Algonquin Power & Utilities Corp (AQN) 2012 Q4 法說會逐字稿

Good morning, ladies and gentlemen and thank you for standing by. Welcome to the Algonquin Power & Utilities Corp Q4 analyst and investor call. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session, and instructions will be given at that time.

(Operator Instructions)

I would like to remind everyone that this conference call is being recorded today, Friday March 15, 2013, at 10.00 AM Eastern time. I'll now turn the conference over to Kelly Castledine. Please go ahead.

Good morning, everyone. Thanks for joining us on our 2012 fourth-quarter and year-end results conference call. With me today are Ian Robertson, our Chief Executive Officer, and David Bronicheski, our Chief Financial Officer. For your reference, additional information on our results is 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. I will be back at the end the call to provide further details. This morning, Ian will discuss the highlights for the quarter, David will follow with his review of the financial results, and then we will open up the lines for questions. I would ask that you restrict your questions to two and then re-queue if you have additional questions to allow others to the opportunity to participate. In addition, we will be accepting questions via our Twitter page. @AQN_Utilities and as time permits we will ask them on this call. I'll now hand it over to Ian.

Thanks, Kelly and good morning, everyone and thanks for joining us on the call today. As you are probably all aware, 2012 was a very busy year here at Algonquin, having exceeded our expectations from a strategic growth perspective in both our regulated and non-regulated utilities businesses. Following the successful completion of the regulatory process in New Hampshire and the mid states, we closed both of those acquisitions, and are now in the continuing process of integrating these new assets, customers, and employees into the Liberty Utilities family. We also completed the acquisition of a 60% interest in a 400-megawatt portfolio of US-based wind generating facilities.

The closing of these transactions marks a significant milestone in the continued growth of our Company, and we believe these acquisitions will strongly contribute to our strategy of providing attractive total shareholder returns, comprised of stable dividend yields, and continuing capital appreciation. We've already demonstrated the continuation of our strategy in 2013, with the early January announcement of the acquisition of the 109.5-megawatt Shady Oaks wind power generating facility in Illinois. Additionally, we completed the previously-announced acquisition of the 17,000 or so customer Arkansas Water Distribution Utility and with respect to the 64,000 customer Georgia gas distribution utility announced in August of last year, we have now received all regulatory approvals and expect to close on April 1, ahead of our initial expectations.

In February of this year, we entered into an agreement to purchase the assets of New England Gas Company, a natural gas distribution utility serving over 53,000 customers in the State of Massachusetts. The completion of this CAD74 million acquisition is subject to customary approvals and is expected to close in the second half of 2013. These activities contribute to our publicly-stated 2017 objective of having one million regulated utility customers and one million kilowatts of installed generating capacity. With Liberty's total customer count expected to close in on 500,000 in 2013, and APCo's interest in non-regulating regulated power utility assets suppressing the thousand megawatt mark already. We believe we are progressing satisfactorily towards this objective.

We have a few financing highlights to mention this quarter, and while I'll leave it to David to discuss the details I would like to briefly mention that during the fourth quarter we were very pleased to have successfully closed our offering of approximately 5 million, 4.5% cumulative rate reset preferred shares for gross proceeds of CAD120 million. These preferred shares effectively replace our final remaining series of convertible debentures which were redeemed as of January 1 of this year, and provide an additional source of attractively-priced capital to fund our continuing value accretive growth initiatives.

Additionally, in February of this year, we reinforced our already strong relationship with Emera, through an additional agreement to subscribe for approximately 4 million common shares of APUC at a price of CAD7.40 per share. Consistent with past practice, this transaction represented a CAD0.10 premium to the closing price of APUC shares as of the time of announcement. This will bring Emera's total investment in APUC close to the maximally permitted 25% under our strategic investment agreement. I'd now like to hand things over to David Bronicheski, our CFO, to speak to the financial results.

Thanks, Ian and good morning, everyone. As most people on the call today can see, 2012 was a year of transition for Algonquin, and it was a year where management positioned Algonquin for strong growth in 2013. I'd like to note that with our decision to divest of our small US hydroelectric generating stations in 2012, we have classified these facilities as discontinued operations in our financial statements, and therefore, I will discuss our results reflecting continuing operations. Overall, we ended the year with adjusted EBITDA from continuing operations of CAD106.2 million, which is an increase of CAD2.5 million over last year's year-end results of CAD103.7 million. Even though we were affected by lower than average wind and hydrology for a good part of 2012, this lost revenue and EBITDA was positively offset by the mid-year acquisition of our newly acquired gas and electric utilities in the US.

So now let's move on to specific details. In 2012, we showed revenue of CAD369.9 million, and this compares to CAD276.6 million in 2011. Our EBITDA in 2012 from continuing operations, as I mentioned CAD106.2 million, compared to last year's CAD103.7 million.

Now a bit more details about our operating results from our subsidiaries. In APCo's renewable energy division, during 2012, net energy sales from continuing operations totaled CAD75.3 million, as compared to CAD77.8 million in the same period a year ago. During 2012, the division generated electricity equal to approximately 91% of long-term projected average wind and hydrology, as compared to the 99% that we achieved last year. For 2012, the renewable energy division's operating profit totaled CAD57.8 million as compared to CAD60.6 million during the same period a year ago. At APCo's thermal energy division, briefly touching on the operating results, they were generally in line with our expectations for the quarter. On the year, thermal posted an operating profit of CAD17.7 million, as compared to CAD20 million during the same period a year ago, with the decrease largely the result of planned outages during the year.

Looking ahead, for the first quarter of 2013, APCo's renewable energy division is expected to perform based on long-term average resource conditions for wind and hydrology. Late last year, our Long Sault facility experienced an unplanned shutdown, and will be brought back to full production levels over the course of the first half of 2013. In the interim, we expect the lost revenue to be made up through our business interruption insurance. Clearly we are expecting additional revenue in the first quarter of 2013 compared to last year, as a result of the acquisition of four new wind assets, including the Shady Oaks wind farm, which we closed on January 1 of 2013.

For our thermal division, we have no planned outages in 2013. The Sanger facility is expected to perform at comparable levels to results experienced in the first quarter of last year, and the repowered Windsor Locks facility will be better able to match production with demand from the mill while limiting our exposure to the more volatile market power pricing in New England. At our EFW facility, we are pleased to note that as expected, we received approval from the Ontario Ministry of the Environment for an amendment to the facility's permit, which now allows the facility to accept waste from all of Ontario. We have entered into several waste supply agreements to ensure continued operation of the facility, now that the contract with the region appeal has expired.

Moving on to the utilities, in 2012 Liberty Utilities reported an operating profit of CAD48.7 million, as compared to CAD44.5 million a year ago. The increase in operating profit is primarily related to the contribution of the recently-acquired assets in Midwest and New Hampshire. For Liberty Utilities West, during 2012, we experienced an increase in water distribution and wastewater treatment revenue of CAD1.2 million when compared to the same time a year ago, but there was a decrease in net electricity revenues of CAD3.1 million, due to lower electricity sales that occurred in the first quarter of last year. In central, in the fourth quarter of 2012, water distribution and wastewater treatment revenue was CAD9.1 million, slightly higher than the CAD8.8 million that we achieved in 2011, and also during 2012, the Central's net revenue from the Midwest gas utilities was CAD12.2 million.

Moving onto Liberty Utilities East, net utility sales both gas and electric totaled CAD38.6 million during the fourth quarter of 2012. As a result of the assets being acquired during the third quarter of 2012, no comparable results are available for 2011. As we look ahead to next quarter for Liberty Utilities, we are expecting continued modest customer growth throughout 2013 in almost all of our service territories. Our Q1 2013 results will reflect the acquisition of our Arkansas water utility, which we are pleased to note was closed on February 1, 2013. An additional rate case filing will be made for our Litchfield Park water utility in the first quarter of 2013. In addition, I'd note that the Rio Rico rate case, which was filed in 2012, is seeking an increase, which if approved as filed is expected to increase EBITDA by CAD1 million over the results achieved in 2012. In addition, plans are in place to file a rate case with the New Hampshire Public Utilities Commission for our New Hampshire electricity distribution utility during the first half of 2013, with interim rates expected to come into effect around mid-year.

I'd like to take a moment to review some of our recent financing activities. As Ian mentioned, we were pleased to add referred shares to our capital structure toolbox in November of last year. We issued 4.8 million preferred shares, raising a total of CAD120 million. We feel that it's an attractive yield at 4.5%, and that it will have a positive impact on our cost of capital.

Additionally, during the fourth quarter, Algonquin entered into an agreement for a CAD30 million senior unsecured revolving credit facility with the Canadian Charter Bank. The credit facility will be used for general corporate purposes, and has a maturity date of November 19, 2015. We also completed the redemption of our outstanding Series III debentures, and delivered CAD13.3 million APUC common shares to do that. On the APCo side of the business, in November 2012, we issued CAD150 million of 4.82% senior unsecured debentures, with a maturity date of February 15, 2021, pursuant to a private placement here in Canada and the United States. Concurrently with the offering, we entered into a fixed cross currency swap coterminous with the debentures to economically convert the Canadian dollars into US dollars, and as a result, we also achieved a lower effective interest rate of 4.4%.

As noted in our year-end disclosures, I just point out that we completed a $15 million private placement at Liberty Utilities, using our utilities master debt platform. The financing of this ostensibly represents the long-term debt portion of the financing for our Arkansas water utility back in February. I'll now turn things over to Ian.

Thanks, David. Just before we open up the lines for questions, I would like to conclude with a brief update on some of our growth and development initiatives. On the APCo side of the business, we recently completed our final open house for the Amherst Island wind project, and are targeting the submission of the renewable energy approval application for April of this year. If and when approved, construction will commence shortly thereafter, and is expected to take 12 to 18 months to complete.

Our Cornwall solar project received its renewable energy approval in January of this year, and construction is set to begin in the second quarter. Commercial operation is expected in late 2013. With Liberty Utilities, we are focused on the integration of our recently acquired Arkansas water utility, and preparing for the closing and seamless transfer to Georgia gas utility in early April. Additionally, we are well into the first phase of the regulatory approval process for our New England gas acquisition, announced earlier this year. And as David mentioned, we have several rate cases underway or planned for this year, and look forward to sharing the results with you as we move through the process.

You may have noted in our MD&A that we had segregated for sale certain New England and New Hampshire hydro assets, which we have previously indicated were non-core to the APCo portfolio. While these are great legacy assets which have contributed positively to APUC's overall stable returns for well over a decade, as our portfolio crests the CAD3 billion mark, we concluded that selling some of these smaller assets was strategically appropriate. Sometimes prudent growth management is about selling things as well as buying them. We are pleased to announce that we have entered into an agreement for the sale of these assets to an established, privately-owned aggregator of small hydro facilities for ä purchase price of CAD27 million, which compares favorably to our CAD24 million book value. We would expect the transaction to close mid-2013.

Lastly, some of you may have noted a press release issued by Sagatay Transmission LP, in which our partnership with a number of First Nation groups in exploring certain Ontario-based regulated transmission projects was noted. While this initiative is at a very early stage, and the capital commitment during the development process is not expected to be material, we are enthusiastic regarding the prospects for these Ontario-based initiatives to provide material investment opportunities in the future. We will definitely keep everyone updated, as the opportunity to participate in Ontario's fledgling investor-owned electric transmission industry evolves.

To sum up, our priority for 2013 is to stay the course, and continue to build on the growth momentum we have generated over the past few years. We remain focused on identifying value-accretive development and acquisitions for both of our businesses, growing cash flow, and further strengthening our stable base of earnings. With that I'd like to open things up for questions-and-answer session.

(Operator Instructions)

Your first question comes from Juan Plessis from Canaccord Genuity. Please go ahead.

With respect to the Saint-Damase project, it looks like you're changing the turbine model and that looks like that's going to result in about 8.5% decline in expected production, while the capital costs are unchanged. So just wondering if you're going to be making up that production shortfall with a higher PPA price, or will this turbine change result in cash flow and earnings a bit lower than your original expectations? And maybe you can provide a bit of color on why the turbine model changed?

Sure, Juan. Let me start by saying that the turbine model change was driven by -- it was at Enercon's request. And I guess you've caught me a little flat-footed because I'm actually, as we looked at it, we were largely indifferent when we looked at the change from an energy production and capital cost perspective, i.e., it wasn't material -- it wasn't return dilutive if you will that -- the change.

It definitely did result in a delay to the project, but it was a request that came from Enercon's side of the table, and it has been approved by Hydro-Quebec, which you can appreciate, it needed to be approved by them. So I'm going to have to get back to you on the specifics in terms of any return diminution, but that was not my understanding, so that let that run that one to ground for you, Juan.

Thanks for that. Sticking with those two wind projects, Saint-Damase and Val-Eo, you mentioned in the MD&A, and I think for the first time, the potential for second phases of both of those projects with potentially 106-megawatt increasing capacity for each of those. Can you provide us with a sense of timing as to when those two expansions might be approved, and maybe some rough estimates on in-service date targets and capital cost estimates?

The expansion of those projects is really has been conceived, if you will, in response to the expectation of the coming of an RFP in Quebec, so I'll start by saying, in some respects the timing of the development of those projects will be related to whether Hydro-Quebec moves forward with the previously-anticipated RFP. I will say that in both the cases, we had the land, we have the infrastructure, it just makes common sense to leverage both of those in terms of participating in that upcoming RFP.

So I think, though it's no secret with the change in government in Quebec, the wind a little bit has come out of the sales of Hydro-Quebec in terms of their timing for that RFP, so I wish I could be more specific, Juan, but the timing of this really is being driven by Hydro-Quebec.

Okay. Thank you very much.

Your next question comes from Ben Pham from BMO Capital Markets. Please go ahead.

Just sticking on the power development side, and on Amherst Island, it looks like a little bit of a slight delay in COD there, and probably not significant in the overall scheme of things, maybe a few months or so. Can you talk about the reasons for the delay, and in addition now, that you've gone through the open houses is there any sort of potential friction points going forward, that we should be watching for in terms of affecting future timing and costs?

Let me start by saying that the delay that you see right now that's in the MD&A was occasioned by a longer than expected process in terms of working with some of the local townships to get through some permits from some archaeological studies, and we've presented those delays to the OPA in the context of the force majeure provisions under the contract. I think we're comfortable that those delays wouldn't result in a problem for the project. Obviously, sooner is better than later, but that's really just the basis of those delays. It took longer to get all of the archaeological work done.

In terms of the friction points going forward, I don't think it's any secret that there are diverging views, and I would say it's primarily centers on the aesthetics of wind projects in Ontario, and we are comfortable that our renewable energy approval application addresses, as best we can, all of the issues that have come up from stakeholders, both on the island and off. We expect to get that application completed early next month. And as you point out, the final open house was held, and it's really held in the context of public consultation to solicit all those views, to make sure that we are being responsive to as many of the concerns as we can.

Unfortunately at the end of the day, to the extent that you like or don't like the look of wind turbines, I'm not sure I could ever satisfy you, if you didn't like it. And we're just going to have to manage those. As we said, we try to be as responsive as we can to all the concerns of citizens. I think the Green Energy Act is pretty specific on how these projects are permitted and approved, and I'd like to think that we've been compliant in every aspect, both in spirit and letter of that legislation.

Okay. Thanks for that. My second question is on the utilities side, the New England acquisition, and that's certainly a pretty attractive valuation that you paid for those assets. Just curious, in terms of when you look at that asset, and the business risk profile of that asset, can you provide a general comparison of that versus some of your past utility acquisitions that you've done, where you pay a slightly higher premium to regulate the rate base?

Sure. I think you have to look at the New England gas acquisition in the context of how it came about. I think it's no secret that the Southern Union Group, who was the seller of those assets following their acquisition by Energy Transfer, Equity Energy Transfer Partners, that acquisition was coupled with the disposition of a much larger gas utility in Missouri called Missouri Gas Energy, and that transaction took place. It was announced in December of last year between Laclede Gas and Southern Union.

The New England gas assets, I don't want to say were they were clearly not the strategically driving part of the business from Laclede's perspective. They're a Missouri-based utility, they were very much focused on that transformational transaction that Missouri Gas Energy would provide to them, and I think we were fortunate as we looked at the valuation and looked at the circumstances, that we were able to acquire those. I think your observation is correct, acquire New England gas at an attractive acquisition premium.

I would point out that it's a relatively small utility. I think the premiums that get paid on utility acquisitions are definitely proportional to the size, because I think that speaks to the frothiness of the bidding or acquisition process. And so I guess I can only say, Ben, that you are correct. We do like New England Gas. We think it did come at an attractive proposition.

I think the risk profile is completely consistent with our other gas utilities in the New England area, specifically Energy North. And as to how the price involved, it was some respects a negotiated price between a willing seller and a willing buyer, and I think the circumstance allowed it to work out favorably.

Great. Thanks, everybody.

Your next question comes from the line of Rupert Merer from National Bank. Please go ahead.

First question, can you give a little more color on your acquisition pipeline? How has it evolved over the last few months in scale and asset class and geography? And are you seeing any new opportunities in wind with Gamesa?

Well, let's divide it into, obviously, the APCo and Liberty Utilities business. There are a number of publicly-announced utility processes under way right now. New Mexico Gas is in place, Source Gas, GE he has announced its intention to sell half of Source Gas. In addition we have, as I've always mentioned, that pushpin board worth of acquisitions that we think make strategic sense for us, and frankly strategic sense for the selling utilities, following our, as I said, tongue-in-cheek save the orphans campaign, where we look for these small utilities which are non-strategic to their large mothership and get in there and try to pitch the owners of these smaller regulated systems of the merits of the disposition.

The problem, of course, with that strategy is, they are by definition smaller, non-core and it's hard to get their attention. I will say and I think New England gas is an example, I think we're confident, Rupert, that we have that continuing pipeline. And you know we have this stated goal of growing our Utility and Power businesses by 15% a year. And that I think we are off to a good start. CAD75 million obviously doesn't hit that CAD150 million or CAD200 million threshold. But between now and the end of the year, I think that pipeline will deliver on the expectations of being able to announce the 15% growth. I can't be specific, just because the acquisition process is one where the timing isn't obviously to our control.

On the APCo side, I think it's pretty obvious that the growth from our Business is as much internally generated through our own pipeline of opportunities, and as Juan had raised the point, we are continuing to push forward on all of those and I think they are pretty well documented in the MD&A. You raised the specific point about acquisitions with Gamesa, and I am pleased and I think we announced at the time of our Gamesa acquisition, a bit of a strategic relationship with them to explore opportunities. We are continuing to do that.

Gamesa have, pursuant to their business strategy, developed a whole number of US-based facility growth plans, and we're looking at each of those carefully to see the ones that meet our objectives. I don't think it's any secret to say that the real key for making a power project opportunity viable is the availability of an offtake purchaser, so that you're not exposed to the volatility of energy price markets. That's just -- having that exposure is not consistent with our profile.

So consequently, our continued success in identifying future acquisition opportunities is largely going to be driven by the availability of power purchase agreements, or long-term power sales contracts. The good news, with the robustness and liquidity in the US energy markets, I think it will be possible for us to replicate the paradigm or success that we have enjoyed with the Senate, Sandy, and Minonk facilities that we acquired last year. I'm not sure -- I hope I was responsive to what you're looking for, Rupert.

Plenty of color there, thank you. Quickly on your divestment, when you look at your metrics for divesting assets, do you see any potential for additional asset sales this year?

I think we are always looking at managing the portfolio going forward. I will start by saying, selling things is always difficult for an organization, and particularly assets that were legacy to our success. Having said that, as the organization has grown and we look at the economies of scale of managing our assets, that threshold of what makes sense for us economically is rising. And so, I think we are constantly looking at the portfolio.

I don't think there's anything else that immediately rises to the level of the small hydro asset, that we in fact had announced last year, our intention to look at disposing, and that we are now pleased to have been able to complete that process. I think the thesis that we bought those assets, owned them, they generated revenue, we invested in them, and we are able to sell them at a small premium to our book value, I think exactly proves that what we try to do here, which is buy high quality assets, manage them, and then, obviously, preserve the value of them going forward. But there's nothing that immediately comes to mind, Rupert.

Okay. Great. Thank you.

Your next question comes from Nelson Ng from RBC Capital Markets. Please go ahead.

In terms of the US housing recovery, have you seen any noticeable changes in terms of usage, or an increase in customer accounts? I was just thinking about your water utility in particular, given its large presence in Arizona?

It's interesting that you mentioned that. We are starting to see green shoots, if you will, of the recovery in the housing market. As you know with the burst of the bubble back in 2008 or so, it got pretty bleak in the Arizona marketplace. We weren't quite at ground zero, but we felt the heat of the blast, if you will. We're now starting to see first of all the inventory of homes that had existed before is pretty much filled out, and we're now starting to actually see new homes getting developed, and you can see overall from a water, wastewater point of view, 3% growth this year is kind of where things have trended.

And the green shoots are that we're getting requests for extending service into new service territories, so it ain't quite back to the 10% a year that we had in the early 2000s, but I think we are cautiously and positively optimistic that the migration, if you will, to the Southern climes, will actually recur, and that we'll start to see organic investment opportunities in those utilities.

Okay. Thanks for that. My next question is in terms of funding -- your funding requirements, you have, you expected to close Georgia Gas on April 1. You have your New England utility in the second half of this year and then you also have a few wind and solar projects that are expected to be completed over the next two years. So what are your plans in terms of finance, and also your need for equity?

I think as we've shown in the past, we clearly have strong access to capital, both on the equity and the debt sides. And today, we've established solid platforms on both sides of our house, from a debt point of view. We have a master debt platform on the utilities side.

We just issued CAD15 million off of that platform just yesterday for our Arkansas utility. And clearly we'll be also issuing the debt portion off of that same platform for our Georgia acquisition that's closing on April 1st, and our New England gas acquisition that's expected to close near the end of the year. On the APCo side of the business, again back in December, CAD150 million off of our APCo debt platform, and again, as we move along with those projects, I think you will continue to see us issuing debt off of those platforms.

With respect to the equity, I think it's fair to say over time, we will need additional equity. You can't build an CAD800 million power pipeline out without some additional equity, but we keep our eye closely on our capital structure, and I think have sufficient flexibility to be opportunistic when it comes to our equity needs. But I will also point out that, just given the number of new facilities that we do have in our portfolio today, we are also throwing off a fair bit of cash, so we can self-generate a good chunk of that equity, as well.

Okay. Thanks. One last question, it's more high level. In terms of your involvement in the transmission line development, is this a sign that you would look to get involved in the very early stages, in general? Or is this a one-off where you're trying to build a relationship with the First Nations, or where you're looking to leverage your relationship into renewable energy?

Actually, I'd say that on be APCo side, if you first of all look at the history of this organization, as you know, we've been at the greenfield stage for power projects almost forever, for the 25 years since we started the business and so I don't think this reflects a material change. What is very interesting about this opportunity is that it really reflects an opportunity for Liberty Utilities, which has never really had the prospect of being a greenfield developer to develop its own pipeline of growth going forward.

I mentioned in response to Rupert's question, that our growth is has really been acquisitional, if you will, in Liberty Utilities. Nice thing about being able to get a pipeline of growth opportunities for regulated transmission assets, particularly in our backyard, I think it's very exciting.

Not exactly sure where this is going to lead, and not because we're not absolutely thrilled with the partnership of the First Nations, but I'm just not sure how Ontario's going to involve evolve in terms of its own investor-owned regulated transmission marketplace. This is something new for Ontario and gosh, being in our backyard, it just makes sense that we put some money to work in it. We are at the forefront of the development of this. It just completely aligned on so many fronts with Algonquin's thesis.

Okay. Thanks, Ian. Those are all my questions.

Your next question comes from John Safrance from Cantor Fitzgerald. Please go ahead.

Could you give us guidance on the Brampton cogen facility in terms of the tons that you would anticipate processing on a quarterly basis, and that CAD70 to CAD75 tip fee that you saw in Q4 apply for the rest of this year?

Well, I'll start by saying, John, that in our investor day, back in October of last year, we guided to CAD2 million, CAD3 million of EBITDA off of the EFW facility in 2013, and that was largely a result of this evolution from the tip fee, with the region appeal to a more merchant based waste supply relationship, which undoubtedly, there's no doubt about it, has a lower pricing.

Overall over the course of 2013, we were trying to target in and around that CAD55 a net ton based on our building those relationships in that marketplace. We fully expect to identify and secure higher-value waste streams, and we have been successful with a couple of waste streams with both private, and frankly actually with municipal suppliers. So, I think we over 2013, 2014 we'll be trying to trend backup into that CAD60-plus value waste stream.

With respect to tons produced, processed through the course of the year, we've a little bit changed our operating methodology there, just given the change in the value of the waste stream. You can imagine it doesn't make economic sense for people to stay up all night and do boiler cleanings when the waste stream value is lower, and consequently doesn't justify the overtime costs.

So I think we're targeting in the 130,000 a year range for 2013, primarily because of this shift in operating paradigm. But I think the key and perhaps from your perspective is I wanted to reinforce that previous EBITDA guidance that we had provided back in October of last year. The CAD2 million, CAD3 million off that facility in 2013.

Thanks for that. And in terms of Long Sault, I wanted to double check the CAD1.8 million or so of insurance that you have, that was looked on revenue line in the quarter?

Yes, it was.

Okay. Great. That's it for me. Thank you.

Your next question comes from Ian Tharp from CIBC World Markets. Please go ahead.

Just picking up on the question around the Brampton cogen, Ian, going back to your guidance of CAD2 million to CAD3 million clipped off of EBITDA for 2013, does that suppose that CAD60 a ton tipping fee, and that lower production or throughput of 130,000 a year? So those numbers really roughly get us to your revised guidance?

No. No. I think in 2013, you get to that guidance with the lower 130,000 tons, but probably closer to CAD53 or CAD55, and obviously as we move into the end of 2013, and we build these relationships that identify these higher-value waste streams, that's what led us to 2014, so you can work your own way forward in terms of the guidance for 2014. We didn't get into that in too much detail back in October, but specifically to be responsive to your question, that CAD2 million to CAD3 million was based on that CAD55 range and 130,000 tons.

Helpful. And if you could, could you talk a little bit about the negotiations that are likely taking place around longer-term contracts around supply for the facility? And is your hope that you would move from maybe shorter-term tipping sales to you, to a longer-term profile?

Absolutely. I think part of what this transition process is all about is about building those relationships with some of the municipal suppliers that take, as you can appreciate, a long time to foster. We have been able to enter into an agreement with Simcoe, we have responded to an RFP up in Guelph. So I think that we are very much trying to build those long-term relationships with municipal producers of solid waste. I think that's just the right thing from our Business's perspective.

Maybe we'll trade away some of those high-value tons that can be dug up on the merchant market, but in some respects this is kind of analogous to our preference for stability in our power purchase agreements, compared to the merchant energy markets. I think we would very much prefer to ink a long-term stable relationship with a municipal supplier. So yes, to what you're suggesting, Ian.

Okay. Shifting gears to the Gamesa wind assets, I was glad to see that Texas actually posted higher than long-term average production. I think it was the only asset that did. I wonder, you've spoken about the notion of potentially contracting the full capacity there. Can you give us a sense of if those discussions are ongoing, and if you're seeing some positive developments on that front?

It's early days. You can imagine certainly Senate and Minonk were acquired for all intents and purposes at the turn of the year, and so we've got 2.5 months of experience with them. We, too, were obviously pleased that when you start to look at you by a brand new asset, there is variability in the energy production. While there's been years and years of data that's gone into the long-term energy production, the asset is what the asset is, and you're always looking at it.

In terms of contracting, contracting for the remaining portion, I think you'll see that more take the form of us out in the marketplace, if you will, hedging that energy, rather than ultimately doing a physical contract with someone. And the reason being, we obviously have obligations under the existing power sales contracts with JPMorgan, and so I'm not sure we would want to disturb them by doing a physical contract for sale. But we do want certainty for that portion of the generation, the 25% or so of the generation which isn't sold pursuant to those contracts, and the way to get that certainty is ultimately by entering into some sort of a financial instrument to do it. So that's really where the focus is, Ian, is on developing, identifying, and executing on a financial hedge. I don't know if that makes sense to you.

It does. And there I assume your Energy Services division manages that exposure anyhow.

Absolutely. That's exactly what the business proposition for them being part of APCo's all about.

Sure. And then finally of course we know that Emera's interest in Algonquin is now approaching the 25% threshold. I wonder if you could give us a sense of whether there's opportunities for the threshold to be increased to just pick a number, 30%, 35% in terms of new opportunities that the two companies can pursue together in the next little while?

Well, in some respects that's really a question that needs to get posed to the Board as a whole. I think you accurately presented the relationship with Emera. I think we are pleased with the strength of it. I think Emera has done well by us, and we've done very well by Emera, and isn't that always the best, when it's a win-win for everybody?

In terms of increasing the exposure, I think there is sensitivity on the Board's part, I'm not telling stories out of school here, that at 25% everyone feels comfortable, and given the voting relationship that exists with Emera, that we haven't, if you will, crowded out or potentially displaced any value enhancing proposition that could come from the capital markets. I think there would be sensitivity that you start to get higher than that number and you do start to potentially have that crowding out take place, and so, while I'd never say never, and I think we're all thrilled with the relationship and I'm speaking on behalf of Chris Huskilson of Emera, but they did sign up to bring themselves up to the 25%. There's nothing in the cards right now, Ian, that's driving us to increase that.

Okay. Thank you. Those are my questions.

Your next question comes from Matthew Akman from Scotiabank. Please go ahead.

Staying with the Emera relationship, as it relates to the transmission investments that you're contemplating in Ontario, I'm just wondering, how you sort those out with Emera, especially in the sense that transmission of electricity is a core business for them? Is it really just about the magnitude of the investment opportunity, or are there other criteria that differentiate how you would sort those out?

I think it's a little early stage, actually, to have worked our way through those specific relationships. I think the geographic proximity of these opportunities to us is probably an important consideration. I think the size, as you point out, is an important consideration. We obviously discussed this at the board level, and I think you accurately point out that Emera are very good with respect to transmission investment opportunities, and we take a lot of comfort from having that guidance and advice on our Board.

But I think, just given the particulars of this circumstance and this situation, it really is probably a Algonquin area of interest rather than Emera, specifically in this circumstance. Obviously, if this thing became much larger and perhaps outside of Ontario we might have a different conversation, but as it sits right now it certainly makes sense for Algonquin.

Okay. Thanks for that. Shifting to Gamesa, you talked about possibly entering into some of the lateral contracts on energy and there's a little bit of energy exposure and rec exposure on the edges on these. And I'm just wondering if your expectations going into 2013, based on where energy and rec prices have gone are still consistent with the guidance you were giving in the fall?

Nothing has really changed from our perspective. As I think you accurately point out, it's around the edges if you will. We actually have been pleasantly surprised. I'll just talk about rec for a second pleasantly surprised that we've been able to surpass the original expectations from a rec sales perspective, though those expectations were not very aspirational, so it's not really material. If you surpass an expectation of CAD1 to CAD1.10, and you are only planning to sell 1000 of them it's not all that material but I'd say from the wreck side of things, we have been pleasantly surprised.

We are not doing very long-term. We tend to be looking at selling them over the course of a year and so there's no 20-year contract being contemplated on the wreck side. On the power side, I think you do accurately point out that shale gas continues to have a depressive effect on prices, and that's why I think we're very pleased to have had those power sales contracts in effect.

Though, I don't think our expectations and the forward curve that we have, upon which we based that guidance that we gave really have deviated very much. It's not like energy prices have taken a big drop in the past year from the time we looked at it, and so given its relatively small portion of the total revenue picture and the fact that our forecast really never really expected a significant recovery, or frankly change, I'd say in general, Matthew, that the guidance still holds.

Okay. Thanks for that. My last question for David is, given the success you had on the preferred issue, does that provide you with new flexibility on equity issuances? The rating agencies tend to provide 50% equity credit for that, and it could possibly reduce your cost of capital, as well, to do more perhaps and delay common equity?

Well, there isn't there is an optimal mix to the capital structure that we're always trying to focus on. The preferred shares, I think, does represent an attractive source of capital for us. Now, you don't get 100% equity treatment, as you know, with the rating agencies on that, so we do want to make sure that we're calibrating the capital structure towards our overall 50-50 guidance that we've tended to do, but no, I agree with you, going forward, preferred shares certainly would be another tool that we could look at.

Great. Thanks. Those are my questions.

Your next question comes from Jeremy Rosenfield, from Desjardins Capital Markets. Please go ahead.

Just following on the New England acquisition that was just recently announced, I'm wondering if you have any ideas as to what kind of initial follow-on capital investments you can make at that utility and near-term plans for upcoming rate cases there?

I'll start by saying that we are pleased with the Massachusetts regulatory environment. They have a number of attractor programs that they have put in place to allow the replacement of cast-iron and bare steel in the system for new piping and to allow an immediate recovery of that. So the nice thing about those sort of attractors is you don't have to wait for a rate case in order to start to see the return on that investment.

And so, I don't think it comes as a surprise that the New England utility assets are slightly older, and do actually have cast-iron and bare steel, so there is investment opportunities to continue to grow the Business going forward. And so it's not a fixer upper by any stretch of the imagination, but there is a lot of, I think, regeneration opportunities. The system remains solid right now, but under the Massachusetts regulatory regime, we are thrilled and enthusiastic about this invest -- about the acquisition of NewGasCo, and see the opportunity to bring our local presence, repatriating jobs back to Fall River, as a great opportunity to establish a constructive presence in that town. At the same time, having those mechanisms to earn on your existing assets and continue to invest going forward, so yes to all of that, Jeremy.

Okay. Great. Just also, you had mentioned a couple of utilities that you're looking at, and obviously you're looking at, I'm sure, several others. Just in terms of the sizes of acquisitions that you continue to look for, has the range for your ideal investment, is that still in the CAD100 million to CAD250 million, CAD300 million range?

I think it's again, not a secret that as the business has grown, the bell ringing size of an acquisition increases. I think you accurately point out on in your question that the New England Gas Co is a very attractive opportunity. I think perhaps previously, Nelson might have mentioned that the pricing was attractive. But at CAD75 million it is hard to move the meter.

So I think that CAD100 million to CAD300 million is definitely where our interest lies, but I think those interests are as much driven by our expectation of availability. And so, while we'd like to buy bigger assets we would like to buy that CAD500 million asset as you mentioned, New Mexico gas is probably a CAD700 million or CAD800 million acquisition. I don't think it's, again, any competitive secret here that there's a frothiness, and therefore a price escalation which is going to cause us to think about and consider whether that's sort of acquisition is consistent with our thesis.

And I guess in short, does it mean that we have to continue to do a number of smaller CAD100 million transactions, rather than trying to find that one $500 million transaction? It really all comes about creating shareholder value going forward, and so I would expect, Jeremy, that you will continue to see us hunt in that CAD100 million to CAD300 million range.

Great. And maybe just one more follow-up, for a little bit more clarity. On the timing of the Morse project, I was a little bit confused about the wording in the release. Correct me if I'm wrong, are you going to start the two initial projects in 2014 and then maybe another 5 megawatts in 2015? Maybe you can clarify that?

No. All three projects will proceed simultaneously, but I think that there has been a delay, if you will, largely occasioned frankly by SAS Power in terms of their interconnect. But we expect all of them to proceed through 2014 and happen all at the same time. But, in terms of their contribution to earnings, it won't be until 2015 that you'll really see anything from them.

Great. Those are my questions. Thanks.

Your next question comes from Matt Gowing from Mackie Research Capital. Please go ahead.

So just before I get to my two questions, just start off by saying congratulations on a successful growth year. And in terms of the California utility, and the rate cases that you talked about in the MD&A, it's good to see that the guidance is maintained for CAD7 million in EBITDA, incremental from the rate case expected in 2013. I think the revenue number is CAD12.5 million. Prior verbiage on this issue was that the CPUC has issued a scoping memorandum, as to laying out the timing going forward. So my question really is, are there any other milestones that have to be met before the rate case is definitive?

Well, let me start by saying, Matt, that the California rate case is definitive. It's done. It's concluded. CPUC blessed it, I'll say, in November of last year. The rates were put in effect in January of this year. And we are collecting rates that are consistent with the guidance that was in the MD&A, which you accurately articulated. So that's a done deal. We're past that one, and we're moved on to Granite State, Matt.

Okay. Excellent. Thanks for that. And on the customer growth side on Liberty Utilities, good to see modest growth across the board in your water utilities. Did see that your Liberty West, looks like total customer count declined by 4% year-over-year. Hoping that you could maybe provide some color there. And I know that you're not providing comparative customer count numbers for the New Hampshire and Midwest gas utilities, but could you comment on the trend of customer count in those businesses, please?

Sure. Let me start by saying customer count is a little red herring-ish, as we look at it, certainly on a quarter by quarter basis. I think there is two things that are in effect. One is that, it is really a snapshot in time and so, but second of all, perhaps more importantly, over the course of a year you can imagine there is almost a natural churn, if you will, in customers. And I'll just give you an example. I think you have touched on it, but I will reinforce it.

In the Midwest, just given the rate tariff structure, there's actually an economic incentive for customers to sometimes actually shut their gas off in the summer and reconnect it in the fall to avoid those fixed charges. So that you'll see customer counts seasonally fluctuate in addition to the homes, people moving in and out of their homes. I guess the good news from our perspective is that the cost and implications of that churn are generally all built into current rates.

I will say, you mentioned that, it's nice to see continuing growth in Arizona. I think that's a fair statement to say, that we're seeing those continuing small positive growths in California, that are somewhat hidden, if you will, by the noise of these quarterly snapshots. And so, I'd actually suggest that there's no significant negative trend that we're seeing in any of the jurisdictions that we're in. I think Arizona's is the most obviously positive one. But I wouldn't get too hung up, Matt, on fishing at those quarterly numbers, as I said. There's a lot of noise built into them, and I think we really should be looking at it, and a trailing 12-month basis is probably a more important way to look at it.

One of the things getting back to your earlier question I think is worth touching on about the California rate case, one of the significant characteristics or provisions of that rate case was for us to achieve complete decoupling, if you will, of our revenues from the actual customer demand. So growth, shrinkage, weather up, weather down, that is completely gone, if you will, and you'll see a very predictable revenue source from that utility through 2013 and beyond. And so again, just trying to make sure that we don't lose sight of the forest for the trees here, that as we look at those customer count numbers, sometimes can be a little misleading.

Okay. Great. Thanks a lot, Ian.

Perfect. Thanks, Matt.

Your next question comes from James Morrison from Cormark Securities. Please go ahead.

I'll be quick. From the pipeline, can you -- when you're assessing new projects and the existing pipeline you have right now, how are you looking at terminal values, when you're trying to meet your IRR targets?

It obviously differs from project to project, James. Are you thinking wind, thinking solar, which ones are you thinking of?

In general I'm thinking, like are you just modeling to achieve your 8% minimum threshold IRR after-tax over the course of the PPA, or are you putting a multiple in that would apply to everything? Wind, solar?

No. We actually think I would say slightly different approach, if you think about wind projects, maybe having a 35-year economic useful life and we'll have a 25-year PPA, and just looking at the same thing as an example. We will model it out over the entire 35 years, but we will, based on a componentization of the components of the facility from a capital reinvestment perspective, presume that we have to replace gearboxes and generators and blades and stuff like that, over the course of that 35 years. We will put little to no terminal value at the end of that horizon, and you can imagine 35 years out, in fact it's not going to make much of a difference in any event.

But that following the PPA, from a revenue perspective, we make the assumption that we look at forecasts for the price of energy, and just assume that we're going to sell that energy into the merchant marketplaces after the 25-year PPA expires, and so it's really is a cradle-to-grave analysis, but I will say that the back end doesn't really have a huge impact, given both the time and frankly, the expected drop in revenues that tends to occur when you look at the contracted revenues, versus the expectation of free-market.

Okay. And do all of the projects in the contracted pipeline right now meet the 8% minimum threshold that you're targeting?

Yes. I think that's really what gets them into the pipeline. If they didn't, we'd probably want to throw them out of the pipeline. I'd say it's, again, not been much of a secret that it's been a bit of a buyer's market when it comes to generating equipment in the Wind or Solar business.

So, I'd actually say that the returns have improved from when the PPAs were originally awarded, obviously I'm speaking of things like SAS Power, the Chaplain project, just given continued I'll say positive, certainly not from Siemens' or Gamesa's perspective, movement in prices of wind turbines. They've gone in the right direction from our point of view, and so we haven't been forced with that uncomfortable conclusion that oh, gosh, this no longer meets the threshold, and we should throw it out of the list.

Right. And none of those projects are at risk of coming up to their mandatory in-service date?

Well, they're all being managed in the context of those schedules, and so, when we speak to SAS Power, the reason Chaplain is on a back burner, but the reason is further down the pipe is because SAS Power says I don't need the power until 2016, and so consequently we're managing against all of those.

And pursuant to one of the earlier questions about Amherst Island, obviously there's a very specific timetable associated with it, and we've been able to manage delays that have been occasioned by some of the permitting process in the context of the provisions that are built into the agreement such as force majeure. So, I think we're actively managing the pipeline and I think we are comfortable that there's nothing at risk right now, and if it was at risk, you'd see more emphasis on it from our perspective.

Okay. Fair enough. Thank you.

(Operator Instructions)

There are no further questions. Please continue.

Great. Well, thanks, everyone. I really would like to thank everybody for participating with us this morning, and as always, please remain on the line for the absolutely scintillating review of our disclaimer by Kelly Castledine.

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 on assumptions relating to, among others, the performance of the Company's assets and the business, financial, and regulatory climates in which it operates.

These forward-looking statements include, among others, statements with respect to the expected performance of the Company, its future plans and its dividends to shareholders. These 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 these 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. You may now disconnect your lines.