Algonquin Power & Utilities Corp (AQNU) 2013 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the Algonquin Power & Utilities second-quarter 2013 analyst conference 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 you that this conference is being recorded today. And I will now turn the conference over to Chris Jarratt, Vice Chair. Please go ahead.

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 Director of Investor Relations. For your reference, additional information on the results is available for download on our website at algonquinpower.com.

I'd like to note that in this call we will provide information that relates to future events and expected financial positions that should be considered forward looking, and Kelly will be back at the end of the call to provide further details on this.

This morning, Ian will discuss the highlights of the quarter, and David will follow with a review of the financial results, and then we will open the lines up for questions. We would request that you restrict your questions to two, and then requeue if you have additional questions, to allow others the opportunity to participate.

And with that, I'm going to now hand it over to Ian.

Thanks, Chris, and good morning, everyone, and thanks for joining us on the call today. I'd 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 a 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 will add 53,000 natural gas utility customers to the Liberty Utilities family, is progressing through regulatory approval, and we expect this to be completed in the second half of this year. As a bit of a follow up on our portfolio realignment initiatives that I've 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 in respect of which we receive partial proceeds of approximately CAD23 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 didn't offer a couple of quick comments on the recent weakness in the capital markets, which might be ascribed to concern over rising interest rates. While 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 mitigates the potential impact of higher interest rates at our Business.

To be more specific, for Liberty Utilities, interest costs, as you are probably aware, are generally a pass-through expense to rate payers. For APCo, while 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 premised on materially higher interest rates than the current environment. Secondly, most APCo PPAs feature CPI, or consumer price index, 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 work to ensure that we can continue to deliver accretive value to shareholders from our pipeline.

We believe that success in an environment of rising return requirements will go to those organizations that can deliver such continuing accretive earnings and cash flow growth to support a rising dividend. While we do continue to identify new, accretive acquisition development opportunities for both Liberty Utilities and APCo, we're confident that APCo's existing CAD800-million contracted power pipeline and identified near-term utility CapEx opportunities within Liberty Utilities of over CAD300 million will provide the earnings and cash accretion needed to satisfy any market concerns over the ability of our dividends to remain compelling.

With that, I'm going to hand things over to David to speak specifically to the Q2 financial results. David?

Thanks, Ian. Good morning, everybody. We're 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 strength and benefits of our business model. In-all for the quarter, we had revenues of CAD148.8 million, and that compares to CAD58.7 million a year ago. And our EBITDA in the quarter was CAD56 million, and that compares quite favorably to CAD21.8 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 CAD35.9 million as compared to CAD19.8 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, strong long-term average resources in Ontario, Quebec, Manitoba and Texas offset lower long-term average resources in the Maritime, 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 the second quarter of 2013, operating profit totaled CAD36.4 million as compared to CAD15.9 million during the same period of 2012, representing a CAD20.5-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 CAD35.7 million in the second quarter of 2013. The operating results from EFW are now classified as discontinued operations in our financial statements. With respect to the operating results from the thermal energy division, operations were generally in line with our expectations for the quarter, posting an operating profit of CAD3 million compared to CAD2.5 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 repowered Windsor Locks facility will operate in line with quarterly performance from the latter half of 2012 that we achieved after the repowering.

Within Liberty Utilities, in the second quarter, Liberty Utilities reported an operating profit of CAD23.5 million compared to CAD8.6 million a year ago, and the increase coming from our acquisitions. In our west division, during the second quarter, water -- wastewater revenue was CAD10 million, in line with the same period a year ago, and net electricity revenue was $9 million compared to $6 million a year ago, and this is mainly due to 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 $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 CAD6.8 million. And in the east, net utility sales, both gas and electric, totaled CAD22.2 million as a result of assets being acquired in the third quarter of 2012. There are obviously no comparable results for a year ago. Looking ahead to the next quarter, we are expecting continued modest customer growth throughout our service territories in the Liberty Utilities west region.

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

I'll now turn things back over to Ian.

Thanks, David. Just before we open up the lines for questions, I'll 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-megawatt Cornwall Solar facility in the quarter, and we do expect to complete construction late next quarter. The facility 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-megawatt wind project located near Morris, Saskatchewan has now received all necessary environmental authorities to proceed to construction. The completion of the interconnection facility by [Telus Power] is actually now the gating item 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-megawatt Chaplin wind project, and expect to submit the initial environmental impact assessment to the Saskatchewan environmental assessment branch this quarter.

We did submit the renewable energy approval application for our 75-megawatt Amherst Island, Ontario-based wind project in April, and, subject to the receipt of the reapproval, expect that construction could commence shortly thereafter with a construction timeframe of 12 to 18 months. And finally, moving east to Quebec, our two wind developments in Quebec continue to advance with the Saint-Damase wind project scheduled to commence construction later this year, and the completion of an open house for our Val-Eo project located near Lac-Saint-Jean 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 working through several significant rate cases, which have combined total revenue requirement increase of CAD18 million. Given the significance of this, I would encourage you to review the specific details of these rate cases in our Q2 disclosures.

Lastly, for Liberty Utilities, I want to highlight that while our focus has been and, frankly, continues to be on growing the utility business through accretive acquisitions, the increased scope of our existing regulated utility business is providing opportunities for prudent investment in the systems, and efficiently growing our rate base organically. We do remain on track for the investment of approximately CAD100 million of capital in our regulated utilities this year, and that's primarily focused on areas which support such investment with rate tariff trackers and other regulatory mechanisms to provide a prompt return on this investment.

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'd like to open the lines up for a question-and-answer session.

Thank you.

(Operator Instructions)

Nelson Ng, RBC.

Thanks, just a quick question on the interest expense at the Corporate level. Could you provide some color as to how it went from a CAD2.9 million interest expense in Q1 to a CAD2.2 million interest income in Q2? Was it derivatives or swaps, or I'm just wondering how that reversed in Q2.

In terms of the level, I'm not sure. Your comment was interest expense turning to interest income I'm not quite sure I understand that. Certainly a contributing factor in our interest, 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 there in the quarter. I'm not sure if that completely answers your question.

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

Yes, because I'm just -- I'm not quite sure I'm understanding your point with respect to I guess interest income or interest expense.

Yes, give us a call, Nelson, we'll happily walk through the financials with you.

Okay, sure thing. Then the next question I had was in terms of the admin costs, they were higher in Q2. I'm just wondering whether that represents the run rate going forward given the increased size of the Business, or were there specific items relating to -- or one-time items relating to M&A in that CAD7.3 million?

Yes, what you saw in Q2 was actually the -- what we did internally was form what we call the central service group called Liberty Algonquin Business Services. And so, as a result that were previously expenses classified as operating expenses that are now being grouped into the central service function and now classified in admin costs. So while, yes, the admin costs are close to what you can start expecting on a run rate basis, I think the other part that you -- is probably less obvious is the fact that within the operating expenses there would have been an offset for a good portion of that step up in admin costs.

Okay, got it, and just one last question. It looks like there was roughly CAD22 million of CapEx in Q2 in Liberty east. I was just wondering whether you could provide some color as to what that relates to?

Yes, within New Hampshire we're spending a lot of money right now on the retooling of a sub station within Granite State. We're, obviously, also continuing things that have safety associated with them are on the top of our list. So just to put it in perspective, of the CAD22 million CAD17 million of it is this sub station rebuild. And as you know, Nelson, we're right in the midst of a rate case in Granite State and I think obviously our expectation is that these CapEx investments would form part of the rate base for consideration in this current rate case, and so consequently, we're confident of near-term recovery.

Okay, so you don't really need to get approval before spending the CAD22 or the expected CAD100 million this year?

No, just to put it all in perspective, obviously generally the regulator doesn't provide pre-approval for CapEx. It is at the risk, if you want to think of it, of 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 in use and useful nature. Things that fall into the reliability category, like the retooling of the sub station in Granite, Georgia.

And so, that CAD100 million reflects a line, if you will, that we've drawn on that big long list of investment opportunities. And the line was drawn. Thing 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 CAD100 million, or arguably, I guess, CAD300 milliion, as we think out three years, we have really thought about finding those opportunities where we can deploy the capital, they are needed for rate pairs, but they are going to give our shareholders a near-term return. Is that the kind of color you are looking for?

Yes, that's right. That's good color.

Perfect.

Juan Plessis, Canaccord Genuity.

Well, thanks very much and congratulations on a strong quarter.

Well, Juan, since it was wind and rain I wish I could take all the credit for it.

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

Hi, Juan, it's Chris. We haven't actually started a formal process yet and we're just in the early stages of how we're going to attack this thing. The good news is I think the environment and the parties who are interested in this type of asset are relatively small and we certainly know all of them if not -- or 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 concluded as quickly as possible.

Okay, thanks for that, Chris. And it looks like your expected capital expenditure plan for 2013 has increased a bit to CAD160 million in total up from a potential of CAD144 million that was indicated at the end of the first quarter, and most of that increase appears to come from spending at APCO, and there's a statement in your MD&A, which says that most of the CAD60 million of spending at APCO is for Cornwall Solar. So my question is, Cornwall Solar CapEx still expected to be CAD45 million, or has that gone up? And if it is still CAD45 million, where is the other CAD15 million going to be spent?

No, the expected spend on Cornwall Solar remains the same at that CAD45 million and the increase in the CapEx spend is largely expected to be actually in the utility group between now and the end of the year. There's some continued capital maintenance obviously on the APCO side, but I think it's fair to say that most of the additional CAD15 million is actually within Liberty Utilities.

Rupert Merer, National Bank.

Can you discuss where you are in the integration process for your recent utility acquisitions you discussed and, of course, the change of some of your costs from operating costs into SG&A? Just wondering if you're seeing any opportunities for efficiencies going forward, or any challenges you hadn't anticipated? Just a general update?

Sure. Well, let me start by saying yes to your intuition that the reorganization that David was describing to Nelson of our some of our business services into this Liberty Algonquin business services are all aimed at garnering efficiencies as we look across the portfolio, not only of regulated utilities but also across the reg and non-reg businesses. And so that is certainly the objective to make sure that we're delivering all of those services with the maximal efficiency.

So, we will continue to, hopefully, garner those efficiencies as we aggregate functions under what we've affectionately called the last structure that Liberty Algonquin business services and so the intent is that you'll hopefully start to see those efficiencies through the financial statements.

Perhaps -- and just I don't know if the question was focused on it but I have to give you a quick update on the integration work, which has been ongoing within the Liberty Utilities family as we have transitioned away from some of the continuing service agreements from the original owners of these facilities and got our customers now on our own 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've completed Georgia, New Hampshire Gas is on track for this quarter. We've seen seamlessness in terms of our relationship with the customers. And in fact actually just kind of blow our own horn for a second, we've been -- while we've kept the Missouri Commission very closely apprised of what's going on. It was very gratifying. They've gratuitously -- in our last call last quarter they offered us that we've now set the gold standard, if you will, for the transition of utilities from one owner to the other, and so that was a very pleasant surprise. And so all going well, Rupert, and yes, your intuition about us trying to seek efficiencies.

So, then if we could turn to the upcoming rate cases. If you could discuss those in a little more detail. You've got the rate case with New Hampshire, of course. The interim rate may be a little lower than you're looking for initially. Generally how are the rate cases evolving and are you seeing any changes to ROE expectations and where are the pushbacks, if any, where are they coming from?

Sure. Well, let me start by saying the primary difference in the bid/ask spread almost in any rate case is, frankly, cost of capital. I think we would be remiss if we didn't argue as strongly as possible for as high a 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 was ordered was 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 do the math that feels pretty constructive from our perspective, and so while we would always maintain that we're entitled to more, at the end of the day this is the process to which we are torn and I think we accepted its outcome.

I guess just to perhaps add some specific color to your question about ROEs, we are continuing to see ROEs in the 9% to 9.5% range in the number of jurisdictions, some of them are higher. Texas has been more positive than that in recent history. So I don't think we're seeing a whole scale erosion, if that's where your question was aimed, in ROE.

Specifically talking about the Granite State interim rate case, I think it is important to note that it's really just an interim measure and that in the context of the hearing, and it is established by hearing, there is really no evidentiary period and so there's really no opportunity to negotiate and get into the specifics of a rate hearing, and so it's pretty prima facia, if you will, the discussions that went on. At the end of the day the final rates are all retroactive back to the day of imposition of the interim rates. And so to be frank it's not really a ditch to die in from a utilities perspective. And while I think I agree with you we would have liked to have seen higher interim rates because we think at the end of the day the rate case that we've advanced will prevail with higher rates, it's not as if our shareholders are going to be deprived of value as a result of that because of the mechanisms to make those rates retroactive.

And the other thing I will point out, and I think that there is a little bit of give and take and I think the Commission was very straight up with us. And I think we are pleased that you'll note in the disclosure regarding those interim rates that we received some positive treatment with respect recovery of some storm costs under our storm fund and that will contribute to the better part of CAD1.6 million or CAD1.7 million annually going forward of additional recovery on costs that are already sunk. So I think overall not a ditch to die in, but I don't think we're unhappy with the package. I don't know, Rupert, if that's the color you're looking for.

John Safrance, Cantor Fitzgerald.

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 about 1.6 million decotherms, and if I look at 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, or is that not the case?

In the second quarter, just to help you calibrate it, the Georgia utility added about CAD3 million to our operating profit, or EBITDA, for the quarter.

Okay, thanks. And historically over the last couple years we've seen a fair amount of your growth from the acquisition side and notwithstanding that you still have a fairly robust development pipeline on the renewable side, can you speak to both the renewable and the utility side with respect to further acquisition? And by that I'm looking for detail on whether or not the -- whatever talks you've had there with private parties have realigned their valuation process with what's happened in the public markets over the last two or three months?

Interesting question, John. Just to start, we do continue to hunt for acquisitions and I'll just add, obviously, that the organic growth now in the utilities sector should certainly not be discounted when you think of the ability of this organization to continue to grow. But having said that, if we -- our intent on meeting our publicly-stated objective of growing both sides of that business by 15% a year, we're not going to achieve that solely by organic growth. And while we have on the scoreboard seen the New England Gas show up for CAD75 million, I think we still have more to go and so consequently we are continuing discussions with a number of potential vendors for utility assets.

Specifically with your comment with respect to have -- and I'm perhaps putting words in your mouth here, John, but have vendors of the assets tempered their expectations in the face of the capital market circumstances that we've all 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'll just call it broadly the Canadian IPP sector has suffered.

And before I get going on a rant about how Algonquin stock's been treated, I think it is 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 utilities. And so it's -- and I'm not sure we're getting that treatment, but bitching about the market's hardly constructive. So, the short answer is we're not seeing a lot of sympathy out of US vendors.

I will add, though, that we, as you are probably aware, the area in which we're hunting for acquisitions, both geographic and size, has left the competition 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. I don't know if that's helpful, John, in terms of background.

Oh, no, that's excellent, thank you. 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 would generate the HLBV income, so I'm just wondering if maybe you could speak to that, as well as -- I think JPMorgan is looking to or already has exited a few of its contracts on tax equity for wind in the US, and just wondering if that is anything that might affect you going forward?

The PTCs that we monitor in the quarter -- I think you can do the math -- was in the CAD8 million range and that was quite consistent with what we expected. The higher HLBV is really due to I'll say two factors. One was when we -- when the tax returns were finally finalized for 2012 related to the facilities there was an additional retro PTCs that came through and that was approximately CAD800,000 to CAD900,000 and then there was, just due to the way the allocations are made of the underlying tax basis to 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 PTC is monetized were in the CAD8 million range.

John, just to answer your question about the -- I won't say the rumors but the public press articles about JPMorgan's exiting their (inaudible), their venture energy company, and exiting the energy business, we obviously spoke to them following those reports and the reports back we got were, oh, it's a little bit misstated in the public press. Their primary focus has been on actually disposing of interests where they actually physically own assets and in some combination -- business combinations that they've undertaken in past years, they ended up with ownership of actual generating stations and I think there's a perception that that's not exactly where the appropriateness of their business lies.

They certainly didn't express any intention to sell any of our contracts, but having said that, we obviously within our arrangement have credit worthiness protection provisions to ensure that if there is ever a successor to those arrangements, we're adequately protected in terms of the credit worthiness going forward.

Jeremy Rosenfield, Desjardins Capital Markets.

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 have maintained that, and I think February of next year is kind of the target date to get that application in.

Okay, and can you talk about any financial impacts there, or expected things that you might ask for?

Probably a little soon to talk about. We'll try to make sure that we get some information into next quart -- pardon me, next-quarter's MD&A, Jeremy, but I think we've obviously had the conversation with the regulator, I don't think this is going to come as a surprise. We've continued to invest capital in the utility, and so, that while there'll be obviously an increase I don't think there's anything startling that we're proposing, but we'll make sure you get some details.

I will point out that one of the mechanisms in Missouri that, and I guess it's a relatively supportive mechanism, is something called their infrastructure reimbursement and this provides you an immediate return on some of the capital that's invested, and we did what's called an interest filing, which did generate close to CAD0.5 million a year of continuing revenue increase, and that's something that really just came out. So that helps mute the requirements for rate cases. But we'll make sure you get the details of that next quarter, Jeremy.

Excellent. 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?

Jeremy, it's Chris Jarratt. No, I don't think that's what drove it, I think we just undertook a strategic review and came to the conclusion that that's not an asset class that we're going to be able to grow, or expand, or even want to be in that business. So that was the driver for this.

Okay, and 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 CAD32 million range, is that accurate?

Well, Jeremy, it's Ian speaking. We're obviously in the midst of selling these things so I'm not so sure it's exactly in the shareholders best interest for us to get into a long discussion of what our expectations were. The math is what the math is, but I think we're obviously hoping to maximize in the value of shareholders, I'm sure you understand.

Sure, absolutely, okay. 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?

Yes, it's Chris Jarratt again. No, that's something that's very interesting for us, and there's lots of opportunities in the north, especially involving first nation communities, so we are actively engaged in a number of opportunities there.

But as you could imagine it's not a real quick process, Jeremy.

Okay, I'll look forward to it.

But having said that, if we are successful, and we think we will be, it certainly is a long-term opportunity. It'll go on for a long time.

Okay, excellent. Maybe just one final question. 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're speaking to FERC jurisdictional ROEs, is that what you're --?

Yes.

Yes, none of our assets are -- in our LDCs are subject to FERC's jurisdictional returns and so it doesn't really impact us. We're obviously in cost of capital discussions right now with the New Hampshire Commission over our Granite State rate case, but the FERC process doesn't really establish any precedence for our returns.

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. All those costs would be baked into our purchase power costs, which are really the most immediate flow through to rate payers. We're really never the owner of the electrons. Think of us as just the purveyors and if those -- they cost more that's unfortunate but it's really for the benefit and cost of rate payers.

Your next question comes from the line of Robert Catellier of Macquarie.

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 chatter in the industry generally about the situation in Ontario, both with respect to permitting and higher EPC costs. The environment seems to be ebbing 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 just signed an EPC contract for our solar project out in Cornwall, I don't think we would be reporting or joining into a chorus of people screaming about necessarily higher EPC costs. I think that we're generally, I won't say 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 that one sees, but nothing outside of that.

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

Okay, that's good color, thanks. 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 seize any opportunities from what they may have had in their development pipeline and can you specifically --?

Sure, I think this is a -- I don't say a banner year, but 2013 represents -- the end of 2013 represents the current extension of the PTC circumstance in the US, and I think given the experience that we've garnered in the development and acquisition of those Gamesa assets that you point out, we would be remiss if we weren't waiting around in that pool seeing what we could come up with. Gamesa is but one opportunity and we're having conversations with Gamesa right now.

You're probably aware that in order to capitalize on the extension of the PTCs, it's really all about now of getting into continuous construction for one's project in order to preserve the PTC value, and having a constructive relationship with the manufacturer of wind turbines is an important element of being able to preserve that value. 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 for that extended PTCs. And so, they are an important player for us, and, obviously, active in the same market that we want to participate in, Rob.

Then my follow-up question 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 had?

Well, let's be clear that they're primary motivation in being in the Development business is not necessary about monetizing the value of those opportunities, but it's insuring that they get to be the chosen supplier of wind turbines. And so I think they are -- they remain absolutely maniacally committed to making sure that they get as many wind turbines sold as they possibly can, and if that comes through partnering up with parties like ourselves on wind project proposals for which they have an interest, they're all over it.

But to answer your specific question and both putting us on the spot, do we see an opportunity to get something done in 2013? It's a pretty active market right now and we're chasing it hard and hopefully we will be able to put a transaction on the scoreboard that does capitalize on that 2013 PTC cutoff.

Matthew Akman, Scotiabank

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 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?

Matthew, good morning. Just a couple comments to put there. I think if you look at our capital structure at the end of Q2, I think that it's fair to say that we are at the conservative end of our leverage spectrum at this point so there is flexibility that way. Obviously we've got lots of room in our bank lines to do things with. And then there's always the pref market that continues to remain open to us, as well. So there's, I think, a number of tools that we have outside of just the common equity that would allow us to move forward.

And then to -- and I don't mean to obviously continue to beat on it, Matthew, but I think our relationship with Emera shouldn't be discounted in terms of looking at this organization's ability to perhaps punch a little 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 where making that acquisition would have been perhaps difficult for Algonquin on its own, our partnership with Emera was extremely constructive in terms of being able to create shareholder value and, frankly, for both parties, but lucky enough 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 check for a transaction that, particularly given that the current environment -- maybe you would be a little bit concerned about doing it if we were out there fighting all by ourselves, but in some respects it's nice to have your big brother come to the fight with you.

Okay, thanks for that. I also wanted to follow up on the conversation that was going on around JPMorgan and the tax equity business and, in particular, since you're chatting with them I'm wondering if you 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 source that the cash flows to which we're entitled, so I'm not sure if we see them having a materially different risk profile, so that's the good news.

The potential -- I don't want to say bad news, but the potential consideration with that is they obviously have a different timing profile associated with them, which we'd have to look at and see layering that into our own cash flows. But I think to overall sum up to say that we're obviously comfortable with the source of cash flows that are coming off those wind farms and with the fact whether they are going to us or to cash equity, we obviously understand that risk profile.

And so to the extent that there was an opportunity to potentially invest in some of those cash flows, we obviously would want to make sure that the timing of those cash flows is transparent to the marketplace, so nobody is making the presumption that you're buying long-term cash flows, when, in fact, they actually have a contractual profile which might differ from the other part of our profile. But having said that I think the answer is yes, Matthew, we would be willing to look at that sort of thing.

Sean Steuart, TD Securities.

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 a fair bit of speculation to say assuming share price stays at existing levels. The one thing that I would point out is these projects and the contracts were awarded back at a period when our share price was actually trading well below where we're trading today. So I would make that comment. But as far as leverage we're prepared to take on, I think we're quite clear on that that we target an investment grade capital structure and we would be looking at somewhere in the 45% to 50% range, as far as debt to total cap those -- on these projects and we're quite committed to maintaining a BBB flat credit rating.

Understood. And one other question, and this is more just to reconcile our model and appreciate the EFWs 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 statements you'll have that information pretty much laid out for you. It's in the note specific to discontinued operations.

Okay, I'll circle back with you on that.

(Operator Instructions)

Rupert Merer, National Bank.

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

You're actually correct. In terms of the timing of when the pay, go comes in, the pay, go comes in at the end of the year once all the production for the year is determined. But you are correct in terms of the actual pay go does represent approximately 50% of the HLBV income.

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

About CAD5 million.

Great. And [Long Su], you mentioned there's some CapEx toward that project, is 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 CAD2 million, CAD3 million that remains to be recovered on that capital. But we obviously haven't finalized with the insurer, so we have -- continue to remain confident that we buy insurance for the reason, and they've continued to pay, and so hopefully it will be a non issue.

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

Great. Well thanks, everyone, for taking the time today. I see by the clock on the wall that we were able to get through this entirely in an hour, and so I appreciate everybody's participation. And as always stay on the line for Kelly's scintillating review of our disclaimer.

Certain written and oral statements contained in this call are forward looking within the meaning of certain securities laws and reflects the views of Algonquin Power & Utilities Corp. with respect to future events based upon assumptions relating to, among others, 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 at 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, that involve inherent risks and uncertainties. We caution that, although we believe our assumptions are reasonable in the circumstances, these risks and uncertainties derive from the possibility that our actual results may differ materially from these expectations set out in the forward-looking statement.

Material risk factors include those in the Company's most-recent annual financial statement results, the annual information form and the most-recent quarterly management discussion and analysis. Given these risks, undue reliance should not be placed on forward-looking statements, which apply only as of their date. Except as required by law, the Company does not intend to update or revise any forward-looking statement, whether as a result of new information, future developments or otherwise.

And thank you. Ladies and gentlemen this does conclude the conference call for today. We thank you for your participation and you may now disconnect your lines.