Algonquin Power & Utilities Corp (AQNU) 2011 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Algonquin Power & Utilities Corp. Q2 2011 analyst conference call. At this time all participants are in a listen-only mode.

Following the presentation we will conduct a question and answer session. We ask that you please limit yourself to 2 questions per turn.

(Operator Instructions)

I would like to remind everyone that this conference call is being recorded today, Friday, August 12, 2011 at 10 AM Eastern Time.

I will now turn the conference over to our host. Please go ahead.

Thanks, good morning, everyone, it's Kelly here. I'd like to welcome you to Algonquin's 2011 second quarter results conference call. With me on the call today are Ian Robertson, our Chief Executive Officer, and David Bronicheski, our Chief Financial Officer. For your reference, the Q2 financial statements and Management's Discussion and Analysis are available for download on our website at algonquinpowerandutilities.com.

I'd like to note that in this call we will provide information that relates to future events and expected financial positions that should be considered forward-looking. This information was developed based on certain factors and assumptions, and we caution that actual results may vary from the forward-looking information. I will provide a bit more detail at the end of the call.

As an agenda for today's call, Ian will start with a discussion regarding a few of the highlights from the quarter. Following that David will review the financial results and then Ian will provide some updates on some of our growth strategies and opportunities. At the end of the call we will host a question and answer period at which point we ask you to limit to 2 questions and then requeue for any further questions you may have.

I will now hand it over to Ian.

Thanks, Kelly, and good morning, everyone. Thanks for joining us on the call today and taking time during what has recently been a turbulent time in the economic environment in the capital markets. While the markets have been volatile lately, to say the least, we are pleased that the stability and steadiness of the business propositions underlying Algonquin Power & Utilities activities have delivered a very solid second quarter. We also had a very active second quarter including a number of exciting announcements. So I'll start the call off highlighting a few of these announcements before David provides the Q2 results.

Before I begin with the highlights I would like to take a moment to touch on our announcement yesterday regarding the Board of Director's decision to increase the annual dividend paid by APUC by CAD0.02 to CAD0.28 annually. I believe that this decision reflects the Board's confidence in our growing cash flows, solid earnings, and ability to deliver on future growth prospects. Our announcements through the first half of the year have increased the growth profile of Algonquin Power & Utilities Corp., or APUC, as we affectionately refer to it, its earnings and cash flows, thereby creating a solid basis on which our Board was able to make the decision to increase the dividend for the second time this year.

And now some highlights from the business. First, recently, we announced that Algonquin Power Company, or APCo again, as we refer to it, has executed a 25-year power purchase agreement with Manitoba Hydro in respect of a 17-megawatt expansion of the existing St. Leon wind energy project. This project is shovel-ready, as they say, since the permitting for the expansion project is already complete. And the turbines which we will be using are immediately available for construction, which is scheduled to commence within the next few weeks. We're pleased that the early 2012 scheduled commissioning date fits neatly into our multi-year business expansion plan, and will allow this project to contribute to our 2012 EBITDA. We believe that St. Leon II is directly attributable to our strong relationship with Manitoba Hydro and the continued support from the St. Leon community.

Second, we had a very active quarter with respect to our relation with Emera. We entered into a strategic investment agreement with Emera which establishes how we will work together to pursue specific investments. The strategic investment agreement outlines areas of pursuit for each company which for Algonquin Power & Utility Corp includes investment opportunities relating to unregulated renewable generation, small electric utilities and gas distribution utilities. As an element of strategic investment agreement, Emera's allowed common equity interest in APUC will be increased from 15% to 25%. We're pleased to report that this agreement received shareholder approval at our recent annual special general meeting held on June 21.

The first initiative announced under the strategic investment agreement is an agreement to jointly construct, own, and operate wind energy projects in the Northeast US. Following regulatory approval the Northeast Wind joint venture to be formed between Emera and Algonquin will acquire 49% of First Wind's 370-megawatt portfolio of existing wind projects in the Northeast US. APUC will initially own 25% of the Northeast Wind joint venture. APUC and Emera plan to work with First Wind to grow the project portfolio through development of other projects in the region. Access to the First Wind pipeline of northeast US-based development projects provides APCo an effective way to extend and lever our wind development expertise in a geographic area which is new to us.

The other initiative under the strategic investment agreement is that Emera agreed to sell its 49.9% direct ownership in the California electric utility to Liberty Utilities in exchange for 8.2 million APUC shares.

On the utility growth front, in May we announced that Liberty Utility entered into an agreement with Atmos Energy to acquire its regulated natural gas distribution utility assets located in Missouri, Iowa, and Illinois. Which currently provides natural gas distribution service to approximately 83,000 customers. The acquisition of these well-maintained, high-quality utility assets is consistent with our growth strategy and provides an opportunity to expand our regulated utility operations in states with which we are familiar to our existing utility businesses. Total purchase price of the utilities is approximately CAD124 million. We remain on schedule with the regulatory approval process and expect the acquisition to close in 2012 after obtaining the necessary state and federal regulatory approvals.

In New Hampshire, work is continuing with respect to the regulatory approvals required for the Liberty Utilities previously-announced acquisition of Granite State Electric Company and Energy North Natural Gas. The current procedural schedule with the New Hampshire Public Utilities Commission contemplates completion of this regulatory process near the end of this year.

I'd now like to hand it over to David Bronicheski to speak about the quarter's financial results.

Thanks, Ian. I'd like to recap briefly our Q2 2011 results. Just to note that we use adjusted net earnings to assess the net earnings without the effects of certain accounting adjustments that are not considered to be reflective of the performance of the underlying business.

Revenue in Q2 was CAD56.8 million and this compares quite favorably to the Q2 2010 revenue of CAD42 million. Adjusted EBITDA in the quarter was CAD28.2 million and this compares favorably to CAD18.7 million in Q2 of last year, as well.

Now some specific highlights. Within APCo's renewable energy division, during the quarter the division experienced strong wind and hydrology resources, allowing it to generate electricity equal to approximately 106% of long-term projected average wind and hydrology, as compared to 81% in the same quarter last year. Net energy sales totaled CAD23.3 million as compared to CAD19.2 million in the same period at 2010, an increase of 21%.

For the second quarter of 2010, operating profit totaled CAD18.3 million compared to CAD15.2 million during the same period last year, again representing a 21% increase. Overall, renewable energy's performance exceeded our expectations due to a strong wind resource in Manitoba and strong hydrology at our US and Canadian facilities.

In Atmos thermal energy division, net energy sales revenue for the second quarter of 2011 was CAD4.8 million as compared to CAD5.3 during the same period last year. The decrease is mainly due to the impact of the shift of the new operating model at the Windsor Locks facility. For the second quarter of 2011 operating profit totaled CAD4.2 million as compared to CAD1.6 million in the same period last year. Overall, the thermal energy division exceeded our expectations due to better than expected earnings at the Windsor Locks facility as a result of higher than expected energy pricing.

Looking ahead to the next quarter, APCo's renewable energy division is expected to perform at long term average resource conditions for hydrology and wind. The capital upgrade that was completed at the EFW facility in 2010 is expected to allow the facility to continue operating in the second half of the year at a similar level to what it has in the first half of the year. The Sanger facility is expected to meet our expectations for the third quarter of 2011 and be in line with the 2010 results. The Windsor Locks facility will continue to sell a portion of its electricity capacity and all of its steam capacity to the industrial host with the balance of the electricity available to be sold either under the ISO New England [diatic] market or to industrial customers through the Algonquin Energy Services business.

Moving on to Liberty Waters, our Liberty Utilities water businesses, the wastewater treatment customer base grew by 4.2% and the water distribution customer base grew by 1.5% compared to the same time in 2010. Revenue for the second quarter of 2011 totaled CAD11.9 million as compared to CAD9.2 million during the same period in 2010, an increase of 29%. The water distribution and wastewater treatment revenue both grew primarily due to the implementation of rate increases over the past 2 years.

For the second quarter of 2011, operating profit totaled CAD6.1 million compared to CAD4 million in the same period in 2010. Overall operating profit from Liberty Utilities water businesses exceeded our expectations for the quarter.

Looking ahead to the next quarter we are expecting continued modest customer growth through the remainder of 2011. The revenue increases from the rate cases completed in Arizona and Texas are anticipated to continue roll in to our results. And Liberty Utilities completed a rate case for Bella Vista, resulting in a rate increase of CAD800,000 that began on April 1 which represents approximately 70% of the requested increase.

Moving on to Liberty Utilities California electric utility business, net energy sales revenue for the second quarter of 2011 totaled CAD6.7 million and operating profit was CAD3.2 million. Overall, we have been pleased with the performance of Liberty Utilities California electric utility and its operating profit has so far met our expectations.

I'd like to take just a couple of moments to review some of our recent financing activities. First, I'd like to touch on APCo's recent bond financing. On July 25, APCo issued CAD135 million in APCo senior unsecured debentures bearing interest at a rate of 5.5% per annum, and it matures July 25, 2018.

This 7-year financing has achieved 4 objectives that we set out to achieve. First, the financing was intended to deal with near-term debt maturities, specifically our CAD70 million St. Leon facility which was coming due in October of 2011. As a result of this financing, APUC now has no debt maturities for several years, thereby eliminating any near-term refinancing risk.

Second, the financing was intended to improve APCo's liquidity and provide additional flexibility to finance its near-term growth initiatives. As a result, APCo now has approximately CAD85 million of room available on its revolving bank credit facility and there is CAD8 million of cash reserves also within the APUC group.

Third, the 7-year maturity of this financing is a better match to the long-lived assets within APCo's portfolio and is a more appropriate match for the permanent capital that will we require in our business.

Finally, the financing was intended to create yet another source of capital to finance APCo's growth initiatives over the medium to long term. As a result, APCo now has access to a brand new fixed income investor base.

Second, I'd like to highlight our subordinated debenture redemption in May. On May 16, Algonquin redeemed all of its issued and outstanding 7% Series 1A subordinated debentures that were outstanding. And in total we issued 15.2 million shares in exchange for these outstanding debentures. This redemption has significantly strengthened APUC's overall capital structure by adding an additional CAD60 million of equity to the balance sheet while at the same time reducing subordinated debt by the same amount. This redemption was accretive from both a cash flow per share and an earnings per share basis.

So, as we look back over the last 9 months, APUC has raised a total of CAD120 million in senior unsecured notes in the private placement market in the US for Liberty Utilities. We've renewed our CAD120 million senior secured bank credit facility for an additional 3 years. We've issued CAD135 million of senior unsecured debentures within APCo. And we've converted CAD60 million of subordinated debentures to APUC equity. Taken as a whole, these CAD430 million worth of financing activities has significantly strengthened the overall capital structure of APUC, placing the Company in a very strong position to execute on our business plans.

I'll now hand it back to Ian.

Thanks, David, for that update. I'd like to wrap up with just a few more moments on our growth strategies and prospects.

Starting with APCo, in addition to the St. Leon expansion I previously mentioned, we are continuing development work on the 25-megawatt Morse wind project in Saskatchewan. This project is actually comprised of 3 contiguous projects which will be operated as a single facility, and which is expected to be operational in late 2013.

In Ontario, we continue to make progress with our 75-megawatt Amherst Island wind project. We are confident that the site-specific wind data confirms the project's estimated annual production of approximately 247 gigawatt hours, through the planned use of newer, more efficient wind turbine generator technology. We have begun the permitting and other pre-construction work. The submission of the renewable energy application is targeted for the summer of 2012 with construction to commence shortly thereafter. We estimate the project will take approximately 12 months to construct.

Our two 25-megawatt Quebec community wind projects continue to progress through the development cycle. Saint Damase and Val-Eo are in the preliminary permitting stage, with ongoing studies and public consultation, with a target to receive all necessary authorizations by the end of 2012.

In our thermal division at the Windsor Locks facility, we are proceeding with the detailed engineering, environmental permitting and project planning work for the installation of a 14-megawatt gas turbine more appropriately sized to serve the mill requirements. We are finalizing negotiations with Ahlstrom for an extended energy services agreement that will insure the project's economic viability through a 10-year extension of the existing contract until 2027. The total expected capital cost for this project is projected at approximately CAD25 million and we believe we are eligible to receive a one-time grant of CAD6.6 million from the state of Connecticut with regards to this upgrade. In addition to installing the new gas turbine dedicated to serve the Ahlstrom steam and electrical load, the existing generating equipment will remain in place and be available to produce electricity for the ISO New England market. We also believe that this project will qualify for a CAD1 million combined heat and power investment tax credit sponsored by the US federal government in addition to the Connecticut DPUC grant.

Now over to Liberty Utilities. As we've discussed in the past, the character of APUC's consolidated earnings is shifting to reflect a materially increased contribution from regulated utilities. With the completion of all our existing announced utility acquisitions, including the acquisition of the Emera 49% interest in Calpeco, our regulated utility earnings will represent well over half of our consolidated EBITDA.

In conclusion, we believe that the new expansion initiatives, the significant progress with regards to implementing our existing opportunity, and the strong year-over-year results resulting from the positive impact of our 2010 growth activities evidence Algonquin Power and Utility Corp.'s ability to deliver against the value creation expectations implicit in our total shareholder return proposition. The confidence of the Board of Directors in APUC's growing cash flows, solid earnings, and future growth prospects is reflected in our recent increase in the annual dividend.

With that, I'd like to turn things back over to Kelly to chair our question-and-answer session.

Thanks, Ian. John, we can open up the lines for questions now.

(Operator Instructions) Rupert Merer with National Bank Financial.

I think all of your investors will be pleased to see the dividend increase. Just wondering if you can give us a sense of your dividend policy at this point. And do you have any targeted payout ratios, for example?

Sure, Rupert. From a dividend policy payout perspective, I think we look at the 2 businesses that we are primarily in, the regulated utility business and the non-regulated IPP business. Within the regulated utility business, I think we would all agree that a payout which is modeled as a percentage of GAAP earnings is probably the most appropriate way to look at determining the appropriate level to pay to investors. And in the IPP business, I think the peer group would suggest that a payout based on available cash flow is likely more appropriate, just given the potential mismatch between GAAP depreciation and practical economic useful life. So internally, I think our Board looks at both of those factors. I don't think we publish a hard and fast number but I think if you back into some reasonable peer group assessment of payout ratios on both of those metrics and do it on a levered basis, you can see that the earnings and growth profile this Company continue to provide the Board substantial head room to manage the dividend.

The dividend increase that came about yesterday, when I say I hope it wasn't unexpected, this is exactly the proposition that we've been advancing to the capital markets. This is why we believe there's inherent value. Perhaps it came a little earlier than the capital markets we're anticipating. But I'm hoping that nobody is shocked by this, that our payout ratio is really quite modest, if you will, at the lower end of certainly the peer group. But ultimately, this is why we are here. We are here to create value opportunities that allow the Board to continue to pay a healthy safe dividend and create value through capital appreciation. So I don't know if that answers your question, Rupert.

Yes, it does, thanks. I'll use my second question for a modeling question. Looking at Liberty Energy, the revenue and operating profit are down quarter-over-quarter. I assume that's normal seasonality that we can expect. Just wondering if you can give us a sense of what we can expect for Q3 and Q4?

You are correct. Not surprisingly because it's certainly not intuitive. The California electric utility is a weak winter peaking utility and that's primarily driven by the fact that, obviously, the ski resorts in the area, snow making machines, those are the primary load. Whereas obviously in a more urban utility, it's air conditioning load in the summer. So for sure, you got it right that it is a seasonality issue. I think Q3, probably from a projection point of view going forward, probably wouldn't look materially dissimilar to Q2. So I think that's probably some reasonable guidance in terms of the load profile. I don't know if that's the kind of thing you're looking for, Rupert.

Yes, that's great. So Q4 would be somewhere between Q3 and Q1?

Absolutely. It starts to ramp back up.

Nelson Ng with RBC Capital Markets.

Just given the market volatility, what are your thoughts in terms of the likely sources of capital for financing the Northwest Wind investment and also the New Hampshire utility acquisition? Net of Emera's share subscription and also the debt raised at the utility level?

I think you raised an important point with the qualifier to your question. Which is the Emera subscription receipts are an important source of providing comfort to the capital markets that we do have the capital committed for both of those acquisitions. I think the financing activities that David spoke of, and the balance sheet that you see in front of you today for Algonquin Power & Utilities Corp is a robust one. It's one that I think if you look at both of those opportunities, the evidence that we have in terms of being able to secure the debt portion of the typical debt portion for those investments, and the flexibility that exists in the balance sheet, means that we have a lot of alternatives. And I think that's always the best place to be particularly in the face of the volatility that exists in the capital markets. So for both Granite State, Energy North and the First Wind acquisition, that we can certainly finance those acquisitions using our existing balance sheet. And if we chose to use debt, the recent conversion of our convertible debentures from the debt side to equity would leave the balance sheet in a not dissimilar place than it was before, and one that we're probably generally happy with. Obviously, we will look to the equity capital markets when it makes sense from the Board's point of view. But I think the short answer from an equity financing point of view is we don't have to do one in order to, certainly in the near term, with respect to the projects you raised. I think that's the right thing for this Company to be in from a shareholder value perspective.

Okay, thanks. And then my second question is more about Sanger and Windsor Locks. Do you expect relatively stable results for the rest of the year in terms of relative to Q2?

They're quite different projects from a risk profile perspective. Let's speak about Sanger first. Sanger is, as you know, operating under a long-term PPA with quite a robust gas price pass through mechanism in the contract with PG&E. And I think it is totally reasonable to look at the history on a quarter to quarter basis, to look at those cash flows going forward. I think Windsor Locks is quite different. And in fact it is that difference in profile which is motivating the Windsor Locks repowering project. As we look at assuring the long-term viability of that project we frankly need to reinvest in the opportunity to change its nature. It is right now, it is a participant in the electricity marketplace in New England. But of course, we're therefore subject to the vagaries of the natural gas pricing and spark spreads within that marketplace. And so, to be frank, it's very difficult to predict because we're, in fact, predicting forward on the gas and spark spreads of the New England ISO for Windsor Locks. But the good news is the investment we're making in Windsor Locks is intended to do 2 things. It de-risks that problem going forward. And secondly lit extends out the horizon to 2027. So those are quite different, Nelson, in terms of their profiles.

Michael McGowan with BMO Capital Markets.

Was wondering if you could provide us with a bit of a status update on the Granite State and Energy North deal?

Sure. We are well into the regulatory approval process. Transition teams are highly engaged from both national grid and our side with a very detailed transition plan, both developed internally but more importantly, submitted to and being discussed with the regulator. We've had over 430 data requests from the regulator. There are no interveners in the process who have a negative view on it. But I think we are working our way to address all of the issues and concerns of the New Hampshire PUC. And I think we're confident and comfortable that the proposition that we're advancing will ultimately meet with their needs and address concerns that they have. And so there is a procedural schedule that has been developed and agreed between all of the parties, and it shows a closing of the transaction, as I mentioned, near the end of this year. We are hopeful that, to the extent that we can meet any issues or concerns of the staff early, we may find ourselves in a position to be able to negotiate an earlier settlement of that. But right now we've just got our heads down, working our way through all of the transition work. But the good news is everybody is totally energized by the process and fully committed.

Okay, great. And if I could just ask a follow-up, maybe a more technical question. Just on your cash flow statement, it shows that if there's a CAD2.1 million OPLO this quarter and CAD6.9 million for the first 6 months of the year on increase in long-term investments in notes receivable, what is that cash flow relate to?

Which particular line are you referring to?

It's in the investing activity, part of your expenditures, increase in long term investments and notes receivable. I was just wondering what type of investment that relates to.

Yes, that would be Red Lily. Our investment in Red Lily takes the form currently of senior unsubordinated debt. So that represents the amount that we advance in the current year related to that investment.

Juan Plessis with Canaccord Genuity.

Just in regard to the seasonality of earnings going forward, can you talk a little bit about that assuming the successful completion of the utility acquisitions?

Sure. Obviously, I think that we're hoping that -- well, I think the history has shown that the investment that we're making in the regulated utility investment business will definitely bring a reduction to the volatility that, frankly, exists in the IPP space. Most notably, even with seasonality, notwithstanding the earlier question of Rupert with respect to the seasonality in CalPeco. Overall, it's far less prominent than you might find, say, in a hydroelectric facility where we could all intuitively imagine that the spring is a much wetter period of time than August. So I think we are driving forward to a business that will deliver far less volatility both quarter to quarter but hopefully from year to year because as a percentage of our earnings, Juan, those naturally occurring wind and water fluctuations should be reduced as a percentage.

Okay, thank you for that. And what's your expectation for the timing of the transfer of the purchase of Emera's interest in CalPeco?

We have prepared and are expecting to file what's called the Section 854 application. It's a transfer approval. We have socialized that whole concept, to be frank. The concept of Emera, if you will, moving upstairs into the Algonquin structure in favor of their current direct interest. And that was part of the original application process when we acquired it and so this has been fully discussed. I met with all of the commissioners in June to let them know that this was coming down the pike. I would hope that we will get that application filed during the month and with the idea of, with a reasonable regulatory procedural schedule, seeing this happen before the end of the year. I think that's a reasonable target.

Matthew Akman with Scotia Capital.

A couple of questions on the development front in Ontario. Ian, how critical was the change in the contract provisions that the government made in accelerating Amherst Island? And is there anything else you've got going on in Ontario that you might be able to bring forward and maybe get contracted over the next 6 to 12 months in renewable?

Thanks, Matthew. It's an interesting question. The changes that the government has advanced. And just for those who aren't aware is that under the FIT contract, the ability for government to terminate those contracts prior to notice to proceed, there's been a waiver that's been proposed, and for which we obviously have accepted or applied for. I think the issue will come down to what happens in the election. To the extent that the liberals remain in power I think this would all have been a mute point. To the extent that the conservatives that come in, given the public statements of the party, it could be very material.

I think what it provides for us is confidence to continue the work that we're doing and investment we're making in Amherst Island. We are obviously fully engaged from an environmental permitting perspective. And that prior to that change we obviously had to be mindful of the fact that that termination provision could have been invoked. And I think this project is sufficiently advanced, I think it's just good news in terms of reducing risk.

In terms of other opportunities for us as a result of that, you know we have a couple of other projects in the queue. They're not nearly as advanced as Amherst Island. But I think where the bigger opportunity might come for us is, to the extent there's ongoing volatility in the capital markets and other developers may have opportunities that maybe are proving more difficult to finance, I think that reduction in the risk profile of these projects as a result of that notice to proceed waiver could provide some opportunities for us to participate with other developers. And I think that's probably beyond Amherst Island, the greatest opportunity for us. It's de-risk other people's projects, as well.

And then just staying with Ontario, is there any update on the energy from waste expansion or is that off the table now?

I think in the context, and you may have read in the MD&A that the Region of Peel, their counsel has, through a resolution, asked us to negotiate an extension of the existing contract with us of not less than 2 years and probably between the 2 and 5-year mark. The objective of that breathing room, if you will, I believe -- and this is obviously you could ask the Region of Peel for the skinny on this one -- but I think the reason of this objective is to see what the long-term relationship that EFW will play in the waste management solution for the Region of Peel. That's a pretty broad spectrum. It could go from expanding that facility to 250,000 tons, to address a bigger portion of the Region of Peel's solid waste needs. And so, really, I think when you say off the table, really what I think it's done is the current plan is to give everybody the breathing room and allow the plant to continue to operate. It's operating very well, as you can see from the results. Give everybody the breathing room to work their way through what it's going to look like for the next 20 years. And I think that's the answer that everybody is trying to come to.

Wojtek Nowak with Fraser Mackenzie.

So first question is on St-Leon. Originally there was 85 megawatts of expansion potential there. What's happening with that remaining potential and the timeline for that?

Great question. As you know, as you accurately point out, St-Leon was constructed with an interconnect which is far bigger and will support far more than the 17 megawatts that we've currently contracted. I think the way we look at it is it's not going away. The wind resource remains, our land at tenure remains, the permitting remains. And so you might actually think of this first that this 17-megawatt expansion is hopefully the first phase of multiple phases. In terms of the timing of it, to be frank, it probably rests more in Manitoba Hydro's court in terms of what makes sense for them and how it will fit into their process going forward. I think we are totally thrilled with the support that this project has received from the St-Leon community. And I can't think of a better opportunity, to the extent that Manitoba Hydro needs more power, of this project participating competitively in whatever process they may come up with. So the way I look at it, it's a latent opportunity which sits on our balance sheet and you'll hopefully you'll see more of these phases coming forward in the future. Wish I could give you a better idea of the timing but the permitting and the land tenure isn't going to lapse any time soon.

And just secondly, you had previously talked about the possibility of a PBA for the Windsor facility with Connecticut Light & Power. Where is that thought right now?

I think the decision that we've made from a repowering perspective probably indicates we're going in a different direction than that. Originally, as you accurately point out, we had hoped to be able to negotiate a contract that would keep the existing facility operating in the same forum. Not sure that -- it's hard to sometimes move a large utility at the speed that you'd like to go. And so we ultimately made the decision that a repowering of the facility makes the most sense. What it does leave, and I will point out, that the existing Frame 6 turbine and steam turbine and HRSG remain available for us to participate in the New England ISO market, as it makes sense. I think with having Ahlstrom there as a steam load makes the heat rate reasonably competitive. But as I pointed out earlier, I'm just not sure the risk profile makes sense for us to continue to operate the existing equipment under it where you counted on the spark spread. So I think going forward this is the right thing for us. It has de-risked the proposition quite substantially. And it does leave us the ability to continue to use and participate, use the Frame 6 participating in New England ISO.

John Safrance with M Partners.

So just to actually follow-up on Wojtek's question about Windsor. In terms of the incremental operating profit off a repowering, what would that look like?

In some respects, the operating profit off of the new solar T130 turbine will not be dissimilar to the existing ESA. I think the real question, if you try to model this going forward, is what kind of contribution will the Frame 6 turbine make to the long-term projections for Windsor Locks. I think we are confident and comfortable that the CAD20 million or so which is going into the solar repowering is definitely warranted in terms of the EBITDA off of just the ESA contract with Ahlstrom. Which is being extended, as I pointed out, to 2027. So I think as you think about the value proposition, you've got to take a view of not only the CAD3 million or CAD4 million of EBITDA which is generated under the existing ESA. But what can these guys do with that Frame 6 turbine in the marketplace going forward in terms of the forward reserve markets, in terms of participating in the merchant markets. And to be frank, it's hard to look at that and make some solid projections. But I think you have to look at both of those 2 elements. I don't know if John, I appreciate I didn't give you a really solid answer on the Frame 6 but it kind of is what it is.

I appreciate the effort. And then just secondly, it's a bit of a glaring hole in my model at the moment, but my apologies if you published this elsewhere, but do you have a seasonality profile for Red Lily I?

I don't know, it's probably not a glaring hole in your model, and we should probably think about doing that. As you know, it only joined the fleet in February of this year. But thanks for pointing that out. And I'll give you a call back after this and we'll make sure we get that kind of seasonality into the disclosure. It's obviously not all that material but we'll make sure you get it.

Ian Tharp with CIBC World Markets.

So I'll change direction for a moment and look at the Quebec inspections that have been going on for all 11 dams there. So you gave some details on the schedule against the CAD17.7 million that would be spent. I just wanted to confirm, that's not only the applications that have been submitted and approved. Is that all 11 of the dams that is included in the CAD17.7 million?

Yes, what you're seeing there is the sum result of everything. So that's the totality of what we see in front of us. There's obviously approvals that we still have to work through with Hydro Quebec and sometimes that takes quite some time to get their approval on it. But that's the totality of it.

And then for my next question, maybe change direction to Saskatchewan. I know they've got an RFP process that bids are due for in the next couple of months. I wonder if you can speak to your activities within that. And also, I know Red Lily II can expand to the tune of about 106 megawatts. Is your view of the RFP such that that would qualify under Saskatchewan's rules for the RFP for this round?

Yes, the Saskatchewan RFP was actually preceded with the Saskatchewan RFQ, if you will. And projects, if you're going to participate in that RFP process, you actually already had to pre-qualify in terms of land tenure, in terms of wind data. So we will be making 3 submissions into that RFP, including Red Lily II. And so I can tell you, I believe, if I'm not mistaken, there might be 22 potential projects will be bid into it. So, look, it's going to be highly competitive. I think we have a great wind resource and perhaps even better, we've been operating in the province for the better part of the year. And so I'm confident of our ability to participate in it. But it is going to be a competitive process, Ian.

I had heard that some of the 22 projects potentially had since been disqualified based on revised terms.

Maybe.

If you don't know then perhaps you aren't subject to it, which is good. And then a follow-up on that, if I may. Depending on when they put their announcement out, when do you expect that? And then also when would you have the project online if you were successful in Saskatchewan?

As you know, that's a whole RFP. I think it was supposed to go in, and I may be misspeaking, in June of this year and it keeps getting delayed month by month. From the time they give us the go ahead, if you will, 18 months is probably not an unreasonable time frame, maybe even a little more, 18 to 24 from the time you hear us make a press release that we've been awarded a PPA to the first kilowatt hour comes out of the farm. That's probably not an unreasonable time frame.

Marko Pencak with GMP Securities.

First question is, with all of the financial distress that a lot of the US municipalities are undergoing right now, do you see any opportunities for Liberty Water or Liberty Energy in that regard?

That's been the Holy Grail, to be frank. We've been waiting for that tidal wave of municipalities to go through privatization of the water business. And as you allude, maybe even their electrical system. You'd think that the pressure that they're under from a budgetary point of view means they could be moving that capital out of relatively low earning assets into other more socially relevant investments. To be frank, though, we just haven't seen it. And I think it comes down to a little bit that utility investment, particularly water, felt a little bit like the crown jewels in that you're selling them off from a municipality perspective. And so, boy, is there a big latent opportunity there, I'm just not so sure when that tidal wave is going to hit the beach. But we're ready, willing and able to surf her in, if you will.

The reason I ask that, I know there is that, they want to hold on to it. But these are interesting circumstances when the Greeks are considering selling their island. So that's why I asked that. Secondly, just with respect to Quebec and prospects of another wind call, and if there were one, how might you be positioned? Could you talk about some of the projects you currently have developed but things you might have beyond those?

And we should just mention, you touch on the thing, as we talk about projects, we frankly don't talk about the pipeline of, I'll call them bragowatts, if you will, that we have So as we speak about Quebec, we have a fair number of projects. I'd probably estimate it 300 megawatts, 400 megawatts worth of projects that we have, land tenure to, we've been collecting wind data on. So we are confident and comfortable that these projects have feasibility. It's just we're waiting for Hydro Quebec to announce that call. So I think that would be great news for us. We would be active participants in that process, just not so sure exactly when it's coming down the pike, Marko.

James Morrison with Cormark Securities.

Just want to follow-up on the FIT program and the conservatives possibly coming in here and raining on the party. How comfortable are you with that, that that waiver has locked in that contract? Or are there other clauses in the contract that you think they could attack and have these agreements nulled?

It's an interesting question, James. Ultimately, as you know, in any of these things, governments always have the right power that they can always play. I think this was the most obvious provision that may have existed for termination of some of the existing contracts. I would hope, and maybe this is just a hope from my perspective, is that if there is a change in government that the value that the liberals obviously see, and frankly we share, that's created with the FIT program, and those existing contracts, that a new government doesn't make it their life mission to see how we can put a bullet in these projects. These projects are contributing, obviously, to the energy security of the province. And so the only question that you have to ask yourself, is this the most cost-effective way to do it. Not whether we should do it, not whether it's the right thing to do, but are we doing it the most cost-effective way. I think the provisions that the liberals have introduced in terms of the waiver of the notice to proceed is, frankly, about getting those projects that are close enough to guarantee job creation, because one of the provisions of the notice to proceed is about having an agreement with a manufacturer of equipment who's going to meet the local domestic content rules. There are a lot of objectives. And so, as I said, I'm hoping that it doesn't become somebody's life mission and that they turn their attention to other things which is going forward, what's the right thing to do within the FIT program. But you never know.

And I just saw in your MD&A here that for the rest of the year, for the full year, you're budgeting CAD20 million to CAD23 million for CapEx. And then in there, there's CAD10.5 million related to the thermal division. What is that going to be, because it seems like that's all back end weighted?

Yes, what you're seeing there is the estimated capital for repowering at Windsor Locks.

Okay, so that's as if it's going through? Is that capital committed?

I think for all intents and purposes it is. We're working our way through the project. Obviously there's a number of gating items, the most obvious of which is we're finalizing the energy services agreement with Ahlstrom. But as things stand today, I think we are optimistic that the project has the necessary elements to proceed. We are spending money on project planning and environmental permitting. So I think from a forecast perspective going forward, I think the balance of probability says this project is getting built and therefore we should show the capital.

And that CAD10.5 million, if that gets spent is it binary? Like that doesn't get spent and none gets spent? Or CAD10.5 million gets spent and the whole thing gets spent?

No, it's binary. Either we're going ahead and spending the whole CAD10.5 million or the project's not going ahead and you aren't spending any of the CAD10.5 million, including the balance that's going to get spent next year.

Yes, sorry, that's what the question was, that if you spend CAD10.5 million you're going to continue to spend all of it.

That's right.

Matt Gowing with Mackie Research Capital.

Just wondering, with some of the turmoil and volatility going on in the energy commodity price market, how that affects your outlook for the ISO New England market in terms of the outlook for pricing, if these volatile prices will have an impact and what the impact could be on your profitability there in New England.

First of all, I start by saying, as you know, the portion of our portfolio which is not locked in under contracts is relatively small. And even the portion within New England which includes Tinker, we tentatively have sold for it over at least 2, 3 years. So I'd start by saying that our exposure in general to the New England ISO market is relatively limited. Particularly as the business grows and we start bringing on projects like St-Leon II and Red Lily, even as a percentage of the existing exposure gets reduced. I think I'd say, just the short answer to your question is, our exposure, both on an upside and potential downside perspective within the New England ISO pricing market, is relatively muted. I think that would be the right way to phrase it, Matt.

And just one final question related to the Windsor Locks. When do you think you'll have visibility or a decision from the state whether you'll be eligible for some of these grants because it's a material amount, about CAD7 million or something like that of total grant money?

Yes. We're eligible for the grants. That's not the question. I think the question is, assuming we're going ahead with the project, for that CAD6.6 million Connecticut DPUC grant, the project needs to be online by July of next year. The current schedule has it being online by that target. I think the question that really is sitting outside is not whether we're eligible for the grant but whether, to be frank, we come to a final conclusion with Ahlstrom, we sort out whatever permitting issues. The grants, I think, are almost a foregone conclusion, assuming we go ahead with the project.

Sean Steuart with TD Newcrest.

Quick question, and maybe this is a better question for the Board special committee. But you have wording in the MD&A around the relationship with APMI and looking to streamline and simplify that relationship by year-end. Can you give us any context on how this plays out? Is this just a one-time payment? Any sort of thoughts on structure that you can share with us?

Sure. I'd like to start by saying that I think all of that information is included in the interest of full, plain and true disclosure. I think if you look at each and any of those historic legacy interactions between APMI and APUC going forward, you'll come to the conclusion that each of those, either individually or collectively, is not material to the business going forward. I think the objective of the special committee is, frankly, to resolve them, come to a conclusion, part ways where it makes sense. I'll give you an example. Obviously -- or maybe not so obviously -- the old manager of Algonquin Power & Utilities Corp, APMI, had a number of projects that the operating forces of APUC were operating, albeit getting paid for. But it made sense from the Board's perspective and, frankly, from APMI's perspective, to let's just server our relationship. Not that it's not a fair value being paid but it just adds a level of complexity. So in that instance, APUC will stop providing operating services, APMI will go out and hire its own people, and has done that. And it just, I think, cleans up the relationship. So I think the objective of the Board is to reduce that list down to, just by exactly the type of thing I said, to say, -- Okay, we'll go here, you'll do this. But there's no huge payment coming as a result of that. I think from an economic point of view, they're all pretty immaterial, Sean.

And just one last question on Windsor Locks. Just with respect to the quarterly generation, we saw a good increase. Can you just give us some context?

Sure. I think as I pointed out to Nelson and those guys earlier, Windsor Locks, the generation you see off that project is going to be directly dependent on what the spark spread and the gas and electricity marketplace has looked like in the New England ISO. And I think that spike in generation is reflective of the fact that we had an attractive opportunity to make money. We'll obviously, we're going to push that accelerator down when that opportunity exists, and you're seeing the generation resulting from that. I think the issue that you have to obviously consider is that's, I wouldn't say it's a risky proposition but it's a proposition which is founded on things that are largely beyond our control. And so while we're pleased that the markets have worked out well, I think the objective of the repowering projects that you see in front of us is to eliminate that risk from our proposition going forward.

Jeremy Rosenfeld with Desjardins Capital Markets.

There's a lot of discussion around the Windsor Locks and also on the merchant's exposure. And from a higher level perspective, I was just wondering, why could really the incentive to keep these assets as opposed to potentially looking to sell those assets off into the capital markets. And recycling that capital for use in some of the other more attractive growth projects.

I think you ask a big picture question which is, as we think about the portfolio going forward, what's the right mix. And does the natural gas assets, right up until April of 2010, Sanger and Windsor Locks both provided a huge amount of stability to the naturally occurring volatility in our hydro and wind assets. Obviously, we had to deal with the end of the PPA in Windsor Locks. And I think the way we've elected to deal with it, at least until we make the strategic decision to say that natural gas projects no longer fit in our portfolio, is to find a reinvestment opportunity which takes away that volatility of which you speak. It's a totally fair observation that it exists today. And I think while the project is kicking off a reasonable EBITDA, I think you make the reasonable point that it is subject to a bunch of natural gas and pricing volatility. Which that unto itself is not part of our value proposition going forward. So I think we will continue to look at our portfolio. We look at whether adding more, getting rid of some of the natural gas might make sense. And so it is something that is always under a discussion, Jeremy.

And then maybe just another high level question. Since I think all of the other detailed questions have been asked so far. Looking at the capital markets right now and the lower bond yields that we're seeing, is there any incentive to try to refinance other debt that exists? I know that there's nothing that's due in the near term but either refinance or maybe try to be more aggressive on the debt side to try to get better rates and try to make the equity investments that you have going for you, stretch them even farther?

Jeremy, just to touch on that. Following the (inaudible) at our St-Leon facility, our project level debt that we're going to have in our capital structure is about CAD60 million, give or take. And as we look at it, and we do look at it from time to time, the debt that's there is sufficiently long term and the makehold sufficiently large that we feel that it just doesn't make sense to collapse that at this time. And then with respect to just your comment overall, I think we've been working very hard in our capital structure over the last 2 years and have made significant progress. We've dramatically lowered our cost of capital over that period of time. And it continues to be a significant focus for the Board and management to continue working on that. And I think what you'll see as we move forward in the fall, we do have our utility acquisitions for Granite State and Energy North. And so we will be looking at getting long-term debt, and in this case in US dollars, placed for that acquisition. And we fully expect we're going to achieve very attractive rates, certainly as good as what we've experienced to date and perhaps a little bit better.

(Operator Instructions) Ian Tharp with CIBC World Markets.

So just a bit of a follow-up on CalPeco. I think you announced last fall and perhaps in the MD&A you have a rate case filing coming up, I think, this month. So I wonder if you can speak to that process. And also the environment for rate cases in California currently.

Sure, Ian. I think the rate case for, and as you know, in California, we are on a 3-year regular rate case cycle. And the typical filing time would be August of this year. I think with 2 things. One is the 854 application which is sitting in front of the Commission. But more importantly, the fact that we really only took the project, took over the utility in January of this year. It's probably going to make sense to delay that 4 or 5 months so that we have the better part of our first year of operating data under our operating paradigm and structure in place. So while we had originally thought that we would make that application in March and discussions with the CPUC and the Department of Rate Fair Advocates, I think we came to the conclusion that the application would be better received if we elected that few months delay.

With respect to the environment in California, as I've mentioned before, we are comfortable and confident of the rationality of the California regulatory environment. All of our discussions have confirmed that suspicion, our continuing discussions with the BRA. It seems like that there's a totally fair balancing going on between the interest of the utility and interest of the rate payers within the CPUC. So I think we are optimistic that we're going to get fair and reasonable treatment in the jurisdiction and I think that the delay of this by a few months just makes sense to insure that.

Mr. Robertson, we have no further questions at this time. Please continue.

Great. Thanks, everyone, for joining us on the call today and I'm going to leave it, turn it over to Kelly for a quick review of our disclaimer.

Certain written and oral statements contained in this call are forward-looking within the meaning of certain securities laws and reflect the views of Algonquin Power & Utilities Corp with respect to future events based upon assumptions relating to, among others, the performance of the Company's assets and 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. Since forward-looking statements relate to future events and conditions, by their very nature they require us to make assumptions, and involve inherent risks and uncertainties. We caution that although we believe our assumptions are reasonable 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 and 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 the 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, this concludes the conference call for today. Thank you for your participation and you may now disconnect your lines.