Algonquin Power & Utilities Corp (AQN) 2012 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Algonquin Power & Utilities Corp Q3 analyst and investor conference call. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question and answer session. Instructions will be provided at that time for you to join for questions.

(Operator Instructions)

I would like to remind everyone that this conference call is being recorded today, November 15, 2012 at 10.00 AM Eastern Time.

I will now turn the call conference over to Chris Jarratt, Vice Chair. Please go ahead.

Good morning, everyone. I would like to welcome you to our 2012 third-quarter results 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 our results is available for download on our website at AlgonquinPowerandUtilities.com.

I'd like to note that on this call we will provide some information that relates to future events and expected financial positions that should be considered forward-looking. Kelly will provide further details at the end of the call. In a few minutes, Ian will discuss the highlights for the quarter and David will follow with a review of the financial results. We will then open the lines for questions and I would ask that you restrict your questions to two and then requeue if you have any additional questions to allow others to participate. In addition, for the first time we will be accepting questions via our Twitter page. Our handle is @AQN_atutilities and if time permits, we will answer as many of them as possible on this call.

With that, I'll now hand it over to Ian.

Good morning, everyone and thanks, Chris. I'd like to thank you all for taking time for joining us on today's call. As you know, we've been busy this past quarter with the successful closing of the acquisitions of additional utility operations in New Hampshire, Missouri, Illinois and Iowa, as well as the approximately 59% interest in the Sandy Ridge wind farm in Pennsylvania.

The closing of these transactions marks a significant milestone in the continued growth of our company and, based on the profile of expected earnings and cash flow contributions from these initiatives, our Board of Directors was provided with the confidence to increase the annual dividend by 11% during the third quarter. We are pleased to have been able to deliver these growth initiatives and believe that the dividend increase is consistent with our strategy of providing an attractive total shareholder return, comprised of a dividend yield and capital appreciation.

Early in the third quarter we announced the continued growth of the regulated utility footprint with the announcement of our agreement to acquire two regulated utility operations. A water distribution system in Arkansas from United Waterworks and natural gas distribution systems in Georgia from Atmos. The Georgia utility system provides natural gas distribution service to approximately 64,000 customers. The purchase price for the Georgia utility is approximately CAD140 million and we expect to acquire net property plant and equipment of approximately CAD128 million, translating to an attractive purchase price multiple of approximately 1.1 times the net PP&E.

The Arkansas utility system provides regulated water distribution service to approximately 17,000 customers in the state of Arkansas. Again, the purchase price for the Arkansas utility is approximately $29 million and we expect to acquire net assets for rate making purposes of approximately CAD25 million, representing an attractive purchase price multiple of approximately 1.16 times. Following the expected closings of these acquisitions in mid-2013, Liberty Utilities will now be serving over 425,000 utility customers in the United States, enhancing the position of Liberty Utilities as a fully capable provider of safe, reliable, high-quality, local responsive service in all of our service territories.

To this end, I'd now like to take a quick moment to commend the Liberty Utilities team for being the first New Hampshire utility to restore service to the close to 25% of our electric customers which were impacted by the recent Hurricane Sandy.

On the non-regulated utilities side of the business, as mentioned during the quarter, we closed the acquisition of a 58.75% interest in the 50-megawatt Sandy Ridge wind farm in Pennsylvania from Gamesa. We also expect to acquire a 58.75% interest in both the Senate and Minonk projects following commercial operation of the facilities, which is on target for the end of the year. During the quarter, we opted not to acquire an interest in the uncontracted Iowa-based 80 megawatt Pocahontas Prairie project, a decision which we believe has positive implications for the return profile of the overall Gamesa acquisition by minimizing exposure to merchant power price volatility.

We have a few financing highlights to mention this quarter and while I'll leave it to David to discuss, I will briefly mention that we were very pleased to have successfully closed on a bought deal basis our offering of CAD4.8 million, 4.5% cumulative rate reset preferred shares for gross proceeds of CAD120 million. The preferred shares, effectively replacing our remaining series of convertible debentures, which will be redeemed as of January 1, provides an additional source of capital to fund our committed growth initiatives while lowering our overall cost of capital.

With respect to the operations, this quarter I would like to acknowledge a couple of highlights and low lights. On the positive side, the quarter saw the seamless assumption of ownership of our Missouri, Illinois, Iowa, New Hampshire utilities. As the high degree of seasonality we highlighted at the time of closing of these acquisitions confirms, summer is, not surprisingly, the lowest point in the earnings cycle for natural gas utility. Notwithstanding, we were pleased with the results from our utility operations over the summer period and we're confident that these utilities will continue to meet the earnings guidance we previously provided at the time of acquisition.

On the disappointing side, we suffered the same challenging hydrologic and wind resource levels, which materially impacted the quarterly performance of a number of our brethren independent power producers. In our case, quarterly EBITDA was impacted by close to CAD3.5 million, driving down earnings per share by close to CAD0.02 per share. Over the first nine months of 2012, the negative earnings impact of these low wind and water resource conditions has been over CAD0.04 per share.

While we certainly hope investment decisions are not made on the basis of such resource fluctuations, we are pleased with APUC's growing investment in rate regulated utilities, which provide revenue decoupling mechanisms to mitigate weather related fluctuations. To this end, we were pleased to confirm that the settlement reached in our California utility rate case included a decoupling mechanism, which will effectively remove all of the weather related earnings fluctuations going forward, preventing any recurrence of the CAD0.015 per share negative earnings impact the abnormally warm winter delivered earlier this year.

Now I'd like to hand things over to David to speak to the financial results.

Thanks, Ian. Our overall adjusted EBITDA in the third quarter of about CAD24.2 million was about CAD1.7 million below last year's results or relatively consistent with what we reported in the second quarter of this year. The EBITDA from our utility acquisitions that we closed in Q2 helped to offset much of the effects of lower hydrology that is being experienced in many parts of Canada and the United States. Lower hydrology and wind resources reduced our revenues by about CAD3.5 million in the quarter compared to the prior year, which I should note was actually an above average year for hydrology.

So let's move on to some of the details. Revenue in Q3 was CAD99 million and this compares to CAD66 million in Q3 of last year, or adjusted EBITDA of CAD24.2 million, compares to CAD25.9 million in Q3 a year ago and CAD24.9 million in Q2 of this year. And our adjusted net earnings were CAD3.3 million, as compared to our adjusted net earnings of CAD6.9 million in Q2 of 2012.

So now a bit more detail and I'll start specifically with Algonquin Power Co, or APCo. In the renewable energy division, during the third quarter of 2012, net energy sales totaled CAD14.6 million, as compared to CAD18.5 million in the same period in 2011. Consistent with many of our peers in the power generation sector, during the quarter, the division generated electricity equal to approximately 80% of long-term projected average wind and hydrology as compared to the 117% in the same quarter last year.

APCo's Manitoba and Western regions experienced resources slightly lower than long-term average resources of production 5% below expected production. Other regions also experienced production below long-term averages. We know New York and New England regions were particularly affected with production at approximately 60% below long-term average resources. For the third quarter of 2012, the renewable energy division's operating profit totaled CAD9.3 million, as compared to CAD13.7 million during the same period a year ago. Our thermal energy division met our expectations for the quarter. We're pleased to note it produced an operating profit of CAD6.3 million, which is in line with what we reported a year ago.

Looking forward to the next quarter, in the fourth quarter of 2012, APCo's renewable energy division is expected to perform based on long-term average resource conditions for wind and hydrology. A relatively small proportion of our total energy sales, specifically the New York and New England regions, continue to be exposed to merchant energy pricing and, therefore, are expected to perform below our expectations. As previously discussed, given the continued growth of the APCo portfolio, we've commenced a strategic review process for these relatively small but otherwise high-quality hydroelectric facilities, which could result in the disposition of these facilities at some point in 2013.

I would now like to draw everyone's attention to a few other things that will impact our fourth-quarter results. We have reported in our MD&A that during the fourth quarter our Long Sault facility experienced an unplanned outage, and while we expect the facility to begin returning to service in the fourth quarter, the impact on our fourth-quarter EBITDA is expected to be about CAD900,000. On the positive side, the acquisition of an interest in the Sandy Ridge wind farm is expected to generate EBITDA of approximately CAD800,000 in the fourth quarter. Thermal energy division Sanger facility is expected to perform at comparable levels to results experienced a year ago and the repowered Windsor Locks facility will be better able to match production with demand from the mill, while limiting exposure to lower market power pricing in New England.

At our EFW facility, we are pleased to note that, as expected, we recently received approval from the Ontario Ministry of Environment for an amendment to the facility's permit, which now allows the facility to accept waste from anywhere in Ontario. We have entered into several waste supply agreements to ensure continued operation in the facility now that the contract with the region appeal has expired. EBITDA from the facility in the fourth quarter is expected to be about CAD1.5 million below the results experienced a year ago.

Moving on to Liberty Utilities, in the third quarter, Liberty Utilities reported an operating profit of CAD12.8 million, compared to CAD10.2 million in the third quarter a year ago. The increase in operating profit is primarily related to the contribution of the recently acquired assets in the Midwest and New Hampshire. I would also draw people's attention to the new reporting segments for Liberty Utilities. We are now reporting Liberty Utilities through three geographic reporting segments. Liberty Utilities West now reports our water utilities in Arizona and our California utility, and the LU Central now reports our water and gas utilities in Missouri, Texas, Illinois and Iowa, and LU East picks up our gas and electric utilities in New Hampshire.

For Liberty Utilities West during the quarter, we experienced increased water distribution, wastewater treatment, our revenue grew 1% when compared to the same period a year ago. And there was a 7% decrease in net utility energy sales in electricity distribution as a result of increased operating expenses at our Calpeco utility. In central in the third quarter of 2012, the region experienced a 16% decrease in water distribution and wastewater treatment revenue compared to the same period a year ago. And also during the quarter, central began operating the Midwest gas utility assets and from the date of acquisition to the end of the third quarter, revenue totaled CAD3.6 million. Moving on to Liberty Utilities East, during the quarter, we began operating natural gas and electricity distribution assets in New Hampshire. Net utility sales for Liberty Utilities East totaled CAD17.1 million during the third quarter of 2012.

Looking ahead to the next quarter for Liberty Utilities, we are experiencing -- continuing to experience modest customer growth in 2012 throughout all of our service territories. We will experience a revenue increase in Liberty Utilities Central during the quarter as a result of the Missouri Public Service Commission approving a CAD500,000 annual revenue increase relating to a filing for an incremental infrastructure system replacement surcharge that we filed in the second quarter. We began billing the increase in early November.

I'd like to take a moment now to review some recent financing activities. As Ian mentioned earlier, we are pleased to add preferred shares to our capital structure toolbox. We issued 4.8 million preferred shares, raising a total of CAD120 million and this transaction closed just last Friday. The attractive 4.5% yield on these prefs will have a positive impact on our overall cost of capital and they are rated P-3 and PFD-3 low by S&P and DBRS, respectively. Proceeds from the offering will be used to partially fund the upcoming acquisition of Senate Minonk that's expected to close in late 2012.

And at the start of Q3, we closed a CAD225 million US private placement with the syndicate of long-term institutional investors in the US to partially fund our utility acquisitions, which closed in Q3. This was the first issue off of our master debt platform that we now have in place to support our utilities businesses. The step platform allows Liberty Utilities to easily source new debt as required to fund growth in the business over time. We believe the terms achieved for the notes are very attractive for the rate pairs of the utilities we acquired. The notes are senior, unsecured and have an average life maturity of just over 10 years and a weighted average coupon of 4.38%. The notes have been assigned a rating of triple-B high by DBRS.

I'll now turn things back over to Ian.

Thanks, David. Just before we open up the lines for questions, I would like to conclude with a brief update on management's continuing foci for the near term. On the APCo side of the business, we're looking forward to placing orders for panel equipment in respect to our Cornwall solar project and planning the 2013 construction process, which is expected to result in a late 2013 commercial operation date. We continue to pursue the development of our nearest term wind projects, including Amherst Island. We're pleased to have completed the Renewable Energy Act application and look forward to the public and government review process in the coming months. Within Liberty Utilities, we are focused on the resolution of the regulatory approval processes in Georgia and Arkansas, and continue planning to ensure a seamless transfer of these utilities once transfer approval is obtained.

And now, just before we open the lines for questions, we have received a number of questions by e-mail. And so I'm going to turn it over to Kelly Castledine to read the question and we'll provide the answers before we open it up for live questions. Kelly?

Thanks, Ian. We got two questions from Rob Catellier of Macquarie Securities. His first question is, it seems like risk in adding Minonk and Senate has decreased substantially, but please detail the process from here.

Thanks, Kelly. I can confirm that at the Senate and Minonk project a 150 megawatt and 200-megawatt projects in Texas and Illinois respectively, that alternative paths have now been erected and are all mechanically complete. Most of them are currently in their reliability testing, which is the final step before declaration of commercial operations date.

I think we are all confident that the commercial operations date will take place in late November and that there will be a closing on the acquisition in December -- well in advance of the December 31 expiration of the production tax credits, which is scheduled to occur in the US. And so Rob's observation is correct. We do see that Gamesa has completed the development, has the agreement contemplated they would and we're looking forward to closing next month.

Okay. Thanks, Ian. The second question is, please update the progress on replenishing the acquisition pipeline. Specifically, I'm curious if the storms in the US have caused you to hesitate on any opportunities that may have been under consideration.

Well, as we have publicly stated, our assets growth objectives are 15% per year, which translates to a target for 2013 of approximately CAD250 million. That would be satisfied either on Algonquin Power or Liberty Utilities side. Within APCo, we are continuing to develop the opportunities of which I spoke before and which have been detailed in our MD&A. And in addition to pushing some of the projects that haven't made it to the threshold of being included into the MD&A to that level. Additionally, we are continuing to examine a couple of acquisition opportunities in -- for additional wind projects.

I wouldn't say that there have been any storm related opportunities that have fallen off the table. That in general, from our perspective and where our facilities have been located, the storm was in some respects a non-event. And so I'm not sure that I would -- that the storms in the US have caused us to hesitate.

Within the Liberty Utilities portfolio, we are continuing to discuss acquisition opportunities, as we have highlighted or alluded to at our investor day held a couple months back. And we are confident that we will continue to be able to add to the utility footprint in a manner consistent with past performance. So there's the answer to that one, Kelly.

So with that and thanks, Rob, for sending those questions, it obviously is an efficient way to do it. Operator, I'd like to now open the lines up for live question and answer session.

Thank you.

(Operator Instructions)

Rupert Merer, National Bank.

I'd like to ask a couple questions about the EFW facility. You suggest you could see a CAD1.5 million drop in EBITDA in Q4. And that seems to be related to lower pricing. Does that suggest you expect volumes to be maintained at the facility going forward?

Rupert, I'm going to turn the question over to Chris Jarratt. Chris has been, within our organization, the guy who's been most on top of the situation. Chris?

Thanks, Rupert. We are continuing to run at capacity, but as you point out, at the average rate that we got paid for that waste has dropped. But we do continue to run at capacity and we expect that to continue.

Great. Is it too early to say what the facility could like into look like into 2013? Do you think you could get better pricing going forward?

I think we gave some guidance at the annual investor day, which was we kind of expect in 2013 the EBITDA to be in the CAD2 million to CAD3 million range. And the outlook beyond that to be even improved further. I think what we're finding is there are some high-value waste streams and we're flushing them out and we hope to conclude a couple of those soon.

Okay. Great. And finally, can you give us an update on the contract negotiations for power contract on that facility? And are you looking at any strategic options for the facility?

Right now, we're just focused on -- I think the highlight for us was focusing on the permit that we received, the C of A that came through in October. And what that enabled us to do was accept waste from anywhere in Ontario. So that was a fairly significant event for us and opened a lot of doors for additional waste sources. With regard to the power contract, we are still pursuing that. We haven't concluded anything yet, but the outlook looks good for that.

Rupert, it's Ian. Just to add to your final comment about are we looking at strategic alternatives? I assume you mean specifically with respect to how EFW fits into our portfolio going forward. Yes. I don't think it's a reasonable observation to say that, that project doesn't look like a number of other projects and while we're pleased to own it and think there's a lot of value inherent in it, we always need to consider, as the portfolio evolves, whether we are the best owner of that sort of project. And that's certainly an ongoing process.

We certainly haven't, either from a management or Lord knows from a board perspective, concluded that -- I know strategic process is euphemistic for a decision to sell, we haven't come to that conclusion at all. But we always -- we've got to be looking at these things as the portfolio grows. We need to ask ourselves the question about every one of those assets. As I think we mentioned last quarter and the quarter before, we have come to the conclusion that some of the smaller Hydro assets, while being high quality in New England and New York, probably -- we're probably not the best owners of those assets and actually do have a formal process underway for those. But not so for the EFW facility.

Thanks very much.

Nelson Ng, RBC Capital Markets.

Just following up on Hurricane Sandy, since there were outages in New Hampshire, do you think the EBITDA in Q4 would be lower than expected in New Hampshire due to the extra cost of restoring power?

The way it works in New Hampshire, Nelson, is that costs associated with extraordinary storm events -- and this would certainly fall into that category, are collected in a separate tracking account, for which we get recovery. So those extraordinary cost that we incurred over and above our normal operating costs and probably measured in the order of CAD1 million to slightly over that for us, will actually not hit our EBITDA because of the tracking mechanisms that are available to us in New Hampshire.

So the short answer is no. And I think as I mentioned, we were pleased that the utility was the first utility to return to service. We got everybody back on within 30 hours or so of the storm hitting. But we won't suffer that as an EBITDA hit, Nelson.

That's great. And then just in terms of the sale of your Hydro facilities, do you have an expected timing on the completion of the sale? Are you selling them one at a time or as a large portfolio?

We are selling them as a portfolio. I think the greatest value is going to be surfaced by that process. We have retained an investment banking firm to manage the process. We are into the second round bids for that process. And the second round participants are in the midst of their due diligence. Whether it gets concluded before the end of Q4, I think there is some question to that but it won't be very far thereafter, Nelson.

Okay. Thanks a lot, Ian. I'll get back in the queue.

James Morrison, Cormark Securities.

Following the prep deal there, you've got CAD120 million from that and then you've got CAD120 million that you're planning on raising in debt towards the Gamesa. So that leaves basically CAD30 million left of equity, which I assume you'll use from Emera subscription receipts. But then you still have another CAD15 million of that slug that were kind of from Emera that was dedicated towards the Gamesa transaction. So does that get rolled into, for instance, the Arkansas water acquisition later in the year? Or does it just expire? what is the plan there?

No. We pulled down the CAD15 million that you referred to when we acquired the Sandy Ridge wind farm back at the end of June, first of July. So that's when we took that down that 15. There's the remaining 45 that will be coming in when we conclude the Minonk and Senate acquisition. So that's kind of how we would round off that financing plan with respect to the US wind farm acquisitions. We will note that there are additional subscription receipts to which Emera is entitled to subscribe to, to reach their 25%. And so that's something that we could avail ourselves of as we get closer to acquiring the Georgia and Arkansas water assets.

Thanks, David. Just looking at that, though, you've got -- I was considering the Sandy Ridge -- I know about the CAD15 million you pulled out there. Do you still have an additional CAD15 million, right? You've got your 270 you plan on spending on Gamesa, less 120 debt, 120 pref shares and the CAD15 million that you've already taken out.

Well, there's CAD15 million of debt that was assumed at the Granite State facility.

Okay. Great. Okay. Moving on from that, the Calpeco approval to increase your ownership to 100%, I thought that was supposed to be taking care of in July. Is there something that's going on there that could drag this out for an extended period of time? Or is it just --

So James, it's just simply logistics. And I'll say the workflow that we had in Q3 to get everything done. That will be done prior to year end.

So the 4.8 million shares will be issued then?

That's correct.

And is there any impact on the lower rate case on the 3.4 million shares that you'll issue once the rate case is implemented?

No.

Okay. I'll get back in the queue.

Juan Plessis, Canaccord Genuity.

You mentioned in your release and in your comments that you expect Q4 hydrology and wind resources to be in line with the long-term average. Are you basing this on what you experienced so far in the first half of the fourth quarter? Is this simply based on the long-term average number?

No. I think it's certainly based on what we know today as we sit here on November 15. And -- but from today forward obviously, Juan, we have to go by the long-term averages. But that's what we're producing generally today. So we have no reason to believe that we won't continue to do that. As you can imagine, Hurricane Sandy obviously provided some welcome relief rainfall associated with it to a number of our generating stations. But in general, October, almost across the territories, has returned to pretty normal hydrology, so it is based on facts to date and prediction for the balance of the quarter, Juan.

Okay. Great. Thanks for that. Secondly, within the renewable energy division, the AES cost, the power purchases were pretty high in the quarter at CAD3.2 million, that's about CAD2.5 million higher than last year. Was this a result of the low hydrology which forced you to purchase more power at a bit higher price?

Well, you appreciate that within AES and we have an obligation to meet the load as it required -- as it exists. And so two things I can imagine contribute to it. And is that firstly, that additional sales would require additional purchases. And second of all, you may be aware that we had our G5 unit under refurbishment. And we had predicted this. It was -- I don't want to say an end-of-life issue that was acknowledged at the time we acquired the Tinker facility and we've been in the planning for this retrofit approximately CAD6 million for a couple years.

So with that unit out of service as well, you could imagine that an additional portion of meeting the load for which we are responsible would have been satisfied by energy purchases. But certainly nothing untoward came up during the quarter that has caused consternation, Juan.

Okay. Thanks for that.

Ian Tharp, CIBC World Markets.

Just turning to Minonk and Senate, Ian, I think you referred to in the past the notion of potentially recontracting the merchant capacity there. I wonder if you can talk to any discussions you've had on that front for the asset?

On Minonk and Senate, both of those have 10-year and 15-year respectively, power hedges in place for about 70% of the energy. Are you speaking of the balance of that, Ian?

Yes, I am.

To be frank, I think the way that, that is best managed is actually not so much contracting specifically for the energy but entering into the market to basically -- through the use of derivatives to buy into some stability, if you will, some puts and calls to basically get ourselves locked in for the price of the balance of that. It's a little bit of a tightrope one walks because one obviously doesn't want to unintentionally create the opposite position, being short rather than being long. And so it does take some management. As we have acquired the Sandy Ridge facility, our AES group have focused specifically on that.

I don't have anything to report right now in terms of what the results will be. But clearly when Senate and Minonk join the family at the end of -- or sometime next month, obviously the opportunity increases quite dramatically in terms of the amount of energy that would be available, that 30% or so. So we're on it. Don't have anything to report right now, but we certainly acknowledge the opportunity to provide stability for that portion of the energy.

Okay. So I think we did talk about it a little bit at your investor day. And I think the notion then was really actually to look at shorter-term power sales contracts, perhaps you were referring more to probably financial hedges at AES would be putting in place for Sandy Ridge to start and then Senate and Minonk once they're operational. Is it more the financial hedge or are we actually looking at one to two year PPAs to hedge off that merchant risk?

In some respects it's sort of the same thing, whether it's a physical delivery or financial hedge. But our position remains the same. And I think your interpretation is correct. It would be done over a relatively short term, one and two years. So say yes to both parts of your question, Ian, but we are looking at how do we at least smooth out that volatility over a year or two.

Okay. Helpful. So moving on, the question was going to be around AES. I know you're still in the process of selling your merchant Hydro assets on the East Coast. And I know they focus a lot on Tinker. And likely now also on dispatching Windsor Locks. It sounds like they do have their hands full with the merchant capacity around the wind. So there'd be no thought of pairing down the activities within AES going forward?

Back in 2009, we made a commitment that we needed to, if you will, get smarter on merchant electricity markets and the markets in which we are participating, notwithstanding the fact that a huge percentage of our energy, as you know, is sold under PPAs. We see that AES provides, obviously in addition to the very specific you've got to go out and market Tinker and you've got to go out and help with the management and dispatch of Windsor Locks, we think that they provide important insight to us in terms of not only those facilities, but now Senate, Sandy, Minonk as we look at development projects understanding the markets in the US, where capacity markets going.

So no, I don't think the sale of the small hydros in New Hampshire or New York really have any implications on whether we would wrap up AES. It's part of a strategic initiative. I don't think an organization which has CAD1 billion plus of energy assets in the US can afford not to fully understand the markets in which their participating, even if the energy's actually being sold under PPA.

Seems fair. If I may, one last question on Liberty Utilities Central. So there's the disclosed disparity between what your expected active connections were and what the actual active connections were, about 2.3% lower. And then you provided, David, a chart that shows your expectations Q4, Q1, Q2.

So I'm just wondering, what should we be using in terms of customer connections and total EBITDA? I know EBITDA was lower given lower customer connections and lower usage, but does all of this guidance and this chart now change given that you've got this lower customer base? Or are we still thinking around these same metrics? It would be quite a jump in customers if Q4 stands at that 83,000 level.

The guidance that's provided, we are still confident in. The fluctuation that you see in the customers is within the realm of, I'll say, normal for the utility, that there is a natural variation. As we look to what we're seeing in customer counts in the early part of Q4, there is the return back to the levels.

So we don't see anything out of the ordinary. There is a natural fluctuation in customer accounts there just as a result of the timing of when people disconnect for moving or those sorts of things. So the guidance that we provided there, if we didn't think we could standby it, we would have updated.

Okay. I just wanted to understand one versus the other. Just to restate, the customer should revert back to that 83,000, 223 and then there's no permanent impairment to the EBITDA production, given any down tick in customer connections?

Yes. That's absolutely correct.

Okay. That's it for me right now. Thank you.

Thanks, Ian.

Sean Steuart, TD Securities.

Couple of technical questions. Liberty Utilities East, the results there were actually better than the guidance you gave in the fact sheet in early July in terms of EBITDA. I'm wondering if you can go into a little bit of context there and should we assume that the guidance you gave going forward through second quarter of 2013 is still intact?

Let me start by saying, as the guidance showed, the results during the summer period are pretty underwhelming, so it actually doesn't take a big swing in operating cost to materially influence something when you're only earning a couple million dollars. So I think while we were pleased that after stepping into the shoes of EnergyNorth and Granite State that the operating costs frankly, came in a little bit better than we had hoped and demand was strong during the summer therefore, the results were better. I don't think it speaks to the fundamentally there's anything different about the business. We remain confident and comfortable that the guidance that we gave will certainly be met. And I would certainly hope that, that the trend that we saw in the first quarter from a cost perspective will continue, therefore, we will exceeded.

I think, let's obviously be clear, the tail of this tape will be told on the year-over-year, the entire 12 month analysis. And we ended up buying the gas utilities just by happenstance at the start of the lowest period, but we are confident that over a 12 month period, the assets are going to perform in accordance with expectations.

Okay. Thanks for that context. And then, Ian, bigger picture, you guys are talking mid-2013 for the Georgia and Arkansas utility acquisitions. So we can assume beginning of third quarter next year? Just as we look at the short to mid-term outlook, should we think about the next six months being digesting everything you've recently acquired and closing on these deals? And then further to your earlier comments on growing the utility portfolio, the latter half of the year for pursuing the next round of growth initiatives?

Well, a couple of comments, Sean. First, as we stated with the Granite State, EnergyNorth, we're kind of out of the regulatory approval prediction business. So I think we're trying to be a little bit conservative just -- we tried to give some very factual guidance with respect to Arkansas and the Georgia processes. We have reached a settlement with -- in Arkansas. So that's going in front of the commission. And so we are hopeful that we'd get an order approving that transfer either later this year or early next.

And specifically with respect to Georgia, the procedural schedule calls for a final decision come February. So you can make your own call in terms of how you believe those work out, but I certainly don't think it's aggressive for you to assume July 1, that both of those utilities will be part of the Algonquin family. Specifically with respect to your comment on continuing to grow the business, I don't think it should be lost on people that even if we were to announce something today -- and we obviously are not -- we're probably talking about 2014 business in any event just given the typical regulatory lag. And so we have a dedicated transition team who are obviously fully engaged, both in continuing to wrap up the transitions of -- in New Hampshire and Missouri and Iowa and Illinois, and those are going well. And preparing for the transactions -- transitions in Georgia and Arkansas. It's a group that we fully intend to kept fed, if you will.

And so the business development group, and I think it's fair to say that includes myself personally, spend a lot of time trying to make sure that, that acquisition pipeline remains full. And so that you may well see an announcement from us before next fall. But the reality is that even if there was an announcement in Q1, we're probably talking about something that won't be really hitting the transition team or the workgroup until 2014. I don't know if that's the color you're looking for.

That helps a lot. Thanks, Sean.

(Operator Instructions)

Ian Tharp, CIBC World Markets.

I think at the Investor Day, we talked about it. I think you also gave some other details prior on the [GAR] front. So the issues faced by Superior Plus. And I think, David, our last discussion intimated that the CRA had not approached you and hinting at any type of challenge. So just wondering if there are any updates with respect to Algonquin on the GAR front.

No. No further updates from that.

Very good. Thank you.

Jeremy Rosenfield, Desjardins Capital Markets.

Just a question on the acquisitions, keeping on the same line of questioning that you were on before, just curious to know if you've either maybe narrowed or potentially widened your scope of acquisition targets that you might be looking at, either in terms of size or geographies. And then as a follow-on to that, maybe you can comment on how you're seeing valuations at the current time in the utilities sector. Here, I'm thinking more in terms of what companies are looking at their own values on that side and how that equates to, let's say, what value you'd like to be paying for acquisitions.

Sure. Let me start on the first part of your question. Jeremy, with respect to geography and size. With respect to size, I think we remain comfortable that in the CAD100 million to CAD200 million, to CAD300 million EV remains our sweet spot. And I think that's our sweet spot for a couple of reasons. One is relative to our own size. I think it's a good number. And it allows us to move the meter, if you will, with that size of investment.

But I think perhaps more importantly, and this gets to the second comment that you raised, which is valuations, I think we are pleased at the disciplined premiums that we've been able to pay in that size space. And I'm not so sure that we would be able to accomplish the same if we upsized our targets to the CAD500 million to CAD700 million range. I think one needs to look at how Central Vermont's Public Service and CH Energy, and perhaps even the current process which is underway in Missouri for the sale of energy transfer equity limited partners interest in Missouri Gas Energy. Those are very robust processes which are attracting much higher premiums, which to be frank, are a little bit inconsistent with our value thesis.

And so were remaining -- I don't want to say downscale, because we think we see these assets as being great additions to our portfolio, but we think it's keeping our size where it's at will allow us to achieve our objectives. Geographically and just to touch on that, we did put out some -- on our map and thank you for your speculation on what we might or might not be buying. We are following on a couple of your leads. Thank you.

You're welcome.

But we very much are continuing to build those clusters of assets and -- but it should be clear, we're not uncomfortable if we can have line of sight to CAD100 million plus in a particular state, adding that to our portfolio. So I think we're probably more focused on choosing regulatory jurisdictions that are supportive -- have a supportive environment, have an organic growth aspect to it. Those are probably our biggest focus rather than necessarily trying to achieve some, perhaps even almost illusory economies of scale. I don't know if that's helpful color.

That's excellent color, thank you very much. I have one maybe follow-up to that which was related to the last part of what you are stating in terms of follow-on investment opportunities. At the utilities that you have right now or the ones, let's say, that you're just closing specifically in New Hampshire, can you speak a little bit about the follow-on investment opportunities that you'd like to pursue over the next couple of years? And also the rate cases that you expect to be filing there, I know that you had previously disclosed potential EBITDA increases. I think on the order of CAD9 million to CAD10 million for each of those utilities potentially?

Yes. Sure. Well, let me just start by saying that focusing on organic growth within an existing footprint is a commitment or objective that applies to all of our utilities, not just those in New Hampshire. And I think Calpeco is probably, I want to say, a better example because it's been in our hold for over a year now and actually coming close to two. And we're very much focused on follow-up opportunities within the service territory. And including rollouts of additional utilities, transmission investment opportunities within the state. Obviously the state has lots going on that -- with their currently anticipated growth in RPS to over 30% in not-too-distant future.

Specifically with respect to your comment with respect to New Hampshire, we are seeing growth opportunities to extend service into areas that aren't currently served. I think New Hampshire is a perfect example of a service territory that has great potential that, because heating oil and some respects even wood pellets are competing fuels, and the price of natural gas makes the conversion a very compelling proposition right now. We're seeing industries that are currently using number two heating oil willing to invest substantial amounts to get them serviced. And so we're bringing a focus to that, that perhaps maybe didn't have the same illumination on and that during national grids. So we are pleased that we are seeing organic growth opportunities. And you'll hear -- there will be bunched in singles, if you will, in the continued game going forward.

Okay. Great. Those are my questions. Thanks.

There are no further questions at this time. Please continue.

Great. Thanks, everyone, for joining us today. And now as always, stay on the line for the absolutely riveting disclaimer from Kelly. Actually, before we go, we actually did get a question from Twitter. And so just before we go, before you get Kelly's riveting disclaimer on forward-looking events, Kelly, bring us into 2012 with a question from Twitter.

Okay. Thanks, Ian. The question is Ontario's Green Energy Act in liberal government is under attack. What is your plan and timing for Amherst Island given political uncertainty?

Thanks, Kelly. As I mentioned in my prepared remarks, we are pleased that Amherst Island is continuing on. We have completed extensive environmental and social studies and have our application really substantially complete under the Renewable Energy Act. We expect to have it filed with the government and the local levels of government and in fact, all the stakeholders within the next couple of weeks. And so we are continuing to pursue the project. We are committed to it. We believe it's a great opportunity, both for Algonquin Power and its stakeholders, but also for the rest of Ontario.

So the timing is -- and we are continuing underway. We have a contract with the Ontario Power Authority and we obviously expect them to live up to it as will we. So there's the answer to the question, Kelly. So with that, again, thanks, everybody. And stay on the line for the riveting disclaimer.

Certain written and oral statements contained in this call are forward looking within the meaning of certain securities laws and reflect the views of Algonquin Power & Utilities Corp with respect to future events based upon assumptions relating to, among others, the performance of the Company's assets and its business, financial and regulatory climates in which it operates. These forward-looking statements include, among others, statements with respect to the expected performance of the Company, its future plans and its dividends to shareholders. Since forward looking statements relate to future events and conditions, by their very nature they require us to make assumptions and involve inherent risks and uncertainties. We caution that although we believe our assumptions are reasonable in the circumstances, these risks and uncertainties give rise to the possibility that our actual results may differ materially from the expectations set out in the forward-looking statements. Material risk factors include those presented in the Company's most recent annual financial results, the annual information form and 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 statements, whether as a result of new information, future developments or otherwise. Thank you.

Ladies and gentlemen, this concludes the conference call for today. Thank you for participating. Please disconnect your lines.