Algonquin Power & Utilities Corp (AQNU) 2011 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Algonquin Power & Utilities Corp Q4 2011 analyst call. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. Instructions will be provided at that time.

(Operator Instructions)

I would like to remind everyone that this conference call is being recorded today, Friday, March 9, 2012 at 10.00 AM Eastern Time. I'll now turn the conference over to Mr. Chris Jarratt, Vice Chairman.

Thank you. I'd like to welcome you to the 2011 fourth quarter and year end results conference call. In addition, we will be spending some time today discussing our wind acquisition announcement that was made in the early hours of today. Due to the timing of that acquisition announcement, we have provided a great deal of information in a short time frame, so we would like to get started quickly.

With me on the call today are Ian Robertson, our Chief Executive Officer; David Bronicheski, our Chief Financial Officer; Jeff Norman, Vice President of Project Development; and Kelly Castledine, our Manager of Investor Relations. For your reference, additional 2011 financial information is available for download under the top link section of our homepage at AlgonquinPower.com.

I'd like to note that in this call, we will provide information that relates to future events and expected financial positions that should be considered forward-looking. 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 regarding a few of the highlights from the quarter, and following that, David will review the financial results. Wrapping up, Ian will provide some updates on some of our financial growth opportunities, and then we will continue the call with a presentation of our acquisition announcement in the early hours of today. At the end of the call, we will host a question-and-answer period. And with that, I'm going to now hand it over to Ian.

Thanks, Chris. Good morning, everyone, and thanks for joining us on the call today. We're happy to be sharing our positive results for the fourth quarter of 2011 with you, as well as the exciting news of our acquisition of an interest in a 480 megawatt portfolio of US-based wind generation. I'll start today with a focus on our results, and then we'll switch over and spend some time reviewing this important acquisition.

Our 2011 objectives of further growth in both our power and utilities businesses has contributed positively to our overall goal of increasing total shareholder return. In addition to solid performance of our existing portfolio, we continued our efforts on the various regulatory approval processes related to our committed utilities growth initiatives in further progressing our prior development efforts.

During the quarter, we announced our entry into the solar energy business, with our 10 megawatt solar project located near Cornwall, Ontario. This project has been granted an Ontario Feed-In-Tarriff contract by the Ontario Power Authority with a 20-year term at an attractive rate of CAD433 a megawatt hour, resulting in expected initial annual revenues of approximately CAD6 million.

We expect to begin construction of the project in the latter half of this year, with a commercial operations date early next. Along with the acquisition, we have an option to acquire 10 additional Ontario-based solar development projects. We've been actively pursuing the expansion of our renewable energy portfolio into the solar sector, and are very pleased with the announcement of this first solar project last quarter.

As an update to our utility growth and the regulatory approval processes that are ongoing in Liberty Utilities, in New Hampshire we continue to progress on the Granite State and EnergyNorth acquisitions, however, have been delayed beyond our original estimated closing time frame of Q1 2012.

We have completed the series of technical sessions with the New Hampshire Public Utilities Commission, are now working with Public Utilities Commission staff and the Office of the Consumer Advocate to prepare a settlement recommendation to present to the commissioners of the new New Hampshire Public Utilities Commission for their consideration. The current regulatory hearing schedule should allow a public hearing in late Q1 2012, or early Q2 2012.

The acquisition of our Missouri, Illinois, and Iowa-based utility assets from Atmos Energy Corporation is also subject to state and regulatory approvals. We continue to move forward, and we're pleased to note that we have approval already granted from the Iowa Commission. We've entered into a unanimous stipulation agreement with the Missouri Public Service Commission, and we're now working through the regulatory approval process in Illinois. We think we're still on schedule to close this acquisition mid this year. And finally, with respect to Emera's 49.9% direct ownership in our California electric utility, we believe the process is on track for a closing mid this year.

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

Thanks, Ian. Now for a brief review of the year end results that we released last evening.

Revenue for 2011 was CAD276.6 million, and that was up significantly from last year's CAD180.4 million. Our adjusted EBITDA for the year was CAD105.2 million, as compared to CAD75.1 million the year before. And our adjusted net earnings was CAD41.6 million, as compared to CAD22.5 million the year before.

The key story in our renewable energy division over the last year was strong hydrology and wind resources, and as a result the division exceeded our expectations for our US and Canadian facilities. During the fourth quarter of 2011, net energy sales totaled CAD23.1 million, as compared to CAD22 million in the same period in 2010, an increase of 5%. During the quarter the division generated electricity equal to approximately 111% of long-term projected average wind and hydrology, as compared to 90% in the same quarter last year.

APCo's New England region experienced resources significantly higher than long-term averages, producing 175% above production forecasts based on these long-term averages. And the Manitoba, Saskatchewan and Maritime regions also experienced hydraulic resources higher than long-term averages, resulting in energy production between 15% and 20% above long-term averages. For the fourth quarter of 2011, operating profit totaled CAD16.1 million, as compared to CAD15.1 million during the same period a year earlier, representing a 7% increase.

In our thermal division, our EFW facility exceeded its production targets in the quarter, and generated positive operating results that were ahead of our expectations. We do note in our public disclosures that on February 23, the Region of Peel decided that it would not seek competitive proposals for waste processing, rather than automatically just extending our existing contract beyond October of this year. We will fully participate in this process, and we are confident our energy from waste solution has a number of benefits to the Region of Peel.

Nevertheless, under GAAP we were required to write off the intangible assets on our books associated with the existing contracts, and we recorded a non-cash charge of CAD13.4 million in our Q4 operating results. Net energy and steam sales revenue in the fourth quarter was CAD4.9 million, as compared to CAD6 million in the same period a year earlier. The decrease is mainly due to Windsor Locks selling into the ISO-New England day-ahead market versus the forward-reserve market, as was the case in the same period a year earlier.

For the fourth quarter of 2011, operating profit totaled CAD4 million, as compared to CAD5 million during the same period in 2010. Looking ahead to the next quarter, APCo's renewable energy division is expected to be in line with expectations in Q1 2012. The thermal energy division Sanger facility will be offline for the majority of the first quarter of 2012, as certain transmission system upgrades are undertaken by PG&E and we upgrade our plant to accommodate the higher voltage. We will also take advantage of this time to advance some of our regular maintenance for the facility. As a result, we expect revenue to be CAD1.3 million lower than the same period a year ago in our Sanger facility.

Moving on to Liberty Utilities, just a reminder that we're now reporting Liberty Utilities by geographic region, rather than line of business. This is in order for us to accommodate the growth that we see in Liberty Utilities over the next three to five years. We believe that this will enhance overall operational efficiencies, and garner greater economies of scale, while preserving the customer and regulatory focus of the Business.

Liberty Water is now reported as Liberty Utilities South, and CalPeco is reported as Liberty Utilities West. In the future, when we close the Granite State, EnergyNorth acquisitions, it will form Liberty Utilities East, and when we complete the Mid-state Gas Utilities acquisition, that will form our Liberty Utilities Central region. Liberty Utilities South's waste water treatment connections grew by 3.8%, and the water distribution connections grew by 2.8% over the number of connections in the previous year. Revenue for the fourth quarter totaled CAD11.2 million, as compared to CAD9.8 million during the same period in 2010, an increase of 14%.

For the fourth quarter, operating profit totaled CAD5.7 million, compared to CAD4.7 million in the same period a year ago. At Liberty Utilities West, we had net energy sales revenue for the fourth quarter of CAD7.8 million, and operating profit of CAD2.6 million. Overall, our Liberty Utilities West operating profit came just short of our expectations for the quarter, due to higher than budgeted insurance, administration, and distribution costs, which include vegetation management and other expenses.

Looking ahead to the next quarter, we are expecting continued modest growth throughout 2012 in Liberty Utilities South, with revenue increases from rate cases completed in Arizona and Texas continuing to contribute to higher revenues, compared to the year earlier. In addition, Liberty Utilities West recently filed a general rate case, seeking approximately a 10% increase in general rates, and we have a procedural schedule now that contemplates a rate implementation of January 1, 2013.

I'd just like to chat with you briefly on our recent financing activities. In just over a year, we've completed over CAD600 million of financings, and established financing platforms for each of APCo and Liberty Utilities. We are established, now, in the US debt private placement market for Liberty Utilities, with a proven ability to raise investment grade debt. And for APCo, we've established a senior unsecured bond platform for our power generation subsidiary that is our permanent debt solution for that subsidiary.

In the quarter we completed a public offering of 16.8 million shares for gross proceeds of CAD95.3 million. Proceeds will be used to fund a portion of our growth and acquisition programs for the utilities side, and it was also used to refinance existing indebtedness within the corporate group. Subsequent to the end of the fourth quarter, we're pleased to announce that Liberty Utilities entered into an agreement for a $80 million senior unsecured revolving credit facility with a three-year term.

Initially, we've got $25 million available to support current operations, but then we'll have an additional $55 million available for all of our acquisitions, once they close later in the year. Additionally, we recently redeemed CAD57 million of 6.35% Series 2A convertible debentures by issuing 9.8 million APUC shares. This was an accretive transaction for us from both a cash and earnings perspective, and we believe that this further strengthens our balance sheet and gives us additional financing flexibility.

I'll now hand things back to Ian.

Thanks, David. I'd like to give you a quick update on our growth strategies and prospects, before we get into speaking about our recent wind acquisition.

Starting with Liberty Utilities, as I mentioned earlier, we have been diligently working through last year and into this to seek regulatory approval on our announced acquisitions, and at the same time creating detailed plans for the integration of these new assets into the Liberty Utilities operating systems. We continue to focus on the rate regulated electric, natural gas, and water distribution utility and transmission-related investment opportunities in the United States.

We are confident that the customer-centric utility proposition advanced by Liberty Utilities is resonant with our customers, our employees, and regulator stakeholders. Moving on to APCo, we are very pleased with the continuing progress on our development projects, with power purchase agreements that we have outlined in our MD&A. Each of these projects is advancing on schedule through the development cycle. We recently shared with you some exciting news on the award of a 177 megawatt, 25-year, rate escalated power purchase agreement for the Chaplin wind project in Saskatchewan.

This project will consist of approximately 77 multi-megawatt wind turbines, and is expected to generate EBITDA in the first year of CAD37.5 million. The project contributes positively to the long-term nature of APCo's renewable energy portfolio. As an update to the 75 megawatt Amherst Island wind project, in August, the Ontario Minister of Energy directed the OPA to offer fit contract holders the opportunity to have OPA's termination rights under the fit contract waived.

We, of course, exercised this option, and as required by the waiver, submitted a domestic content plan, and provided a statutory declaration regarding equipment supply commitments at the end of November. The environmental studies are well underway, as well as engineering work, and the submission of a renewable energy application is targeted for this summer, with construction to commence shortly thereafter.

We estimate that the project will take approximately 1 year or 1.5 years to construct. Our 2 25 megawatt Quebec Community Wind projects continue also to progress through the development cycle. Saint Damase and Val-Eo are in the preliminary permitting stage of environmental studies in public consultation, with a target to receive all authorizations by the end of this year. To align with the targeted commercial operations dates set out in the Hydro-Quebec PPAs, construction of Saint Damase is expected to commence in early next year, with commercial operations late 2013. And construction of Val-Eo is expected to begin in early 2015, with commercial operations late that year.

Development on our 25 megawatt Morse, Saskatchewan project continues, with construction scheduled for early 2013, and completion in early 2014, to match the interconnection requirements of SaskPower. In our thermal division, we are advancing through the repowering of the Windsor Locks facility, following the execution of an agreement with our steam host, Ahlstrom, for a revised and extended energy service agreement, which now continues through 2027.

The repowering consists of the installation of a smaller, 14 megawatt solar T130 turbine, which is more appropriately sized to serve the mill requirements, leaving the existing 50 or so megawatts of electric generating equipment to generate value by participating 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. Total expected net capital cost is forecast at approximately CAD17 million, which takes into account certain grants and tax credits for which we believe we are eligible.

Obviously, we have continued to focus on expanding this pipeline of development opportunities, as evident with our announcement this morning. We'll now take some time to discuss the acquisition of an interest in a 480 megawatt portfolio of wind projects in the US. And we're trying something new today. I direct your attention to the webcast, where we have some slides to help provide some additional color to our words. The webcast information is available in the news release that was issued this morning, and the slides are also available on Algonquin Power's homepage under top links.

With that, Kelly, if you'd advance the slide, I'd appreciate it. Today, we're going to run through four or five, maybe six slides. Myself, David Bronicheski, and Jeff Norman, our Vice President of Project Development are going to be providing some color to this. The slide that you see on the page right now just provides a bit of an overview of the portfolio that's being acquired.

We're acquiring it from Gamesa Technology Corporation, which is a developer of, or manufacturer of wind turbines based in Spain. One of the leading developers there. And their business mandate is to sell turbines, in some respects, standing up rather than lying down, and they do that by building wind parks, and we're obviously thrilled that we've been able to reach agreement to acquire these four wind projects. You can see them on the slide there. They're in Pennsylvania, in Illinois, in Iowa, and in Texas.

I would point out that the projects are being acquired by us following their commercial operations date, and Gamesa is continuing to work through, and in some respects, take the development cost risk associated with finishing these projects off. And the price that we're paying for them is, in some respects, it's fixed today, and what it ultimately costs to build the portfolio is, in some respects, none of our business nor concern.

Flipping the page, Kelly. I thought I'd spend just a couple of minutes highlighting why this investment, why it makes sense for us, how it is aligned from a strategic perspective. I think if you look at the APCo portfolio of renewable generation, these projects fit pretty nicely into that group. Our current portfolio has an average PPA length pretty much equal to the average length of the contracts that we'll be entering into with respect to these generation. They're in strong, well-proven wind regimes using quality equipment, and so we think they're pretty aligned with what we're currently doing in APCo.

I think it was important to point out that we are acquiring a 51% interest in this portfolio, and I think that is also consistent with our strategy of adding value to our investments through the expertise that we modestly think our group possesses in the development and operation of wind farms. The projects, while obviously a sizable portfolio from a megawatt point of view, it is important to keep in mind that it is really is four facilities, and we currently operate some 57 or so facilities in APCo, and so we're confident that we can easily integrate these additional businesses into the operating infrastructure that we have.

One of the things, the third point there, one of the things that is important, the only practical way, actually, if you're in the renewable resource-driven generation business, the only practical way to diversify your resource risk is through geographic diversification. We are pleased that, if you look at the footprint of these generating stations, they are located sort of outside our existing footprint, and so, therefore, we will get the benefit of further diversification in our portfolio. I mentioned, we aren't taking any development risk.

While we are obviously comfortable with that risk, and we're doing it elsewhere in our business, to the extent that someone else is prepared to take that risk at a price that we find is attractive, we are all about managing that risk. Our investment in those projects will only take place at the time they are COD, or have reached their commercial operations date, and just from a timing perspective, we expect the first two projects, the Pocahontas and Sandy Ridge projects, to be acquired by us, or our interest by us, probably end of April, with the other two projects, Senate and Minonk, which are the larger of the two, acquired in the fourth quarter this year.

I mentioned earlier that the contracted nature of these assets is pretty indistinguishable from the general nature of our existing portfolio, which is good. And lastly, I think what isn't always important in looking at a wind project is the wind resource. What struck us about these projects, and what gave us a great deal of confidence, is the relatively long period of record for which wind data has been collected on these projects, and the extremely thoroughness of the wind resource assessment that was done by Garrard Hassan.

I think, as we think of four and five years' worth of wind data that has been collected, it gives us a great deal of confidence, as we start to look at the expected energy production from these projects. And last slide, before I turn things over to David Bronicheski to kind of walk you through some of the economics, is I'd like to spend a couple of minutes on the transaction structure. I'd say it's something new for us, but to be frank, we're walking a very well-trodden path for wind investment in the US, and while the diagram on the slide may look somewhat complicated, perhaps with a little explanation, it hopefully is quite simple.

We are going to be acquiring a 51% interest in the what is called the cash equity of this transaction. Between ourselves and Gamesa, who is holding the other 49%, the total investment value is about CAD528 million. On the left hand side of the slide -- and as I said, this is something which is new for Algonquin, but certainly not new for wind investment in the US -- is the participation of certain tax equity investors, and these, as you can see on the slide, are two well-known financial institutions, I'd say highly taxable financial institutions, whose major objective in the investment is to receive the value from the production tax credits and other tax attributes that wind projects in the US qualify.

And so I think, as we look at the investment structure between us, we have sort of similar, but quite different sources of return. Under the structure, and we provide some details to it, we will be receiving 100% of the cash flows and earnings from the project, certainly up until 2018, and the tax equity investors' interests, primarily, returns are driven from their interest in the PTCs and other tax attributes.

There is a period of a couple years, from 2018 through approximately Q3 2020, where cash flows revert to the tax equity investors of 65%, and we'll own 35%, and thereafter it reverts back to us, with 95% coming our way. It's quite a well-trodden path, well-trodden structure in managing these sort of projects going forward.

I would point out that we are acquiring a 51% interest in the cash equity position, which does make us the manager of the portfolio holdings company, which will have its interest in those four projects, and that is important to us, because it gives us the opportunity, as we said earlier, to add value, from a control perspective, in terms of managing the projects going forward. With that, I'm going to turn it over to David Bronicheski, to give you a little bit of insight into the financing structure.

Thanks, Ian. On the next slide, this is slide 5, we have a very simple chart that outlines the financing structure for this acquisition, and as Ian said, this follows, basically, a standard structure used in the US to take advantage of the not inconsequential US tax incentives that exist there. Total assets are CAD888 million, and they'll be financed with, for our part, a CAD120 million bond offering from our APCo's bond platform that we established last year, and we'll also have CAD150 million or CAD149 million of APUC common equity that will be used to finance our portion of this. Then, of course, Gamesa, as the non-controlling interest, will be there for CAD258 million, and then we have our tax equity investors that are there for CAD360 million. And that really is the structure for how this acquisition is going to be financed.

Moving on now to slide 6, thought it would be helpful to just provide people on the call with a picture as to what our capital structure would look like on a pro forma basis following the acquisition. As you can see there, we ended the year with a capitalization as you see before you. Of course in February, as you know, we converted CAD60 million of our Series 2A convertible debentures from that into equity, and then if we overlay the capital structure from our US wind acquisition that we're talking about, you can see, then, on the far right hand side, what Algonquin's capital structure would look like an a pro forma basis, pro forma this acquisition.

And if you look at the metrics down below, you can see that throughout this process, we actually maintain very strong investment-grade credit metrics, and that certainly is our objective in all of the acquisitions that we look at, to make sure that, in fact, we are maintaining investment-grade credit metrics, and in fact, going forward in this year, our credit metrics are actually improving. So with that, I'll now turn things over to Jeff Norman, who will talk briefly about our power sales contracts that exist in this acquisition.

Great. Thank you, David. Obviously the power sales contracts are an important component, and this slide provides you with an overview of how that contract works for the four different projects. In summary, the contract duration is 11.8 years, or just under 12 years on a weighted average basis for the projects, with Senate being the longest at 15, and Sandy Ridge and Minonk being 10 years each.

The net price here is approximately CAD35.67 for the contracted price on average. You can see it ranges from CAD30 for Minonk to CAD42.37 for Sandy Ridge. It's important to note that this does not include the value of RECs, the value of capacity, or the value of the PTCs, which is the key driver for tax equity, and their investment of CAD360 million.

When you combine the merchant, or the hedged price, with the hedged volumes, which we're showing a total of 1,150 gigawatts as the maximum contracted quantity, you end up with 73% of the revenue being hedged. The remaining 27% is merchant. The merchant prices are, in the first five years, approximately the same, at just over CAD35.

But they will benefit from inflation as they move forward, and will be a good offset to the operating cost inflation that we would expect to see. The other thing that's worth pointing out, here, is we are in three electrical markets. Two of the projects are in PJM. The Senate project, which is in Texas, is in ERCOT, and the Pocahontas project is in MISO.

And so that is the summary with respect to the sales contracts. Obviously, the other important point is that the off-taker is JPMorgan. And the next slide provides an overview of the tax-assisted equity, which Ian touched on. This is obviously also an important component, given of the CAD888 million purchase price, CAD360 million of it is driven by tax equity.

That gives you an idea of the value placed on the production tax credits. Just by way of background, in the US, the Federal incentives either come by way of the investment tax credit or the production tax credit, and for projects with a good wind resource and fairly high capacity factors, the production tax credit is economically favored, and that's why it's been selected here for the project.

When you select the production tax credit, you obviously need a counterparty that is taxable, to be able to take advantage of the PTCs and the accelerated tax depreciation, and that's where JPMorgan and Morgan Stanley come into the picture. The tax equity investment of CAD360 million in the project is reduced over time, as the PTCs and accelerated depreciation move forward and are taken advantage of by JPMorgan and Morgan Stanley.

In addition to the CAD360 million, there's a payment for PAYGO, which is incremental PTC value which comes in and impacts our cash flow analysis. And our favorite part is that, after approximately 10 years, the residual ownership of the tax equity investors is reduced to 5%, leaving the sponsor Co with 95% ownership.

The final point I'd like to make is just the three stages in the life cycle of a tax equity investment. In the first stage, APCo receives 100% of the operating cash flow from the facilities, and this is expected to be about 7 years. Then for a fairly short period of time, 65% of the cash goes to tax equity, with 35% being retained by the sponsor co, and that is used to pay down the remaining tax equity balance. And then once that is done, APCo receives 95%, and the tax equity investors simply have a 5% residual.

Great. Thanks, Jeff. In addition, in the presentation and I don't think we'll walk our way through them, there are four slides that continue on that provide some additional details on the acquisition. I will just touch on that this tax equity structure is new to us, but not new to the renewable energy industry, and there are a couple of interesting implications of having a tax equity participate in Algonquin going forward, both from a GAAP earnings income statement perspective, and also, notably, from a cash flow perspective.

We won't get into it on this call from a description point of view, because its methodology is quite complex, but from an accounting point of view, the way that tax equity gets accounted for, obviously, needs to be reflected in our income statement, and I think it generates some positive implications from an earning point of view, but more materially, because what I think we all think of is cash, as Jeff touched on. The tax equity investors also will be paying us for certain production tax credits that weren't factored into their original analysis above a certain threshold, and that will generate an additional CAD11 million per year of cash flow, on average, going forward for the first seven or so years.

And so, look, we think that, overall, the investment is attractive. It's accretive, we believe, on both an earnings and a cash flow perspective, with an unlevered after-tax IRR which certainly exceeds our threshold, and on a leverage perspective, and as David touched on, we use relatively modest leverage in our structure, remains accretive on a per share basis.

So, in summary, and we'll open it up for questions, because I'm sure there are lots, we think the acquisition of this interest in the 480 megawatt portfolio of wind, it is strategic. It doubles our current power generation portfolio. It represents significant growth in the APCo side of the Business, and while we shouldn't lose sight of it, our Saskatchewan Wind PPA win, coupled with this, suggests that this Organization is making good on the proposition of delivering attractive total shareholder returns through accretive growth. So with that, I'm going to turn it back over to Chris to chair our question and answer period.

Great. Thanks, Ian. With that, Ron, if you could open up the lines, we would like to get started on our question-and-answer session.

Thank you. Ladies and gentlemen, we will now conduct a question-and-answer session.

(Operator Instructions).

Your first question comes from James Robinson from Cormark Securities. Please go ahead.

Hi, guys. James Morrison. This is an interesting transaction. If the COD gets pushed out for the final two projects, Senate and Minonk, into 2013, does the tax equity need to be replaced by another investor, or does that somehow need to be made whole?

Great question, James. And we knew who you were. But, look, that was an extremely important point from our perspective when we were negotiating this transaction with Gamesa. Clearly, that cannot be a risk. The timing cannot be our risk. And this is important acquisition for us, and so the short answer to your question is no, James, it's not our responsibility. To the extent that 2013 comes, and either Senate or Minonk, or Senate and Minonk haven't met a threshold that allows -- that haven't been completed in timing that allows tax equity to go ahead, and the PTC hasn't been extended, the commitment with Gamesa is for us to sit down, restructure the transaction in a manner that preserves our returns, and so I look at that, and I think Gamesa, understandably, also look at the timing of that as being a development risk. That is not a risk that Algonquin should be suffering from, and so that's how the transaction's been structured.

Right. So the tax equity investors wouldn't be at the table at that point, but you would be able to preserve whatever return that you've negotiated, and Gamesa would kind of eat the difference?

That's exactly it.

That's good. And then I guess you're operating a few different jurisdictions, here, with different REC markets, and capacity markets, and day-ahead markets. Do have you a sense as to kind of an overall, like all-in dollars per megawatt hour, revenue that you're expecting to get? Because I know Borlex, for instance, sells their RECs forward into longer term contracts. It sometimes can be a negotiated market.

Certainly. First, let me start by saying that the management of the merchant energy, merchant capacity, and merchant RECs is largely going to be a process that's undertaken by our Algonquin energy services group, which as you know, is kind of the manager of our market-based participation. All-in, if you look at it from sort of a REC, capacity, and energy perspective, it's about CAD40 a megawatt hour, maybe CAD40.80. So I think if you -- so as Jeff had mentioned earlier, if you look at the merchant and the contracted energy being in the CAD35, CAD36 range, it looks like we're adding about CAD4 or so for RECs and capacity, which I think the nice thing about it is, I think there's room on the upside. I will point out that ERCOT and MISO, two markets in which the Senate and Pocahontas projects, respectively, are located are energy-only markets, and so consequently capacity doesn't play a very big role. And RECs are obviously a bigger deal in PJM than they perhaps are in MISO and some of the other ones. So all in all, it's a relatively conservative part of the value equation that comes from RECs and capacity. I don't know if that answers your question.

Yes. So I guess, overall, fully running you kind of expect the CAD65 million in revenue?

Yes, maybe a little bit higher than that. I look at -- we've kind of looked at it on a bit of an average basis over the first couple, three years. We think of the first year, full year, obviously 2013. But in the CAD65 million, CAD67 million range isn't an unreasonable number. I think it is important to mention that the value proposition on a cash basis is materially enhanced by those PAYGO payments.

Right.

So run down through it, and there's another CAD11 million that needs to get added in, not on the income statement, but down on the statement of changes, and that is important as well.

Right. You're getting those because the production of those wind assets is higher than anticipated in your contract with --

It's not higher than anticipated. The way it works is when tax equity sized their investment, they really only, in effect, paid for 75% of the expected PTCs. But they'll get them all, because that's the way the agreements work, and it's only fair that they pay for all that they get, and so that's how the payment of these PAYGO payments really arises. It's paying for those PTCs that weren't factored into their original price.

And so what kind of IRR has the tax equity participant built into your contract? Are they looking for like 12%, and then everything else goes to you?

Oh, no. The tax equity guys are -- their total returns, taking into account the value of their tax losses and the value of their PTCs, it's kind of in the 7% to 8% range. Obviously, a little bit of sensitive competitive information from the tax equity's perspective, but it's substantially lower than that.

Right. That's an unlevered number?

Yes. I should point out that everything's unlevered in this transaction. There is no debt down in this structure. It's just the way the structure works, and so there is no debt there. All of the debt that we're talking about, and we obviously look at it just from our own perspective, is upstairs, and so we look at financing it at the corporate level, and no one, tax equity, nor our partner, has the right ability to put any debt in the structure at all.

Okay. Finally, you mentioned GAAP taxes, or I guess US taxes still be a lot of loss carry-forwards, but in Canada you'll be 7% GAAP tax rate. Will you be paying any cash taxes in Canada on this for the next few years?

No, I think our expectation is, it's a long time, probably long after you and I are having these sort of conversations, that cash taxes would arise.

Let's hope so. Okay. And then I guess, actually, I have a bunch of accounting questions. Maybe I'll just call you off line for those.

No problem at all. Happy to discuss.

Thanks, guys.

Thanks, James.

Your next question comes from Rupert Merer from National Bank Financial. Please go ahead.

Good morning everyone. Congratulations on the acquisition.

Thanks, Rupert.

You mentioned that your unlevered after-tax IRR exceeds your threshold. Could you remind us what that threshold level is?

Well, typically, as we've sort of thought about -- I'll look at it in fully contracted assets. I think the current market would be down in the, probably, in the 9% range. That's typically where these are. There is a different aspect to this, and we have, I think it's fair to say that looking at forward, from a forecast point of view, and this is obviously on the basis of our energy market forecast, and we hired -- there's been a couple of firms who have looked at it, it's in the 10 % to 11% range.

Okay. And what terms would you anticipate for the project debt that you're seeking on the investment?

We're actually not seeking any project debt. We're just going to putting more APCo debt in there. As you know, we did the last APCo bond financing at 5.5%. So we would be issuing another CAD120 million of debt up at the corporate level, and you can figure for yourself where you think that would come in, but 5.5%, 6%, David, sounds about right to you?

Rates haven't moved that much since last summer when we financed. So 5% range.

The leverage is attractive. It obviously helps the returns. But to be frank, with an unlevered after-tax IRR in the double-digit territory, I'm not sure you actually have to use much leverage to make this thing attractive on a per share basis.

Then you suggest you've got 73% of your energy revenues hedged. I assume that includes the RECs?

No, it doesn't. That's just off of the energy. The RECs and capacity payments, they're, say over the first four, five years, it would look like they could add maybe another CAD8 million or CAD9 million. So if you want to look at it that way, there may be 10%, 15% of the revenues would come from RECs and capacity. I would point out that, all-in, and this was what we were saying, so if you take the total expected revenues, divide by the total expected energy, we're looking at about a CAD40.80 cost, all-in, so think of it on a megawatt hour basis. So there isn't a lot of reliance placed on those RECs and capacity payments, maybe CAD5.

Okay. And is there any opportunities for hedging the energy sales from Pocahontas in the future?

Sure. Let's talk about that for a second, because it's an interesting point. The reason we didn't elect to hedge, in fact, we had the ability to enter into a power sales contract for the Pocahontas project, basically on the same terms, a 10 year project. We actually elected not to take it, and the reason is this. The Pocahontas project is connected into the MISO grid, but the pricing note for that Pocahontas project would be at Min Hub, which is some distance away. We didn't have a lot of historic empirical evidence of the hedging relationship between the point where we were interconnecting and that hedge. I think the intention is over the next one, two years, once the project is operational, and to the extent that we get comfortable of the predictability of the relationship between those two nodes, we would likely go back and enter into a power sales contract. As you know, our general philosophy is to hedge away the risk. We're not a merchant player. That's not the nature of our business. Our business is to have -- we'll trade away upside for stability every day, and so I think you'll probably see us, once we get that operating experience, announcing that we have entered into a contract for Pocahontas.

Thanks. I'll get back in the queue.

Thanks, Rupert.

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

Thank you. Congratulations on the transaction today.

Thanks, Juan.

Just a couple points of clarification. There was mention in the press release about a development agreement with Gamesa. And just wondering, it talked about giving you some visibility on their pipeline of 2,700 megawatts of projects. I'm wondering about the terms of that agreement, and if you participate in those potential projects at the same percentage as your joint venture interest, or is it something different?

It's a little bit different, and to be frank, it's a little bit looser. As I mentioned, Gamesa's approach to selling wind turbines is to sell as many as they can lying down, but to the extent that they sell them standing up, to allow them to do that, they have a very active development group. I think a very professional development group. And when we sat down with them, and went through the, I'll show you mine if you show me yours work with Gamesa, we found there was a lot of interesting projects in their pipeline, and so I think Gamesa is not a long-term holder. They're not building these to own them. They're building them to sell them, and we are always interested in finding a group who are motivated sellers, and so I think there is a -- I think it's more of a negotiated opportunity that will exist. We obviously also have a large number of projects going on in Canada, and they're obviously interested in adding value.

They're obviously interested in selling turbines. They're interested in adding value to that. Think of it really more, Juan, as a collaboration agreement. A lot of work went into structuring this transaction, and I think our intention is to have created a paradigm, if you will, for us to be able to turn the crank yet again, and to the extent that Gamesa has additional projects, and they are located primarily across the US, and there's an opportunity to turn the crank on the structure again, I think we would likely do it. Let's just talk about our percentage, the 51% versus 100%. I think it really comes down to just size, and we would love to have been able to take 100%. I think everything has to be in measure. And so consequently, who knows, the next project may not have Gamesa retaining a partnership interest, and we might own 100% of it. So I don't think you should look at anything magic of the 51%, from our perspective, other than it was important that we be in a control position.

Okay. Thank you for that. And given you've recently announced the large Chaplin wind project, and as well, today's announcement, what does this do to your cash tax profile?

These projects alone are pretty efficient from a cash tax perspective. So they unto themselves go beyond our original horizon. Again, obviously CAD355 million going into Saskatchewan will help push it out. David, I don't know if you've done any calculations on that.

Right now our, I'll say taxability horizon, the last time we put out guidance on that was 2016, 2017. Clearly, as we build these projects out, that taxability horizon will be pushed out even further. And quite frankly, that's what makes this use of tax equity in the United States very attractive to us, because when our taxability horizon is that many years away, then obviously somebody else can utilize the production tax credits and other US tax incentives better than us. We're just now wrapping up our year-end, and finalizing the tax returns for 2011, and once that process is done, we'll be refreshing our guidance with respect to the taxability horizon. But we do expect that to be pushed out to a few years, beyond the 2016, 2017 period.

Okay. Thank you for that. That's helpful. And just with respect to the financing, you did provide some guidance there that Emera will contribute up to CAD105 million of equity. Can you tell us what the price per share that Emera would pay for that equity?

Sure. I think just to be clear, we're looking at that under our strategic investment agreement, which permits Emera to participate up to 25% in the common equity ownership of Algonquin, that CAD105 million is what, today, they could participate in. Historically as they've done their investments in Algonquin, they have always participated at a premium-to-market. I think that is the right message. There is a significant informational asymmetry between themselves and the rest of the market. I think they respect that. And so while we expect Emera's participation to be announced closer to the investment date, I think that's not an unreasonable thing to assume, that as we think about going forward that's generally how they've made their investments.

Okay. Thanks for that. Just a follow-up to that. In the event that the Maine PUC denies Emera's request to increase its stake in your equity above 10%, what are your alternative financing plans, not just for the Gamesa asset acquisition, but also for Granite State and for CalPeco?

I think in the first instance, look, we've certainly had discussions with Emera about just managing the liquidity issues that would be associated with that. I think it's fair to say that the hearing, with respect to Emera's interest in Algonquin in Maine, has been complicated by the fact that it has been held and is a combined docket with the issue of First Wind, which as you know, we are no longer participating in. I think that to the extent that there was a denial, I think we all feel, and I don't want to speak for Emera, that perhaps that this issue should be re-heard outside the cacophony of the First Wind transaction, and so I think that would be our approach going forward. But we have had discussions with Emera about managing the liquidity, and whether that involves them providing some sort of a loan in advance of exercising those subscription receipts once they do get approval, that is yet to be determined. Keeping in mind that really the only subscription receipt that is outstanding for which we -- that's capital related is the CAD60 million for Granite State and EnergyNorth. And while, in human terms, that's obviously a phenomenal amount of money, I don't think it will present a liquidity crisis for this Organization. David, I don't know if you have anything to add to that.

No. I think you've hit all the right points with respect to that.

Great. Thanks very much.

Thanks, Juan.

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

Thanks. Congratulations on the transaction.

Thanks, Nelson.

Just speaking about First Wind, so I guess that one you pulled out of First Wind partly due to regulatory reasons. Do you see any issues in terms of getting regulatory approvals for these four projects?

Well, in some respects, we should be a little bit clear about First Wind and the regulatory approval. There was no regulatory approval required, practically, in respect of First Wind. The regulatory approval came, understandably so, because Emera owned regulated utility assets in the state of Maine, and so it was really almost sort of a corollary issue that gave rise to the Maine PUC regulatory hearing. There is no such fact pattern associated with the Gamesa assets, and so while we have of course the, I don't want to say obligatory, FERP 203 filing and Hart-Scott-Rodino filing, we do not anticipate, and there frankly isn't any regulatory structure that would mandate, the same sort of approvals that were necessitated in First Wind. The short answer to your question, Nelson, is no.

Great, thanks. Just kind of switching gears to CalPeco, in terms of their rate case filing, I'm not sure whether I've looked at it properly. But if you're asking for a CAD7.5 million rate increase, but does that mean that your EBITDA will actually go up by CAD13 million, due to the lower expected commodity costs, or can you kind of walk me through what your expected increase is in on the bottom line?

Our expected increase would be the CAD7.5 million. The commodity cost issue is always a pass-through, be it an increase or decrease. So in short answer, and actually even as I think of that, I need to check that, to see whether the 10% increase in net of the -- yes, actually the way it works is -- actually, you know what? I'm not going to misspeak, Nelson. I'll give you a call back to give you the specifics on that, because obviously I don't want to get it wrong.

Okay. Great. Thanks. Those are all my questions.

Okay.

Your next question comes from John Safrance with M Partners. Please go ahead.

Good morning, and congrats on the transaction.

Thanks, John.

Just a follow-up question on the equity component for this deal. So you allude to Emera, obviously, participating to some extent, up to CAD105 million. If you add up the subscription receipts, and maybe I've not calculated properly, but by my count, excluding the first energy, which is no longer on the table, by the end of this year, you would probably be up somewhere around 20% of the total common equity at that point, which would leave, I think, about 7 million shares available to Emera to subscribe to. Is my math correct there, and how do you bridge that between the CAD105 million?

We'll have to go over that math. Because there's something in that calculation just that doesn't sort of ring true to us. Certainly, we're very comfortable with the assumptions that we have on the CAD105 million, and what that does for Emera as far as percentage ownership, and it's all completely within the strategic investment agreement parameters that we agreed to last April.

And John, obviously -- I don't know what you're using as sort of a total issued and outstanding basis, but with the change in our CDs, obviously those that need to be reflected, currently we have about 146 million shares outstanding. I'm just not so sure, maybe that's a denominator issue in your calc. Good news is, this is a relatively simple calculation. We'll work it out with you to get it right. The good news is the math is pretty straightforward.

I'll follow up with you on that front.

No worries, John.

In longer term, I know you mentioned with other projects that maybe you'll go upwards towards 100% of the equity on it. But with the existing four assets, is there any ability or desire on your part, at some point in the future, to increase your stake and buy out Gamesa in these four projects?

Sure. Look, Gamesa is not a long-term holder of these assets. I think we are pleased that Gamesa saw value in participating with us at the 51%, but I think, frankly, their desire was to sell 100%, and so as we think about our portfolio going forward, it's all in measure. I think the Wind in Saskatchewan is an important thing to consider. To be frank, the discussions have been ongoing for months, it's an extremely complicated transaction, and the wind in Saskatchewan wasn't factored into, as we looked at our portfolio, Canadian, US, PPA versus power sales contracts, and as we look at managing and balancing our US FX exposure, we didn't have the benefit of that CAD350 million. We might look at the transaction differently now, in terms of our participation, and it's nice to have a guy on the other side of the transaction who is happy, willing, and able to sell you another 49%. Yes, John, I think we look at that 49% as being warehoused, and we would like to see if it makes sense for us to take more.

Okay. But there's no pre-existing option on that 49%?

No.

Okay. And then just finally on the solar construction, you've got another 10 projects in behind that that are obviously subject to what the ultimate Feed-In-Tariff rates look like for the program in Ontario. In terms of -- and maybe you don't want to tip your hand too much to the OPA, but do you sort of have an idea in terms of what your minimum threshold would be on those rates?

CAD443. [Laughter].

CAD442. Well, it's a difficult question to answer. What we need to do is factor in the price of panels, and obviously the total cost to build out. As panel prices continue to move down, that price continues to move. I think to give some guidance, in 2009 when the CAD443 per megawatt hour price was there, and panels were at CAD450 a watt, we didn't think the economics made sense for us. As the panel prices moved down significantly, it put a lot of value on those projects, and so I think there's a good opportunity, or a good chance that OPA's going to lower the price in our strike zone, but we're not absolutely certain, and it's a bit of a moving target as panel prices move around.

Understood. Perfect. That's all from me. Thank you.

Thanks.

Your next question comes from Matthew Akman from Scotia Bank. Please go ahead.

Thanks. Hey, guys, congratulations on the deal. Many of my questions have been asked. I just wanted to follow up, not on the wind deal, actually, but on the energy from waste facility, and get your thoughts on your competitive position going forward there. In particular, we're a bit concerned that there was a fair bit of capital, and time and energy spent there by you guys in 2010 on this, and now they've decided to tender it, which governments are want to do, I suppose. Having said that, you've got the infrastructure in place, so can you just talk maybe about how you feel about your business position there, and what your options are to make sure that you continue to earn a return on that capital?

Sure, Matthew. It's Chris Jarratt. I'll speak to that. Yes, we're in the middle of that process right now. So we've got to be careful exactly what we say from a competitive point of view. But I think the punch line of it is, the energy from waste probably is more expensive than the other options, but it certainly offers a whole bunch of advantages that the other options don't offer. Things like the Region of Peel has always been very much aware of having a made-in Peel solution. They've always wanted to have a diversified waste solution, and that's what this provides them with. There's also jobs in Peel, which are important to people. And Peel has always been -- always wanting to improve how much of their waste gets diverted from landfill.

So certainly, we tick the box on all those. I think, overall, Peel has always been supportive of energy from waste, and I think for the most part they still are. Certainly the staff seem to be that way. So I think we're going into this process, and I think our chances are quite good. Just in terms of your question about the capital that got spent, that was actually kind of a good thing. The failure occurred a couple of years ago, and you can see from our financial results that that facility has never operated as well as it has in the last couple years since that capital was injected. One of the things that did do was it gave Peel a very good feeling that that facility is in good condition, and will operate for the foreseeable future. So in some respects, it was a benefit for the whole process. And I'll just finish with the -- we do have a six month extension commitment from the Region of Peel. So that takes us out to almost the end of this year, end of October of 2012.

Are you guys saying, just as one follow-up, to clarify, that if on the off chance that you don't meet their wind RFP process, that you can continue to utilize those assets with third party waste?

Yes, I think we feel extremely confident that there's lots of other sources of waste around, that there's a number of municipalities. There's 4 million tons a year of garbage that gets shipped down into the US of industrial waste. There's lots of waste that's out there, and lots of other customers, and we're obviously talking to them, in case, as you say, the worst happens.

Okay. Thanks, guys. Those are my questions.

Thanks, Matthew.

Thanks, Matthew.

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

Most of my questions have been answered, also, but maybe I'll just give one high level question. In terms of the strategy for acquisitions and growth going forward, with the significant wind transaction, and well Chaplin is certainly longer term, but certainly with this, the Gamesa transaction, what's now the capacity looking for, let's say, acquisitions on the utility side of the business, how does this affect that?

Well, look, we've always maintained that there's no sort of fixed target. As attractive projects come through the door, we'll look at each one. I think we are very interested in continuing to grow the utilities business. I think it's a longer sell cycle in the utilities side, just given the whole regulatory piece. We are continuing to execute on our kind of save-the-orphan strategy. We haven't changed our target investment, and without giving away too many secrets, there are things in the pipeline. So I don't think this acquisition -- I think having Emera there as a strong supporter of our growth, and value creation proposition, gives us a lot of flexibility, Jeremy, in terms of capacity to deliver on the growth side. We look at these businesses, as you know, it's very separately and distinct, and the Liberty Utilities business development group and the APCo business development group are quite distinct and apart.

Then just maybe one more question. Just in terms of the dividend and the payout ratio, and how the Gamesa acquisition might impact cash flows going forward, and the payout ratio relative to those cash flows, can you give some comments around that?

Sure. Look, to the extent that anything is accretive to cash flow, then the payout ratio obviously drops. I think that the question that you would ask yourself, or perhaps you're posing to me, is does that accretion signal a dividend increase? I'll answer that in two ways. One is by saying that sort of decision is obviously the purview of the Board. But we look at our job, and I'm looking, obviously, at everyone around this table, is to create the flexibility for the Board to provide those dividend increases, and the second comment I'll make with respect to that is, we've always maintained the value proposition associated with an ownership of an APUC share is, from the current divvy, but supported with capital appreciation, and that capital appreciation will come from continuing to drive the dividend North, and I think everybody buys into that proposition. So as I said, I can't answer your question directly, but all I can say is I think that the Gamesa transaction does provide an increased flexibility to the Board to increase the dividend if they so saw fit.

Great. Thanks a lot.

Thanks, Jeremy.

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

Good morning. Congrats on the transaction. Never a dull moment here, guys.

Thanks, Ian.

Just looking look at Granite State, EnergyNorth, you mentioned the settlement recommendation. Wondered if you could talk a bit about it, and potentially if it either increases transaction costs or operating costs going forward.

No. Look, it's primarily -- the transaction settlement is primarily focused on the transition. And without kind of getting into the dirty of it, there's been a couple of bad experiences, some of them -- actually one of them in New Hampshire, where the transition of a previous utility did not go smoothly, and so understandably so, the Commission staff is very much focused on ensuring that the transition plans are well-developed, that the resources are applied, that the metrics for measuring success from a customer service perspective are all well developed. And so consequently, the majority of that settlement agreement is really about that whole transition.

There is very little that speaks to the long-term implications. One of the things that we have agreed is that, certainly with respect to EnergyNorth, it just came in for a rate case, that we've agreed that until we get through the transition, we won't come in for a rate case to help -- to ensure that those transition costs aren't somehow confused with the long-term operating costs, and so that was kind of the agreement. But to be frank, what are we talking about, 24 months, that kind of thing, and since it had just come in for a rate case, it didn't seem to be an inappropriate ask from the Commission's point of view. Ian, we don't see anything in that settlement that somehow fundamentally changes the value proposition for us going forward.

Okay, helpful. And then turning to Windsor, you may have mentioned it in the details, but it sounded like you had incentive payment contingent on Q2 completion. Apparently you're still on track for that time line?

Absolutely. You're absolutely correct. Just to put it in context, we qualified for a CAD6.6 million grant from the DPUC, subject to getting the project done, and it's actually, I think in early July, if I'm not mistaken. But you're absolutely right, Ian. And look, everybody's on it. The schedule is -- we've got a very firm hand on the tiller of that schedule.

Okay. Great. And then moving out West to CalPeco, certainly Q1 being a very important quarter for that asset. How do things look so far? I know ski season down there may be looking a bit barren in terms of snow.

We'll have you know, they use electricity to make snow and so --

Good point.

In some respects, their loss is our fake snow gain, and so actually the short answer, we have done very well and so -- anyway. I guess, in some respects, the whole utility game is not about how much energy we sell. We are in the business for earning a return on our invested capital.

Right. Okay. Interesting. And then just turning to the wind transaction, certainly we've covered a lot of details there, but there is reasonable portion of merchant risk here, AES managing that going forward. So I wonder if you can talk about how the merchant portion of the power that's produced and sold will be identified and sold into the market. I think the risk that I'm thinking about is that you've got a windy day. You've filled up your capacity under the PPA to JPM, and you're left with excess capacity to sell into an over-supplied market. Just trying to understand those dynamics perhaps, Jeff, without going into too much granularity.

Sure. So I think the example that you've laid out is a good one, and I'll just continue with that. So if we were generating 50 megawatts, say, at Pocahontas, being the 80 megawatt facility, in an hour, and our obligations under the hedge were to deliver 40 of that, we've got the incremental 10, and what do we do with the incremental 10? Obviously, our cost associated with that incremental 10 is low, so we would be bidding to put that energy into the market and taking the real-time price. But that has been factored in in our analysis and in the curve for merchant pricing, and so we're comfortable with the merchant energy pricing curves that we've used, and what the real-time price we will receive on average will be. Obviously, in any given hour, it's going to fluctuate, but when you take a look at it on average, the curve that was built into the model that tax equity used was derived from Ventyx. We retained PA Consulting to generate curves on our own, and those are what's used in our hourly analysis of the model, factoring in exactly the issue that you have.

Just to add one more point to that, and I don't know if this was your implication, the way you phrased the question, Ian, is that -- Oh, on a windy day you're saturating marketplace. It's interesting, we did a bunch of work to find, is there a correlation between wind production and hourly pricing in the marketplace? And the short answer is, that correlation doesn't exist, and even in a market which has, to be frank, as much wind in it as ERCOT, there is no strong negative correlation between pricing and wind energy, and so I think -- maybe that's not what you were implying, but that relationship actually doesn't exist.

Actually it was what I was implying. I appreciate you taking it on head-on. You made some comments around the Pocahontas asset in terms of the difference between the nodal price and I guess where you would be able to get a PPA. Is there something structural that's happening between the project and that pricing node? Is there kind of a transmission issue, or something that would lead you to think that there's more risk around getting that power to market, or am I reading too much into it?

No, it's really just an R-squared issue. It's not about constraints. It's just about managing the relationship.

The basis relationship.

That's exactly it.

Okay. I think that's it from me. Thank you very much.

Thanks.

Your next question comes from Sean Steuart from TD Securities. Please go ahead.

Thanks for all the detail, guys. I'll be quick. Just a couple of questions. First on call CalPeco, Ian you touched on things rebounding in Q1, as we might expect. Just wondering if you could go into a bit of detail on some of the issues you had in the fourth quarter, and just confirm for us, these are sort of non-recurring issues with respect to higher insurance, those sorts of things.

Well, the first one that we talked about, vegetation management, when you say they're non-recurring, they're certainly part of our rate case going forward. But the insurance definitely -- it's a recurring cost, but it's been built into our rate case from a cost perspective. The vegetation management one is actually pretty specific. We are trying to get established a tracking account, which -- we're in the discussions with the CPUC, so that those costs that are going forward through 2012 are actually aggregated in a separate account.

Managing vegetation in the Tahoe area is a very important element of providing reliable service, and to be frank, helping manage forest fire risk. Consequently, nobody wants to defer vegetation management expenses, including the CPUC, and so we're in discussions with them right now to, in effect, warehouse those costs, if you will, to capitalize them from a regulatory perspective going forward. The other thing that I think you may have seen in CalPeco from a cost perspective, as we are working our way through our cost allocation manual, some of those costs that you saw in CalPeco are really allocated costs, rather than something that's uniquely happened within that utility.

Understood. Then second question, Ian, sort of a bigger picture question, given I guess the amount of growth you have in the near term pipeline. If you guys hadn't walked from the First Wind deal, would this new wind transaction be something you would have still considered? And I guess it's comfort, with the amount of growth you have in the pipeline right now. Maybe you can just speak to that sort of hypothetical question.

Well, let's put it this way. Let me speak to what's attractive about this transaction, is being in a control position is an important part of adding value to us. Certainly that is not the characteristics in First Wind. And the answer is maybe we wouldn't have. Everything is about things in measure, and we wanted to make sure that we bought an appropriate part of -- appropriate interest in US wind, and it's entirely possible that First Wind would have satisfied that objective, and we may not have pursued this. Luckily, things kind of worked out the way they did. I think we feel we can add more value here in the Gamesa assets than we could have in First Wind.

Okay. That's great. Thanks, Ian, and congrats on the deal.

Your next question comes from Matt Gowing.

Congratulations on the deal. My questions have been answered. So thanks a lot.

Thanks, Matt.

(Operator Instructions)

There are no further questions. Please continue.

Great. Thanks very much everybody. Kelly Castledine is going to finish up with some disclosure information.

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 and Utilities Corp with respect to future events, based upon assumptions related to, among others, the performance of the Company's assets, decisions, financial, and regulatory climates in which it operates. These forward-looking statements include, among others, statements with respect to the expected performance of the Company, its future plans, and its dividends to shareholders. Since forward-looking statements relate to future events and conditions, by their very nature, they require us to make assumptions involving inherent risks and uncertainties.

We caution that, although we believe our assumptions are reasonable under the circumstances, these risks and uncertainties give rise to the possibility that our actual results may differ materially from the expectations set out in the forward-looking statements. Material risk factors include those presented in the Company's most recent annual financial results, 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 the our 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.

Ladies and gentlemen, that does conclude our conference call for today. Thank you for participating. Please disconnect your lines.