Algonquin Power & Utilities Corp (AQN) 2011 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and thank you for sending by. Welcome to the Algonquin Power & Utilities Corp. Q3 2011 analyst called. (Operator Instructions). I would like to remind everyone that this conference call is being recorded today, Friday, November 11, 2011, at 9 AM Eastern time.

I will now turn the conference over to Chris Jarratt. Please go ahead, sir.

Thank you. Good morning, everybody. This is Chris Jarratt and I'd like to welcome you to the 2011 third-quarter results conference call. With me on this call are Ian Robertson, our Chief Executive Officer; David Bronicheski, our Chief Financial Officer; and Kelly Castledine, Manager of Investor Relations.

For your reference, the Q3 financial statements and Management's Discussion & Analysis are available for download on our website at AlgonquinPowerandUtilities.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. This information was developed based on certain factors and assumptions, and we caution that actual results may vary from the forward-looking information. Kelly will provide further detail at the end of the call.

As an agenda for the call today, Ian will start with a discussion with a few of the highlights from the quarter, and following that, David will review the financial results. Ian will then provide updates on some of our growth strategies and opportunities, and at the end of the call, we will host a question-and-answer period.

I also note that all numbers referenced in this call are in Canadian dollars, and with that, I will now hand it over to Ian.

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

We're happy to be with you today announcing what we think are some solid results for the third quarter of 2011. The results of execution on our growth strategies are certainly demonstrating the stability and solid earnings that we had planned.

In addition to solid performance from our existing business portfolio, we had an active third quarter of diligently working through the various regulatory approval processes related to our committed utilities growth initiatives and further progressing our development efforts. So I'll start the call off by highlighting a few of these announcements before David provides some insight into the Q2 results.

During the quarter, we announced the execution of a 25-year power purchase agreement with Manitoba Hydro in respect of the St Leon II 17-megawatt expansion of our existing St. Leon wind energy project. The St Leon II project was shovel-ready ready when the PPA was signed since permitting had been completed in 2010 and the turbines were immediately available for construction, which I will point out commenced during the third quarter.

The expected early 2012 commissioning will allow this project to contribute to our 2012 EBITDA and lines up nicely with our multiyear business development pipeline. We had a successful groundbreaking ceremony at the end of August with the Premier of Manitoba and believe that our presence in the province of Manitoba continues to be strongly supported by both Manitoba Hydro and the St. Leon community. I'll have some further updates on our wind development efforts later in the call.

Also during the quarter, we were very pleased to announce that the Board of Directors approved a 7.5% dividend increase, bringing the total annual dividend on the Algonquin Power & Utilities Corp. shares to CAD0.28, paid quarterly at the rate of CAD0.07 per common share. This increase follows a previous approximately 8% dividend increase of CAD0.02 annually in March of this year, and is consistent with our strategy of delivering our compelling total shareholder return, comprised of an attractive current dividend yield and capital appreciation driven by earnings and cash flow growth.

As an update to our utility growth and the regulatory approval processes that are ongoing in Liberty Utilities, in New Hampshire we continued to progress on the Granite State and EnergyNorth acquisitions. Closings of these transactions are subject to state and regulatory approval, in respect of which the procedural schedule established in April of this year scheduled final hearings to occur in early 2012.

The acquisition of the Missouri, Illinois, and Iowa-based utility assets from Atmos Energy Corp. is also subject to state and federal regulatory approvals, which we continue to move forward. We believe to be on schedule with the process and expect the acquisition to close in mid-2012.

We believe that the well-maintained, high-quality utility assets associated with these initiatives align closely with our regulated utility growth strategy provide an opportunity to substantially expand our utility presence in the United States.

Algonquin Power & Utilities Corp. in America continue to progress two new regulatory approvals required by the Northeast Wind joint venture with First Wind to construct, own, and operate wind projects in the Northeast U.S. Closing of this transaction is subject to certain conditions, including regulatory approval, and is expected to close in early 2012.

We anticipate further successes as Algonquin Power & Utilities Corp., or APUC as we affectionately refer to it, and Emera work with First Wind to grow the project portfolio through the development of additional wind projects in the region.

And finally, with respect to the transfer of Emera's 49.9% direct ownership in our California electric utility, the regulatory approval application was submitted in early Q3, and we believe the process is on track for closing in early 2012. As previously announced, as consideration Emera will receive 8.2 million APUC shares in two tranches, with approximately half the shares to be issued following regulatory approval of the ownership transfer and the balance of the shares to be issued following completion of the utility's first rate case, which is expected to be completed in the latter half of 2012.

I'll now hand it over to David to speak to the financial results of the quarter.

Thanks, Ian, and now a review of Q3 2011. Revenue for the quarter was CAD66 million, and this was consistent with the revenues in Q2 of 2011 and significantly higher than the CAD44.8 million we posted in Q3 a year ago. Our adjusted EBITDA in the quarter was CAD25.8 million, compared to CAD28.2 million in Q2 and significantly higher than the CAD17.7 million that we reported in Q3 of 2010.

And now for some third-quarter highlights from our operating subsidiaries, beginning with Algonquin Power Company. In APCo's renewable-energy division, the key theme this quarter was strong hydrology and wind resources and high plant availability, and as a result, the division exceeded management expectations at our U.S. and Canadian facilities.

During the third quarter of 2011, net energy sales totaled CAD18.5 million as compared to CAD14.4 million in the same period a year ago, an increase of 28%. During the quarter, the division generated electricity equal to approximately 117% of long-term projected average wind and hydrology, as compared to 87% in this same quarter last year.

APCo's Maritime region experienced resources significantly higher than long-term averages as a result of some of the storms that blew through the eastern seaboard, producing 166% above long-term average resources, and the Quebec, New York, and New England regions also experienced higher resources than long-term averages, producing between 15% and 25% above long-term average resources. The Manitoba region experienced resources also above long-term averages, producing 5% above the long-term average, while the Western and Saskatchewan regions experienced resources between 5% and 8% below long-term averages and the Ontario region experienced resources of approximately 20% below the long-term average.

For the third quarter, operating profit totaled CAD13.8 billion (sic - see Press Release), as compared to CAD9 million during the same period a year ago.

In APCo's thermal energy division, our thermal energy division met our expectations for the quarter with our EFW facility slightly exceeding expectations as far as its production targets go and continued solid performance from our co-generation facilities in Connecticut and California.

Net energy sales revenue for the third quarter of 2011 was CAD6.8 million, as compared to CAD8.4 million during the same period in 2010. The decrease was mainly due to the Windsor Locks facility selling into the ISO New England day-ahead markets, compared to the forward reserve market as was the case in the same period in 2010.

For the third quarter of 2011, our operating profit totaled CAD6.7 million as compared to CAD7.3 million during the same period a year ago. And looking ahead to the next quarter, APCo's renewable and thermal divisions are expected to come in in line with our expectations.

Moving on to Liberty Utilities, you may have noticed that we are now reporting Liberty Utilities by geographic region rather than line of business. This is a direct result of the current and expected growth within Liberty Utilities. This approach will enhance operational efficiencies and guard greater economies of scale, while preserving the customer and the regulator focus of the businesses which arise from the independent operations of these regions.

For now, though, it's largely a nomenclature change. Liberty Water is now being reported as Liberty Utilities (South) and Calpeco is now being reported as Liberty Utilities (West). In the future upon successful closing of announced acquisitions, the Granite State/EnergyNorth utilities will form Liberty Utilities (East) and the gas utilities we're purchasing from Atmos will form Liberty Utilities (Central).

Liberty Utilities (South)'s wastewater treatment customer base grew by 3.6% and the water distribution customer base grew by 1.6% over the same period a year ago. Revenue for the third quarter of 2011 totaled CAD12.3 million, as compared to CAD10.2 million during the same period in 2010, an increase of 21%. Water distribution and wastewater treatment revenue both increased, primarily due to the implementation of the rate increases that we have put in place over the past two years.

For the third quarter of 2011, operating profit totaled CAD6.5 million, compared to CAD4.3 million in the same period a year ago. Overall, operating profit from Liberty Utilities water businesses met our expectations for the quarter.

Moving on to Liberty Utilities (West), net energy sales revenue for the third quarter was $6.7 million (sic - see Press Release), and there are no comparable results as we acquired the utility on January 1 of this year. For the third quarter, our operating profit totaled $3.3 million (sic -- see Press Release).

Looking ahead to the next quarter for Liberty Utilities, we are expecting continued modest customer growth for the remainder of 2011 throughout our service territories and Liberty Utilities (South) with revenue increases from the rate cases completed in Arizona and Texas continuing to contribute to higher revenues.

Liberty Utilities (West) is a winter-peaking utility, and we are therefore expecting its performance to be closer to the results we experienced in Q1. We will have more to say on the seasonality of this utility, as well as other aspects of this utility, at our upcoming Investor Day on November 28.

I'd now like to take just a brief moment to talk about our recent financing activities. Following on the successful CAD135 million debenture issue for APCo during the quarter and the redemption of our series of convertible debentures over the -- or earlier in the year, we did complete a public offering of 15 million shares for gross proceeds of CAD85.3 million. Proceeds will be used to fund a portion of the investment related to previously-announced growth initiatives for both Liberty Utilities and Algonquin Power Co. and to partially repay existing indebtedness and for other general corporate purposes.

Total value of financings completed in the last year is now in excess of CAD550 million. And as a result, we have completely transformed the capital structure of Algonquin Power & Utilities Corp. These efforts have lowered the risk [profile] of APUC, extended out debt maturities, and will provide additional financial flexibility to continue to successfully execute on our business plans.

In Q4, we will be back in the U.S. debt private-placement markets, raising between CAD135 million and CAD200 million of investment-grade utility debt in anticipation of approval of our U.S. utility acquisitions. We will also be arranging our working capital bank credit facility for Liberty Utilities that is appropriately sized for our expected utilities business in 2012.

I'll now hand it back over to Ian.

Thanks, David, and before we open the lines up for the really important part of this call, your questions, I want to give you a quick update on our growth strategies and prospects.

Starting with APCo, we are pleased with the continuing progress on the five development projects, with power purchase agreements that are outlined in our MD&A. Each of these projects is advancing on schedule through the development cycle.

As an update to the 75-megawatt Amherst Island wind project, in August the Ontario Minister of Energy directed the Ontario Power Authority, or OPA, to offer contact holders such as ourselves the opportunity to have termination rights under these contracts waived. We, of course, exercised this option and, as required by the waiver, submitted a domestic content plan and will provide the required the statutory declaration requiring -- regarding equipment supply commitments by the end of November, with the expectation we will satisfy the waiver requirements within the timeframe specified.

We have begun the environmental studies and preliminary engineering work, and the submission of the renewable energy application is targeted for the summer of 2012, with construction to commence shortly thereafter. We estimate that the project will take approximately 12 to 18 months to construct.

Our 225-megawatt Quebec community wind projects continue to progress through the development cycle. St-Damase and Val-Eo are in the preliminary permitting stage of environmental studies and public consultation, with a target to receive all authorizations by the end of 2012. To align, though, with a targeted commercial operations date set out in the Hydro-Quebec PPAs, construction of St-Damase is expected to commence in early 2013 with a COD, or commercial operations date, late in 2013, and construction of Val-Eo is expected to begin in early 2015 with a COD in late 2015.

Development on our 25-megawatt Morse, Saskatchewan, project continues with construction scheduled for early 2013 to mask the interconnection timing requirements of SaskPower.

Obviously, we also continue to focus on expanding this pipeline of contract and development opportunities. We have continued to work in several wind sites in Saskatchewan, including Red Lily Phase 2 and two responses to the Saskatchewan (inaudible) offers process under which SaskPower proposes to procure 175 megawatts of additional wind power. APCo has submitted an 87.5-megawatt project and 175-megawatt project proposal in response to this call, which SaskPower is expected to award in the first quarter of 2012.

In our thermal division, during the quarter we executed an agreement with the steam host Ahlstrom at our Windsor Locks facility for a revised and extended energy services agreement, which now continues through 2027. On the basis of this agreement, we have committed to the installation of a 14-megawatt solar T130 turbine, more appropriately sized to serve the mill requirements and leaving the existing 50 or so megawatt electrical-generating equipment to generate value in the ISO New England market.

The primary objective of this project is to de-risk and extend the value proposition associated with this facility. The total expected net capital cost of this project is forecast at approximately CAD17 million, taking into account certain grants and tax credits for which we believe we are eligible.

Now over to Liberty Utilities. In this business unit, we continue to focus on rate-regulated electric, natural gas, and water distribution utility and transmission-related investment opportunities in the U.S. We are hard at work with the regulatory approval process for our announced acquisitions, and are confident that the customer-centric utility proposition being advanced by Liberty Utilities is resonating with our customer, employee, and regulator stakeholders.

Back in April, we announced that Liberty Utilities (South) had entered into asset purchase agreements to acquire three rate-regulated water utility systems in the U.S., and we are pleased to confirm that the acquisitions of Noel Water Company and KMB Utilities Company, both in Missouri, have been completed and will contribute to the economies of scale in our Liberty Utilities (Central) region.

In summary, we have been diligently working through 2011 to seek regulatory approval on our announced acquisitions, while creating detailed plans for the integration of these new assets into the Liberty Utilities operating systems. We continue the same strategy to acquire additional assets to add to the Liberty Utilities family. On the power side, the status of our pipeline assets continues to advance, and we look to continue expanding our renewable energy footprint in North America.

Our consolidated earnings landscape will shift in the coming months as a result of the increased contribution from the rate-regulated utility side of our business. We believe that this shift has positive earnings stability and credit rating implications. Our strong year-over-year results are evidence of a strategy that is having a positive impact on the overall business and shareholder value.

And with that, I'd like to turn things back over to Chris to chair our question-and-answer period, but before I do, I would like to reiterate and reaffirm our invitation for all of you to join us for our second annual investor morning being held on November 28, 2011, here in Toronto. To register, you can either e-mail Kelly Castledine or simply to registration@AlgonquinPowerandUtilities.com.

And with that, I'll turn it over to Chris to chair our question-and-answer period.

Great. Thanks, Ian. And operator, you can go ahead and open the call.

(Operator Instructions). Rupert Merer, National Bank Financial.

Great quarter. So looking at the CapEx, it's good to see St. Leon moving ahead. You spent CAD16.9 million in renewable energy developments in the quarter. How much of that was for St. Leon and how much you have left up to commissioning?

We've spent approximately [CAD15 million] on St Leon II. Within the quarter, we're expecting to spend about another CAD10 million for the balance of the year, and then there will be a little bit tailing into 2012.

Okay, great. And then, the remainder in the quarter, how much of that was for the overhaul at Tinker and is there any left to go there?

The capital at Tinker was relatively modest in the quarter. Just going by memory, a couple million. The big push on the Tinker G5 project will come next year.

Okay, great. And then, finally for me, looking at the CapEx in thermal, you had CAD9 million. How much of that was for the Windsor Locks repowering?

There's basically two significant projects that are in that number. We've got a capital project at Sanger and we've got the repowering at Windsor Locks. The majority of that would have been the Windsor Locks repowering.

Okay. What's the scope of work at Sanger at the point?

It's just preparing to change out the --

What's happening, Rupert -- it's Ian -- is PG&E is upgrading the voltage of our interconnection from 69 KV to 115 KV, and that obviously necessitates a change in our main power transformer.

And while that sounds like initially just a load and a dragline up, I think the hidden benefit for us is that that increase in voltage also comes with a significant increase in capacity, and so, therefore, as you will recall with our repowering of Windsor Locks -- or Sanger a few years ago with the installation of the LM6000, we've got a substantial, like, 14 megawatts, of additional generating capacity, which is a little bit landlocked, if you will, from a delivery perspective.

Those constraints will be alleviated, and that's -- so that's a process for that couple of million dollar main power transformer upgrade. I think it unlocks that 14 megawatts of generating capacity. That's a project that is expected to be completed at the, I want to say, middle of Q2 of this coming year. It's really tied, as you can imagine, to PG&E's schedule, but that's kind of the best forecast.

Okay, great. And then, the CAD6.6 million grant from the Connecticut government, what are the hurdles you need to over before that amount can be confirmed?

Well, first of all, the amount is confirmed. We have a commitment for it. It's really -- we just need to meet the time -- the timing constraint of July 2012 for the commissioning of the expansion.

Obviously, we don't know -- what we don't know in terms of what's coming down the pipe from a schedule perspective, but we have very much planned for it. The major equipment deliveries are all targeted around meeting that date. Construction schedules are all targeted around that.

So, look, as we sit here today, we have high confidence in it, and that's why in my prepared remarks I mentioned that we thought about this as a total CAD17 million investment, rather than the gross amount, because I think we are confident in that grant coming through.

Great. Thanks very much.

John Safrance, M Partners.

Good morning, everybody. Just a question on the closing timeframe for Northeast, EnergyNorth, and Granite State, and please free to correct me if I'm wrong, but I seem to recall originally guidance would be for the fall of this year. Has that been significantly pushed back in terms of timing in Q1? Should we assume a January 1 start? Or should it be somewhere middle of the quarter?

Well, I mean, when the original procedural schedule was created back in April, it always showed, as we moved through the process, that that final hearing was scheduled for, I want to say, January 13, 2012. So that would be, hopefully, the kind of final gavel coming down.

The process in New Hampshire is one of settlements with a staff and the office of consumer advocacy, and we're pleased that we have had very constructive conversations, the most recent of which were settlement conferences held yesterday and the day before. And so, you know, it's difficult to predict how long it will take you to get through the issues and proposed settlements that are acceptable to all the stakeholders.

I like to think the issues are on the table, and we're working our way through them, and I don't think we're clutching our heart as we talk about the list. Obviously, we want -- we're coming to town here. We want to set the right tone, and so I think -- I don't think anything has fundamentally shifted. I think the perhaps earlier guidance of late 2011 is as much not knowing exactly how long it's going to take to get through the process.

I think as we sit here today on November 11, just the amount of time and effort and work that needs to go into papering and order and putting it in front of the commission probably makes that January 13, 2012, date sort of just a practical date to include, but I don't think there's ever been any fundamental shift or change in the tone or tenor of the discussions, John.

Okay, thanks for that. And just moving on to Atmos, given that it's operating in different states, do you see any risk to that process or are you fairly confident in that mid-2012 figure?

Well, we, I guess, see risk to the process. As again I mentioned in my prepared remarks, we -- I would suggest that the value proposition that we are advancing in each one of the states in which we are seeking approval actually is resonant. This idea of your local utility [fielding] back the customer-centricity and building positive regulatory relationships is very much welcomed.

Having said that, obviously you have add regulators into the mix, and I would say that it certainly changes the workload. We have three groups with whom we hold discussions. I personally have attended a number of technical sessions in all three of those states and met with the regulators.

I wouldn't -- I certainly -- risk wouldn't be the process or the term that I would describe. It certainly is work. We are committed to meeting the needs of those regulators, and there's nothing that leads me to believe that we won't be able to positively do that. We've been responding to data requests from all three of those commissions, and the discussions that have been going on outside of the formal technical session processes have been nothing but positive.

So, look, it's a lot of work, John. Nobody's kidding anybody, but I don't think we have encountered anything that leads us to be anything but continually cautiously optimistic.

Okay, great. And just the last question before I hop back in the queue. Your save the orphans program, are you still evaluating things on a fairly active basis? Or are you seeing that side of the business becoming a little bit more competitive in terms of the return that you're seeing?

No, look. I mean, I think that the strategy still is as effective from our perspective as it has always been.

I think when you stay competitive, I think the [CDPS] process that we saw where that utility went for 1.4 times a rate base, I think is more indicative of the size of the utility. When these things get up to CAD0.5 billion, CAD1 billion worth of enterprise value, there's no doubt about it. It becomes more strategic and the process becomes more competitive.

I think in the area where we're hunting and have been successful, the CAD250 million, as we sort of speak of chipping the rock off the side of the mountain, I think we are continuing to have success in those conversations. And the map has as many pins on it, if you will, of opportunities that it once had. Obviously a couple of those pins have turned into honest-to-goodness transactions, and we continue to follow that, John.

Nothing leads us to believe that -- it's not like you've seen lots of other transactions in that strike zone that we haven't been successful on. And so, I think we, again, remain committed to the strategy.

Great. Thanks very much for the update.

James Morrison, Cormark Securities.

So, between the equity that Emera committed for the Calpeco acquisition in Northeast Wind and National Grid, it looks like they will have about 20% of Algonquin after this most recent equity raise. So, do you expect them to continue on to the 25% threshold in the agreement? Or do you -- like in the form of a contribution to the Atmos acquisition?

Well, first of all, I don't when Emera's call is, but you might ask Emera that question.

But having said that, look, I think -- I would hope that the thesis for Chris investing in this organization, in Emera's commitment to this organization, remains as valid as it did when they first made the commitment. I don't think they would have sought our approval to increase their ownership to 25% if they didn't think there was value in going there. I would hope that you'd concur that the results that our existing asset portfolio are delivering and the prospects of the organization going forward look as positive as they did when the transaction got announced, and so there's nothing that leads me to believe that Emera is not -- remains -- does not remain interested in continuing to contribute.

I'd just touch on one thing that you did say, which was in respect of the Atmos transaction coming forward, I think just to kind of hit that nail on the head, I'm not sure we necessarily need to issue more equity for the Atmos transaction. I think, as we have pointed out even actually before this current offering, that the balance sheet, our balance sheet, following David's comment, is sufficiently robust and our internal cash generation sufficiently strong that I think the Atmos transaction could get closed without another equity offering.

And so, perhaps that the conversation about Emera would participate or not might be a little bit moot, but just to be responsive to your question, there's nothing that leads us to believe, and no conversations or comments have been made, that Emera doesn't remain as interested in the investment piece as they did when we announced our strategic investment agreement back in April.

Okay. Fair enough, and with regard to the Windsor Locks repowering, should we be expecting any sort of downtime? And when do you expect to break ground on that?

We've already, quote, notionally broken ground. The good news about that repowering is it's really installing yet another turbine inside the existing powerhouse, alongside the GE frame six. If you went down there, you'd see it all taped out on the floor where the turbine is going to go, where all the piping is.

The good news about the way it's going to be done is very little downtime is going to be necessitated as a result of this installation, and so, as I pointed out again in my prepared remarks, we think of this whole installation as a way to de-risk this proposition. I think, as I'm sure you have all looked at your own models, the issue with the turbine that we have right there, the frame six, is that it's -- while if the first [sparks] criteria in your favor, you're going to make a boatload of cash when you are operating it, but management may go against you in the market place. It's not such a great proposition.

And the nice thing about the way that the system has now been redesigned is we are now decoupled, if you will. The operation of that is decoupled from the needs to service Ahlstrom, which are our ongoing obligation regardless of the [sparks branch] in the marketplace. So, I think our expectation is 2012 looks not dissimilar from 2011 in terms of the ability to continue to generate EBITDA with no real material downtime.

Okay, great. And just one last quick one, you did a little bit of work to improve your tax shelters there. Where do you see yourself being fully taxable? In what year?

As you know, before this recent tax planning initiative, basically it's an internal capital structure reorganization that we undertook in the quarter, we were looking at 2013 to 2014. Obviously a lot depends on the performance of the business, but based on our current expectations, it looks like that horizon has now been pushed out at least for one more year, so we're looking at now the 2014 to 2015 timeframe.

Okay, great. That's it for me, guys, so I'll see you in a couple of weeks.

Juan Plessis, Canaccord Genuity.

Thank you. The contract renewal decision from the Region of Peel for the EFW facility, that's been delayed to February. Just wondering if you can comment on any options you might have if a renewal is not granted.

It's Chris Jarratt speaking. Yes, we certainly -- our first choice is obviously to do something with the Region of Peel. They've been our partner on the facility, or that facility, for 20 years. So, they are the logical choice.

But, of course, we have to pursue other options in the event that that doesn't come to fruition. So we have certainly been doing that.

I think the one thing that's kind of important from our perspective is that the -- it's our strong belief that that facility will increase in value dramatically as time goes on. Just a couple of interesting facts around that. There has not been a new incinerator built in North America since the 1990s. There's been no new landfills in Ontario since 1999. Regional municipalities have existing landfills which are rapidly filling up, so all these things kind of combine to make it our expectation that that facility has lots of other options available to it.

And I guess the other interesting factor that has come up is York Durham, a fairly close-by neighboring municipality, have just finished their permitting for a proposed incinerator, and just a couple of interesting facts. It took eight years to permit that facility and it's probably at least three years away from actual becoming operational. That is a 140,000-ton per year facility. Ours is about 177,000 tons, by way of comparison, and their costs are about CAD250 million.

So, all these things make us strong believers that there is lots of other opportunities for that facility, and we are pursuing them.

Okay, great. Thanks for that. Now, moving on, you're not proceeding with the purchase of the Louisiana Land and Water Company. Just wondering if you can give us some color as to why, and wondering if there's any costs associated with that, I guess, failed process.

Sure. I would say failed process might be too strong of a color, Juan. It's Ian speaking.

We had entered into the agreement to acquire it. The closing was subject to our continuing due diligence. It just that's the way the owner wanted to go. Obviously, if the results or the findings of -- that we had come up with during that due-diligence process, in the way that the deal was currently configured in terms of price and risks that we were going to be asked to assume, it didn't make sense for us to proceed.

I think the facilities still exist. I think the owner needs to consider where -- what the right strategy forward for him is. But sometimes the best deals are the ones you don't do, in the way they have been constructed, so I think it was the right discipline. It wasn't a huge investment, as you know. CAD5 million or CAD6 million with a rate base, always a nice thing to add to the portfolio. That certainly is certainly not -- I think it was the right thing for our group to sort of say the due diligence results didn't quite turn out the way we had expected.

Okay, thanks for that, and my apologies. The failed process term was a poor choice of words.

And just finally, just a housekeeping item here. You've written in your MD&A that in the third quarter, Liberty Utilities (South), their operating profits exceeded expectations. Now, I know that the rate increases accounted for the revenue increase, so did the division exceed expectations because of lower operating costs? Or was it something else?

It's really -- the growth, as you can see, the wastewater treatment growth at 3.6% certainly was -- is year over year higher than what we've experienced the last several years, so that definitely was a contributing factor to that.

And yes, the ongoing contributions of the rate increases, coupled with the higher customer count, it really is what was the major driving factor behind that.

Okay. Thank you very much.

Nelson Ng, RBC Capital Markets.

Good morning, everyone. Just in terms of the -- I guess your recent equity offering and you're sitting on roughly, I guess, CAD95 million of cash, given the, I guess, slight delay in the regulatory approval process, will you be able to do anything with that cash? Or are you just going to hold onto that and just wait for those transactions to close?

Obviously, we're doing everything that we can vis-a-vis, if you want to call it, a negative carry. Certainly it's not just being -- sitting completely idled, but certainly the proceeds are obviously intended for those major things that you referred to, and so, yes, we will be looking to put those funds to work with the expectation that those acquisitions are going to be closing early in the new year.

Certainly from our point of view, we value, and we believe the capital markets also values, a strong balance sheet, and as we looked at the markets in the fall and the uncertainty that seems to be brewing overseas, when we saw an opportunity to move forward with the financing, we thought that prudence of being the better part of valor called for us to do the offering when we did.

Okay. And then, just moving on to Windsor Locks, do you have any -- are you able to provide any kind of round numbers in terms of the economics of the repowering, like in terms of, say, payout period or equity returns or, like, IRRs?

Yes, sure. I think the -- Nelson (inaudible), I think the -- as I mentioned to John and in the prepared remarks, we really look at this as kind of a de-risking proposition.

I think the -- so from an EBITDA perspective, the number CAD3 million to CAD4 million going forward will obviously now be preserved with much less risk because our current operations are highly dependent on spark spreads within the marketplace, and we are much more de-coupled to that.

In addition, we've now [lost] the entire 50 megawatts of the (inaudible) available to participate, and so it's hard to fully quantify the contribution that that would make, but I think really what we are kind of hoping that the investment community sees as the extension of this out to 2027 has really kind of trading away upside for downside protection. That's really as much the mantra as we use around here as we think about our projects, and so I think the right thing is to consider a continuation of that going forward.

Okay. And then, just a quick question on, I guess -- I'm not sure whether you're able to talk about your involvement with Western Wind. In terms of why, I guess, you stopped pursuing that or stop looking at that asset, did you just not want to go hostile or did you not want to participate in a competitive process? Or can you just provide some color?

Sure. Look, we probably said pretty much all that needs to be said in the press releases. We have a certain style and perhaps professionalism that we want to bring to our business dealings. We had thought there was an opportunity to create value for the Western Wind shareholders.

As you can obviously follow from their press releases, they had a different view. I don't think -- I don't think the -- this organization has a number of prospects in front of it that is happy to pursue, and while going -- doing a hostile takeover is obviously not something that we would shy away from if it made sense, I think we came to the conclusion that in the circumstances that exist in the time, there are other places where we should be spending our time and effort. So I think, as I said, I don't want to say much more than that but I think you've read the record.

Okay. And then, just one last question. What's the uptake on the premium DRIP program?

We don't have all the numbers in the -- they come in basically quarterly following the dividend. That's just the way the CDS program works. So, we don't really have an update at this point in time. We just put it into place, but we expect next quarter we could certainly provide additional color at that point.

Okay, great. Thanks a lot.

Matthew Akman, Scotia Capital.

Wanted to pursue a little bit direction you might be taking on M&A over the next while, and obviously we know that small regulated utilities is in your target zone. I guess we also know that renewables are, with First Wind and the expression of interest in Western Wind, but I guess I'm wondering whether it might extend also to gas-fired power. You are putting capital into the assets you've got in Sanger and Windsor Locks. Would you also look at acquiring gas-fired power in the U.S.? Or is that out of the strike zone?

I think, Matthew, you have to kind of look at when you see gas-fired power, you're saying a mouthful there. Obviously the contract and nature of any particular asset is absolutely fundamental to the risk profile of that.

I think you'd look at the difference between Sanger, even, frankly, and Windsor Locks prior to the repowering. Those facilities are very similar in size, but as you can imagine, quite a different value proposition.

I think -- I say that this organization knows what it's good at. It obviously has a rich history as a developer of renewable power projects, and obviously we'd want to capitalize on that. We're not shy of owning the assets that we own in Sanger and Windsor Locks, and obviously are happy to continue to own them.

I will point out something might -- the capital power assets just didn't work for us. They just didn't fit the profile of the type of assets that we want to own and that we think is consistent with our risk profile going forward. The nice thing about the renewables as generating assets, as you know, your marginal cost of operating is like 0.005 or 0.01 to kilowatt hour. It's hard to imagine a marketplace, even after the contract had expired, where you're not going to be making positive margin. That's not the case, as you know, on some gas-fired facilities.

I think you're really, to be frank, I think the strategy if you're in the gas-fired business, it's almost go big or go home because if you can't get your heat rate down into that 7,000 range, which is competitive in the marketplace, you're just -- you're living on pins and needles when your contract expires.

Okay. So it sounds like not a significant focus, but possibly opportunistically if it fit your low-risk profile?

That's probably a reasonable statement, Matthew.

Okay, great. Thanks. That's all I had left, guys.

Wojtek Nowak, Fraser Mackenzie.

Thanks. Good morning, guys. It's Wojtek. I just had one quick question here on your admin expenses. They seem to have nudged up sequentially. Just wondering if there's any -- or what would be the one-time items there and how should we look at that going forward?

There's a few one-time items in there, but I think directionally what you're seeing is we are doubling the size of this organization over the next three to five years, and so as a result, we want to make sure that we have the appropriate level of support and infrastructure in place in order to support that growth. So I think, for the most part, you're starting to see our admin expenses moving in line with the expected growth trajectory that we're on.

Okay, thank you. That's it for me.

Marko Pencak, GMP Securities.

Thanks. Good morning. Your Morse wind project seems to have slipped a little bit to the right. Is there some specific issue that's affecting that and just your perspective on whether the timing is sort of contained or whether there could be potential for further slippage?

No, look, the project is actually very attractively placed from a wind resource point of view. Permitting is not an issue. Really the only thing that's driving it, frankly, is that power and the interconnection.

So we have to be responsive to SaskPower's operating plans for the lines. They're obviously committed. They've issued a PPA, and so it's really just about being responsive to those times. In fact, the project [or the deal] could be built in 2012. I think we'd just have to -- we're really just going to have to time things to make sure that when we are done, SaskPower is done. So that's really all it's about, Marko.

Okay. And on the last Q2 conference call, we discussed the financial conditions of some of the municipalities in the U.S. and opportunities that that may present, and you had commented, Ian, that you're looking for opportunities, but nothing has sort of happened yet. Two days ago, of course, Jefferson County, it's the biggest U.S. municipal bankruptcy filing, and it had to do with the payment of or inability, I guess, to service their sewer bond, so I just would be curious to get sort of an update from you in terms of what you guys are seeing in the U.S. in sort of the same context.

Look, we have always thought that the municipal -- the situation from municipalities made them kind of the Holy Grail for privatizations, and as we talked about probably last quarter, it's these guys have hung on tooth and nail. I think that that circumstance is those guys obviously hung on too long.

There are a few processes underway. You may be aware that Vero Beach has held a public referendum as to whether to sell their water and electric utility assets. And so, look, I think the pressure continues on these guys. They have obviously lots of places to put their money, and it's just hard to get the guys to come to the realization that an IOU, or an investor-owned utility, is the right thing for them to do, and I think it seems like the filings that you make reference to where you're kind of forced there. There's just no alternative now.

So you mention various processes. Aside from the ones that have been publicly disclosed, have they -- have some municipalities hired advisers who are feeling out opportunities before they go through the actual public process?

Yes, we certainly have been approached by advisers saying that -- and are participating in them on sort of a quiet basis. Obviously, what we're trying to do is also be responsive to them, to say -- to their needs in saying maybe this feels like a public-private partnership, rather than just an outright sale.

So we're trying to be flexible as we have conversations with these guys, but Marko, your speculation is correct in that there are a number of nonpublic processes going on and discussions that are under way between ourselves and municipalities or cities with respect to their utility assets.

And have any of those processes gone far enough where you are able to start, at least on a preliminary basis, assessing the economics returns, or is this still at a much higher level just in terms of conceptual change in the ownership structure?

No, in some respects it almost starts right in the beginning when you have a conversation with these guys. The question is, what's the value of the seal in the ground? What are you looking to do from a rate perspective? Because that, in fact, drives the amount of cash that the city is able to lever under those assets, that is obviously more seal on the ground or they're less sensitive to what might happen from a rate perspective, obviously the valuation goes, gets better.

And so, no, I'd actually say that the conversations that we are having start almost with, like, how much is this worth because the city fathers with whom we've had these discussions are all about trying to solve their problems. And frankly, if they were only going to say CAD5 million out of it, it is not going to solve their problem. If there's CAD100 million of value there, well, that's a different issue.

And just the last part of that, then. Would it be fair to say that -- or have you found that the ballpark economics are coming into ranges that notionally would be acceptable to you guys?

To be frank, or we wouldn't be pursuing an opportunity that didn't have economics which were similar to those expected in a normal regulated IOU business. And as you know, kind of ROEs in the 9.5% to 10.5% range with equity thicknesses 50 or [above]. Those are the conversations that we've been having with them, but obviously we're not interested in taking a lower return than that which we could attain elsewhere for the exact same risk profile.

Great. Thanks for the detail.

Matt Gowing, Maki Research Capital.

Good morning, everyone. Congrats on the quarter. Ian, you mentioned earlier in the call on the Sanger, the completion of the voltage upgrade on the lines to 115 KV, and that should be completed middle of Q2. Will you be able to capitalize that immediately, start delivering more power, generating more revenue right after -- like right in the middle of Q2 or will there be some subsequent agreements with Pacific Gas & Electric that you need to make before you can start capitalizing on that?

Well, now that (inaudible) exists, and I think you actually point out, which is, okay, now we have to come up with the commercial arrangements for the delivery of that power. We have had conversations with PG&E. I think it's a little early today for me to say oh, April 3, Matt, we're going to start selling 14 more megawatts worth of generation at CAD50 a megawatt hour. I don't think that's -- we're not at that stage yet.

So I think we're just going to have to stay tuned to move those discussions ahead. I think my comment really, frankly, was really about this upgrade, while it's mandated by PG&E, it does have some benefit for us, and so I don't think we're disappointed that we have to put the capital into a new main power transformer for ourselves. But maybe what we will try to do for our Q4 earnings call is, perhaps even for our investor Day on the 28th to try to lure you to come, is maybe we can give a little bit more color on that at that time. I'll make sure that in Mike Snow's presentation for APCo, he kind of gives a bit of a deeper dive into the markets in which we would be selling that 14 megawatts.

Great. Now I'm definitely going.

A question related to the construction of the Sheffield plant through your Northeast Wind of joint venture, is that construction progressing nicely? Still expecting to reach commercial operations in Q4?

Yes. That's the case. It's right on schedule.

Great, great. And then, related to your CAD470 million capital investment plan for your 165-megawatt APCo advanced development pipeline, what's your financing strategy on those projects? Are you looking at partnering on certain projects? And do you have any -- are you in the discussion or negotiation stages with any potential partners there?

Well, on the projects that are in front of us right now, the contracted assets that we have, I think those are fully within our wheelhouse to complete on our own.

I think the First Wind acquisition or the First Wind investment is an example, though, Matt, that we are prepared to be flexible and partner up to leverage our capacity across jurisdictions in which we're not already active. I think First Wind, as you know and from the deal that we've announced, have a focus on Maine and Vermont and New York and places that we just haven't had, so this is a great opportunity, I think, for us to leverage our capacity, not [necessarily] our capability.

Obviously I think within this organization, we are totally capable of doing these things ourselves. The assets that you make reference to, I think, are within the financial capability of us to own alone. We're not adverse to having conversations about partners. I just don't think we need it for those assets.

Great. Thanks. One last housekeeping item. The passthrough revenues that are booked to the Liberty Electric West, so Calpeco, 2011 through the quarters, is that a good reflection of the seasonality for that passthrough revenue in subsequent years?

It would be. The year has been, I will say, average and typical from our point of view, and so that is probably a good prospect for seasonality.

Obviously, you haven't seen the last quarter. David had kind of intimated that as we get closer to the winter months, given that this is a winter-peaking utility, you'd expect those passthrough revenues to rise. And since obviously some of our general rates are tied to a per-kilowatt hour rate, obviously our operating profit kind of has a seasonality associated with it.

As a further inducement to get you to come to Investor Day, it is our intention to kind of give the entire capital market some deeper-dive clarity into the seasonality of all of our utilities. You can imagine that the water utilities in Arizona have a countercyclical seasonality to that [witchards] peaking utility in Tahoe. The gas utilities have their own obvious cyclicality associated with them.

I think our intention is to give the capital markets some clear indications, on perhaps a utility-by-utility basis, how we see the EBITDA is shifting from quarter to quarter to help you guys in your estimates. It's always -- we want to make sure that what we call a quarter a win, you think it's a win as well, and that it's not because of a difference of opinion of seasonality.

So, yes to your question, Matt, but again, stand by and we'll give you more information on the 28th.

Great. Thanks a lot and I look forward to it.

Jeremy Rosenfield, Desjardins Capital Markets.

Good morning, everyone. At this point in the conference call, I think most of my questions have been answered. The only one that I would have outstanding at this point would be with regard to the potential for any upcoming projects in Quebec. We've been hearing that province is readying to issue some new requests for proposals on that side. Do you have any prospects that you would be readying to submit here?

Oh, yes. We have a number of projects that we had submitted in the last round that have continued to advance since the [apetados] in 2004, I think it was, and so, yes, I think we're going to be active in that process as well.

Do you have any numbers that you can break out for us, or at this point it's too preliminary, or maybe just the number of prospects?

Look, I don't want to do it on the call kind of on the back of a napkin. Again, I think -- again, we'll make a note of that and try to give a little bit of color on that on our Investor Day. So again, to lure you from Montreal to come up here.

It's hard to lure somebody from Montreal to Toronto, but sure. Definitely. I'll see you guys, then. Thanks.

Michael McGowan, BMO Capital Markets.

Good morning. I have a couple of procedural questions. With respect to the closing of the New England utilities, you mentioned an early January hearing date. Now is that sort of a one-day hearing or is that a process that could take a few months to -- for the commission to reach a determination?

No, in New Hampshire, the process is really about reaching agreement with [staff] and the OCA, and those hearings are very much procedural in nature. It's about the gavel coming down on an agreement that's reached by the parties. It's just not the nature of their process to have a long, litigated process.

In general, I think it's fair to say that the commissioners are [resident] to have a litigated hearing where there's a fundamental difference of agreement with staff on what's the right thing to do. The good news on that one is I think we have had very positive and constructive conversations with staff, and so I think our expectation and hope is that we go in hand in hand, which is their normal course of business, with staff and the OCA to say we all endorsed this.

Okay. So, then, on January 13 or a couple days thereafter, those deals should close?

That would certainly be the expectation.

Okay, great. And just a question on Windsor Locks again. The large 50-megawatt turbine that you have there right now, any plans to decommission that or are you just going to continue to operate that for a number of years and essentially try to capture incremental margin with that asset?

Yes, no reason to disconnect it, decommission it. I think that it's got an interconnection into the CLRP territory in what is obviously a generally congested node in New England ISOs.

The operating cost, if you will, to staff it so it's available to turn on when the spark spread makes sense for us are all being covered by the solar turbine going forward, and so in some respects we look at it as a free auction to participate in the New England ISO capacity and energy marketplace, and so, frankly, no thoughts of decommissioning it. There wouldn't be any savings, to be frank, and I will say that its value is measured by its weight at scrap metal, but the used [LL or breen six] market is not particularly strong. That wouldn't be a compelling reason to decommission it.

Okay, great. Those are my questions.

Ian Tharp, CIBC World Markets.

Thanks. Good morning. I can safely say all my questions have been answered except for one. And it's around the engines. You referred to a slight downtick in revenues regarding your participation in the ISO New England day-ahead market versus the forward reserve market. So, I wonder, obviously you set into it with eyes wide open in terms of estimates. Any kind of reflection on that and options to potential change it if it, in your view, it will continue?

Well, I think the downtick in revenues arising from that is probably a result of the market-clearing price in the forward reserve. We just felt that our fortunes were better served by not taking that lower clearing price, and obviously there is a certainty, if you will, that comes with participating in a forward-reserve market, but the option, to be frank, cleared at a price which was significantly lower than what we thought our alternative revenues were, and we were right.

I think it was the right call. We made more money preserving the flexibility of participating in day-ahead than we would have with the certainty of the forward reserve. Obviously we are -- that's, as I mentioned during Mike's question, is we will continue to have that optionality in front of us going forward. Frankly, with the [premium sticks] not being committed to anything is the nice thing -- if we think we'll make more money taking the [four hundred] payment, we will go back into that and bid in the auction at a different price point, and if we think our interests are best served by participating in the day-ahead, we will.

I think if there's one thing that, anecdotally, you can take away from our last experience is that the machine and the system have been competitive in the past in the marketplace on a spark-spreads perspective, and so there's nothing that would lead us to believe that that won't continue ongoing forward. And so, look, obviously the forward capacity reserve market price point changed, but I think the value proposition still exists for our system.

Good. It sound like you still have optionality there, so thanks for the detail. We'll see later this month.

Sean Steuart, TD Securities.

Thanks, guys. Just one question. Everything else has been addressed. The SaskPower wind RFP, you wrote in the MD&A you're expecting PPAs to be awarded Q1 next year. I guess last quarter, we were under the impression that we'd hear something by the end of this year. Can you give any context on delays there? I'm taking -- I'm assuming this is nothing really material, but any context you can give would be appreciated.

Actually, I didn't know that -- if we had given the guidance at the end of this year, I guess I'm trying to rack my brains to think of what that came from. Clearly, as we speak of the first quarter of next year, we're really just parroting the process as articulated by SaskPower.

So, Sean, I can't give you any meaningful guidance. It may turn out -- it may be, and I'm just speculating now, that SaskPower themselves had extended the curve. As you know, the submission date got extended a couple of times of the RFP, and so that may have resulted in the extension. But from the day we have submitted, I guess, that RFP, I don't think there's been any delays or extensions, and certainly nothing that leads us to feel anything but optimistic on our chances in that submission.

Understood. Thanks for all the detail on the answers, and we will see you in a couple of weeks.

(Operator Instructions). Gentlemen, we have no further questions at this time. Please continue.

Great. Thanks. Thanks for everyone and, again, looking forward to seeing everyone on the 28th. I'll turn it over to Kelly for a quick 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 compartments of the Company's assets and the business, financial, and regulatory climate 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 that 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 any 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 statement, whether as a result of new information, future developments, or otherwise. Thank you.

Ladies and gentlemen, that does conclude our conference call for today. Thank you for your participation and you may now disconnect your lines.