into this Liberty business services, they are all teams that’s garnering efficiencies as we look across the portfolio to not only Liberty Utilities, but also across the [reg and reg] businesses. So that is certainly the objective to make sure that we are delivering all of those services with kind of the maximum efficiency.

So we will continue to obviously garner those efficiencies as we kind of aggregate functions under what we affectionately call the last structure of Liberty (inaudible) business services, so we intend to – hopefully you will see those efficiencies through that financial statement. Perhaps just a – I don’t know if the question is focused on it, but I have to give you an update on the integration work which is ongoing within the Liberty Utilities family as we have transitioned away from some of the continuing certain agreements from the original owners of these facilities and got our customers now on our only owned internal customer information system and having our own customer service reps answering the phone.

And those are all going well. We have completed the mid-stage, we completed Georgia, New Hampshire Gas is on track for this quarter, we’ve seen the significant terms of our relationship with the customers.

And in fact, actually get the kind go our own course, we have been what we kept the Missouri commission very closely apprised of what’s going on (inaudible) finding. We courteously in our last call last quarter, they offered us that we have now – that’s the gold share if you will for the transition of facilities from one owner to the other and that so was a very pleasant surprise.

So all going well Rupert and yes, your information about, I was trying to think efficiency

So then if we could turn to the upcoming rate cases if you could discuss those little more detail, you’ve got the rate case – interim rate has been a little lower than you are looking for initially. Generally how are the rate cases evolving and are you seeing any changes to ROE expectations and where are the pushbacks --

Sure, well let me start by saying that primary difference in the bid/ask spread almost in any rate is frankly cost of capital. I think we would be remiss if we didn’t argue as strongly as possible for as higher cost of capital as we possibly could envision and the results of our rate case in Rio Rico that the difference between our ask and what we are boarded with primarily in cost of capital, I will say that Rio Rico we saw a 9.2% ROE with an implied equity thickness of 80% and I think if you kind of do the math I feel pretty constructive from our perspective and so while we would almost maintain that we are kind of to more at the end of the day that the process to which we are torn, and I think we accepted its outcome.

I guess if that perhaps add some specific color to your question about ROE, we are continuing to see ROEs in the 9 to 9.5% range in a number of jurisdictions, some of them are higher, Texas has been more positive than that in recent history. So I don’t think we are seeing a whole scale erosion if that’s kind of where your question within ROEs, specifically talking about the Granite state interim rate case, I think it is important to note that it’s really just an interim measure in that in the context of the hearing and it’s [validated] by hearing, there really is no evidentiary period.

So there is no opportunity to negotiate and get into the specifics of a rate hearing. So it’s pretty much official if you will the discussions that went on.

At the end of the day, the final rates are all retroactive back to the date of in-position of the interim rate and so if you think, it’s not really a ditch to die in from a utilities perspective and while I agree with you, we would have liked to see higher interim rates because we think at the end of the day, the rate case that we have advanced will prevail with higher rates. It’s not as if our shareholders are going to be apprise the value as a result of that because of the mechanism to make those rates retroactive.

And so the other thing I will point out and I think that there is a little bit of a give and take and I think that commission was very straight up with us and I think we are pleased that you will note in the disclosure regarding those interim rates that we received some positive treatment with respect to recovery of storm costs under our storm fund and that will contribute to better part of the 1.6 million or 1.7 million annually going forward of additional recovery on our costs that are already [solved]. I think overall not a ditch to die in but I don’t think we are unhappy with the package.

I don’t know Rupert if that’s kind of the color you were looking for.

Wondering could you give us maybe some additional insight on how the Georgia asset performed and I think the only guidance that you gave us previously was the 1.6 million – if I look at sort of what we would have expected for the other component in there on the natural gas side? Looks like there was a bit of under performance if that’s not the case.

In the second quarter, just to help you calibrate it, the Georgia utility added about $3 million to our operating profit or EBITDA for the quarter.

Ian, historically over the last couple of years I guess we have seen a fair amount of your growth from the acquisition side and notwithstanding the fairly robust development pipeline on renewable side, can you maybe speak to both the renewable and to the side with respect to further acquisition and buyback, I am looking for detail I guess on whether or not the whatever talks you’ve had there with private parties, have sort of realigned their valuation process with what’s happened in the public markets over the last two or three months?

To start, we do continue to hunt for acquisitions, and I will just add obviously that the organic growth now in the utility sector should certainly not be discounted when you think of the ability – various organizations to continue to grow. But having said that, if we are intensely on meeting our publicly stated objective of growing both sides of that business by 15% a year, we don’t want to achieve that solely by organic growth and while we have on the (inaudible) team the New England yes show up for 75 million, I think we obviously still have more to go and so consequently we are on a continuing discussion with a number of potential vendors for utility assets.

Specifically with your comment with respect to – I am perhaps putting words in your mouth here, John but have vendors of the assets tampered their expectation in the face of the capital market circumstance is that we all have been painfully aware of here in Canada, the short answer is unfortunately not because most of these acquisitions are US based and if you follow the US utility sector, it has not suffered the decline that the – I will just call it broadly the IPP sector has suffered and before I get going on a rant about how all those stocks have been treated, I think it’s fair to say that when you look at how our portfolio is comprised, a significant portion of our business is regulated utility assets which really should be considered in the context of the trading multiple of US utility. So – and I am not sure we are getting that at present but I would be pitching about the market part of being constructive, but so the short answer is we are not seeing a lot of specifically on our US vendor.

I will add though that the – as you are probably aware the area in which we are hunting for acquisition both geographic and size has led the cost efficient somewhat muted for those type of assets. And so I think we are still confident that we can deliver accretive acquisition value to continue to meet that 15% growth objective.

Just a couple last questions on HLBV, I think in your last conference call you indicated that it would be following a somewhat seasonality profile and I think we saw a sequential decline in terms of actual production for the three assets that will generate this income, and so I am just wondering if maybe you could speak to that as well as – I think JP Morgan is looking to or already has exited a few of these contract loans for wind in the US and just wondering if that’s anything that might affect you going forward?

I think the BCCs that we monitored in the quarter I think you can do the math or it was in the $8 million range and that was quite consistent with what we expected. The higher ratio of BV is really due to two factors, one was when we – when the tax return was finally finalized for 2012 related to the facilities, there was an additional call it retro PPCs that came through and that was approximately $800 million to $900 million and then there was just – the way the allocations are made of the underlying tax basis, tax equity, there was an additional tax basis that was able to be put over to the tax equity side and that contributed to the higher HLBV income.

But overall the PPC is monetized, we are in the 8 million range.

John, just to answer your question about the outdated rumors but the perfect – they are close to about, JP Morgan’s exiting their – they are taking and faster their venture energy company at exiting the energy business. We obviously focus following those reports and they reported these where it’s all or little bit is misstated in the public press.

Their primary focus has been on actually disown thing of interest where they actually physically own asset and in combination – that they have undertaken in past year they ended up with ownership of generating station and there is a production that’s not exactly what were the appropriate business of their business line. They certainly didn’t expect any intention to sell any of our contracts but having said that we obviously within our range have credit worthiness protection provisions to ensure that if there is ever a successor to those arrangements we are adequately projected in terms of its credit worthiness going forward.

So first question just on rate cases, previously I think you might have mentioned a rate application plan for the Missouri utility in 2014 but in the MD&A material here I don't see that within that table. I'm just wondering if there's any updates on that.

Yes, we are planning on doing a filing and sort of having in that February of next year is kind of the target date to get that application in.

And can you talk about any sort of financial impacts there, or expected things that you might ask for?

Probably it’s a little soon to talk about – we will try and make sure that we get some information into our next quarter – next quarter’s MD&D, Jeremy, but I think we obviously have conversations with the regulatory, I don’t think this is kind of the surprise, we continue to invest capital in the utility. And so while there will be obviously an increase I don’t think that make certainly – we will make sure you get the detail.

And I will point out that one of the mechanisms in the – jury date, relatively supportive mechanism is something sort of our infrastructure reimbursement and this provides you an immediate return on some of the capital, we did the interest filing which typically generates close to $0.5 million a year of continuing revenue increase and that’s something that really just came out. We will make sure you get the details of that next quarter Jeremy.

Just turning to the assets that you're looking to dispose of the EFW and Brampton, I'm just wondering if the strategic review and the change in the outlook relates to somebody making an unsolicited offer for those facilities, has that happened?

No, I don’t think that’s what drove, I think we just undertook a strategic review and came to conclusion that, that’s not an asset class that we are going to be able to grow or expand or even one of the – in that business. So that was the driver for this.

And then if you just look at what you wrote it down to the book value now, am I correct in thinking it's somewhere around the 32 million range, is that accurate?

We are obviously in the midst of selling these things, I am not sure that’s exactly in the shareholders’ best interest, I think – get into a long discussion of what our expectations were. The math is, where the math is, but I think we are obviously hoping to maximize in the value of shareholders.

Let's turn to something else. Previously you've talked about transmission opportunities in northern Ontario, I'm just wondering if there's any updates on that?

No, that’s been very interesting for us and there is lots of opportunities in the north, especially involving First Nation communities. So we are actively engaged in the number of opportunities there.

Having said that, if we are successful and I think we will be, it certainly is a long term opportunity. It will be the one for a long time.

Recently there's been some news about changes to transmission ROEs in the New England market and I'm wondering if either on the generation side or on the distribution side in your utilities you might have any impact from a change in the transmission ROEs?

No, I think you are speaking to kind of first jurisdiction of ROEs – yes, none of our assets are – and their [LBCs] are subject to first jurisdictional return. And so it doesn’t really impact us, we are obviously in cost of capital discussion right now with the New Hampshire commission over our Granite state rate case.

The first process doesn’t really establish any precedence for our return.

Is there a cost, though, associated with the transmission rates in the businesses and does that get passed through ultimately?

Yes and yes to your questions and all those sort of costs would be baked into our purchase power costs which are really the most immediate flow-through to rate payers. We will really never be owner of the electronic, think about it just the purveyor that’s going to get those, it costs more, but it’s really more than the best fit in cost for rate payers.

I just want to get back to your comments about -- that you had earlier about the declining costs. I think on a general basis and if you go back long enough that's pretty hard to dispute on a general basis.

But recently one of your peers and I think there's been some chatter in the industry generally about the situation in Ontario, both with respect to permitting and higher EPC costs. The environment seems to be I guess adding a little bit towards higher costs in Ontario.

Can you comment on that, both on the EPC costs and with respect to just permitting delays?

Well, for a group who literally is just trying out on EPC contract or solar project down in Cornwall, I don’t think we would be reporting or joining to a chorus of people screaming about necessarily higher EPC cost, I think that we are generally pleased but I think the costs came in consistent with our projection over the past couple years. And so obviously there are continuing inflationary pressures on these, but nothing I would dissect.

I think more broadly and I think it’s fair to say that the cost of equipment, the decreases that we have seen in wind turbine and solar equipment have certainly overshadowed the inflationary pressure on EPCs. So I don’t think we are not offering up from our experience anything that should lead to kind of major recalibration of our capital cost estimates for our project development pipeline and perhaps arguably the opposite, as you start to see improved efficiencies both on the solar but really notably on the wind front, I would actually argue that legacy projects are improving on [securities].

And then my second question had to do with Gamesa. Can you just tell us a little bit of what you're doing there to maybe seize any opportunities from what they may have had in their development pipeline and can you specifically --

This is obviously our standard year, but 2013 represents – the end of 2013 represents the kind of current extension of the PTC circumstance in the US and I think given the extremes that we have garnered in the development and acquisition of those Gamesa assets that you pointed, we’d be remiss if we were kind of leading around and not cool thing what we could come up with. Gamesa is one opportunity and we are having conversations with Gamesa right now.

You are probably aware that in order to capitalize on the extension of the PTC it’s all of now getting into continuous construction for one project in order to preserve the PTC value, and having a constructive relationship with the manufacturer of wind turbine is an important element of being able to preserve that value and so we’ve been having a number of conversations with Gamesa about how we might exercise some ability to make commitments for turbines that would qualify that extended PTCs. So they are important player for us and obviously active in the same market that we want to participate in Rob.

Then my follow-up question is really just one will put you on the spot. Do you think you have a good chance getting something done with Gamesa that would meet the PTC deadlines?

And secondly, with Gamesa seemingly executing on its financial plan and maybe turning the corner a bit, do you think they have the same level of motivation to maybe monetize some of those development prospects they have?

Let’s be clear that their primary motivation in being in the development business is not necessarily about monetizing the value of those opportunities but it’s ensuring that they get to be the chosen supplier wind turbine. And so I think they have remained absolutely in my views undeniably committed to making sure that they get many wind turbines sold as they possibly can and that comes through partnership with partners like ourselves on wind project proposals for which they have an interest, they are all over it.

So to answer your specific question both putting us on the spot, do we see an opportunity to get something done in 2013, it’s pretty active market right now and we are chasing it – hopefully we will be able to put a transaction on the (inaudible) that does capitalize on that in 2013 PTC cut off.

I just wanted to follow up a little bit on the acquisition discussion and the fact that obviously the whole sector is off a little bit, which does affect the cost of equity capital anyway in these deals and maybe it's more a question for David, but I'm wondering what kind of flexibility you see in financing with maybe mezzanine or a little bit more debt on the short term just as we go through these machinations because -- and how cognizant you guys are about the fact that there is a little bit more risk in taking on deals that require big equity chunks just given some of the turmoil in our sector at the moment?

Just a couple of comments to put there, I mean I think if you look at our capital structure at the end of Q2, I think it’s fair to say that we are at that conservative end of our leverage spectrum at this point. So there is flexibility that way, obviously we’ve got lots of lines to do things with and then there is always a prep market that continues to remain over to us as well.

So I think a number of tools that we have outside of just the common equity that would allow us forward.

And then to kind of – and I don’t need to obviously continue to feed on it, Matthew but I think our relationship with [Primera] shouldn’t be discounted in terms of looking at this organization’s ability to have punch a little bit above its weight in terms of the type of transaction that we might consider, I think if you look back at the experience that with Calpeco at a time we are making that acquisition would have been perhaps difficult for Algonquin on its own, our partnership with [Primera] was extremely constructive in terms of being able to create shareholder value or frankly for both parties but looking at it from Algonquin’s point of view. And so maybe that is another opportunity that needs to be just kept in mind as we think about as you call it that big equity chunk for a transaction that particularly given the specific current environment maybe it would be a little bit conservative of doing it if we were out there probably all-buy ourselves, so in some respect it rather comes to the (inaudible).

I also wanted to follow up on the conversation that was going on around JPMorgan and the tax equity business and, in particular since I guess you're chatting with them I'm wondering if you guys would ever consider buying any of the tax equity cash flows that they might be selling from third-party projects that are not -- instead of buying actual hard assets?

Well it’s an interesting proposition and I think the short answer is the cash flows that would otherwise be going to tax equity come from the same resource as the cash flows to which we are, so I am not sure if we have seen them having a materially different risk profile, so that’s a good news. The potential is a bad news, but the potential consideration with that is, they obviously have a different timing profile associated with it, which we have to kind of look at, layering that into our own cash flows.

But I think to kind of overall sum up, to say that we are obviously comfortable with the sort of cash flows that are coming off the wind farms and with the fact, whether they are going to us or going to tax equity, we obviously understand that risk profile, so to the extent that there was an opportunities to potentially invest in some of those cash flows, we obviously want to make sure that the timing of those cash flows, the transparence to the marketplace so nobody is making a presumption that you are buying long term cash flows when in fact they actually have kind of cash flow profile which might differ from the other part of our profile and – but having said that, I think the answer is yes, we would be willing to (inaudible).

A couple questions, I guess further to the last question maybe for David. For your renewable development projects that you haven't set financing up for yet necessarily, how high would you consider taking leverage on those projects assuming your share price were to stay at these levels?

Well I think that’s certainly perfect speculation, to say assuming share price stays at existing levels, I mean the one thing that I would point out is these projects in the contracts were awarded back at a period when our share price was actually trading well below where we are trading today. So I would make that comment.

But as far as leverage we are prepared to take on, I think we are quite clear on that, we try to have an investment grade capital structure and we would be looking at somewhere in the 45 to 60% as far as debt to total cap, on these projects and we are quite committed to maintaining a BBB flat credit rating.

And one other question and this is more just to reconcile our model and appreciate the EFW is out of your adjusted EBITDA that's held for sale now. Can you give us the actual EBITDA that facility generated in the second quarter?

If you look at the notes to the financial states, you will have that information pretty much, that’s laid out for you, it’s in the notes specific to discontinued operations.

Just a couple of quick housekeeping questions. How much pay-go did you receive in the quarter from the US wind farms and going forward, does it still make sense to think about the pay-go is about 50% of HLBV?

You’re actually correct that – in terms of the timing of when the pay-go comes in, pay-go comes in at the end of the year once all the contracts year is determined. But you are correct in terms of the actual pay-go does represent approximately 50% of the HLBV.

And then on the Cornwall Solar project, how much did you spend on that in the quarter?

About $5 million.

And Long Sault, you mentioned there was some CapEx toward that project, was that covered by insurance?

Generally yes, we are just about through the construction and while we’ve received interim payments from the insurer on the way through, there’s probably a couple 3 million that sort of remains to be recovered on that capital but we obviously haven’t finalized that with the insurer and we continue to remain confident that we buy insurance for the reason and therefore continue to pay. So I hope it would be --

Thanks everyone for taking the time today. I see by the clock in the wall that we were able to get through this entirely in an hour and so appreciate everybody’s participation.

And as always, stay on the line for Kelly Castledine review of our disclaimer.

Certain written and oral statements contained in this call are forward-looking within the meaning of certain securities laws and reflect 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’s future plans and its dividends to shareholders.

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