Algonquin Power & Utilities Corp (AQNU) 2010 Q4 法說會逐字稿

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Algonquin Power & Utilities Corp. Q4 analyst conference call.

At this time all participants are in a listen-only mode. Following the presentation we will conduct a question-and-answer session with instructions provided. (Operator Instructions).

I would like to remind everyone that this conference call is being recorded today, Friday, March 4, 2011, at 9 AM Eastern time. I will now turn the conference over to Chris Jarratt.

Thanks, John. Good morning. My name is Chris Jarratt and I am the Vice Chairman of Algonquin Power & Utilities Corp. I would like to welcome you to our call, the 2010 fourth-quarter and year-end results conference call.

With me on the call are Ian Robertson, Chief Executive Officer; David Bronicheski, Chief Financial Officer; and Kelly Castledine, our Manager of Investor Relations.

For your reference, the Q4 and year-end financial statements and Management's Discussion and Analysis are available for download on our website at algonquinpowerandutilities.com.

I would like to note that in this call we will provide some 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. Further details will be provided at the end of the call.

As an agenda for today's call, Ian Robertson will start with a couple of highlights from the quarter. Following that our CFO, David Bronicheski, 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 have a question-and-answer period.

With that I will pass it over to Ian Robertson.

Thanks, Chris, and good morning everyone. As Chris mentioned, my name is Ian Robertson. I am the Chief Executive Officer of Algonquin Power & Utilities Corp.

I would like to start with some highlights from our fourth-quarter results, and beginning with Algonquin Power Co., or APCo as we affectionately refer to it. In Q4 of this year APCo saw relief from the broadly distributed challenging hydrologic condition that we and others in the industry had been experiencing earlier in the year.

In particular, Manitoba, New England and New York saw a return to overall resource conditions generally in-line with long-term averages, while our Western and Ontario region continued to show lower than average resources. APCo enjoyed significantly above long-term average hydrology in the Maritime and Quebec regions.

The good news is that to date the first quarter indicates renewable resources generally in-line with average conditions. In the Thermal Divisions we were pleased to have our energy from waste facilities back online through the latter half of 2010. And look forward to continued improved waste processing throughout 2011 as a result of the major capital projects that took place in early 2010.

Within the Liberty Utilities Group operations at Liberty Water, which serves approximately 76,000 customers, were generally in accordance with expectations, with modest continued growth in customer count.

We continue to focus on the growth of this operating subsidiary with a target to grow our regulated utility business by the end of the year to a point where it will contribute at least half of APUC's go forward EBITDA.

Significant contributors to meeting this goal, we note the successful New Year's Day closing of our 47,000 customer California electric utility, and the upcoming closing of the acquisition of Granite State, an electric distribution utility, and EnergyNorth, a natural gas distribution utility, both in New Hampshire, that where previous previously announced on December 9. With these new utilities the Liberty Utilities Group will be providing over 0.25 million customers with reliable, safe and cost-effective utility services.

I would like to now take a couple of minutes to provide a quick recap of the progress of some of our previously announced 2010 growth initiatives. In general, we had a very active fourth quarter with some very positive news to start 2011.

First, to our Liberty Water rate cases. During 2010 Liberty Water was very active in the pursuit of rate cases across the organization, and successfully completed rate case proceedings at nine utilities in Arizona and Texas, which on an annualized basis are expected to contribute an additional CAD10.2 million in revenue for Liberty Water.

We saw CAD2.3 million of these revenue increases delivered in 2010 results, and we will realize the full run rate in 2011. We have one remaining additional Arizona rate case in which we are requesting a revenue requirement increase of CAD1.1 million, which is expected to be concluded by the first quarter of 2011.

Secondly, our electric utility acquisition in partnership with Emera. As previously noted, the California electric utility acquisition by Liberty Energy was finalized on January 1, following receipt of regulatory approvals from the California and Nevada Public Utilities Commissions.

Since that date we have been operating under the Liberty Energy banner, and are pleased to report that we have been reliably serving the electricity needs of our customers while we have been building out the capabilities of the California-centric organization needed to meet our objective of best-in-class customer service.

To deliver on our proposition a number of key individuals from Liberty Utilities management group from Arizona and Toronto have been relocated to the Lake Tahoe region.

Lastly, we have had some recent exciting news from our development team with respect to our win development efforts. In late December Hydro-Quebec Distribution announced the acceptance of proposals for the purchase of energy from the 24 megawatt Saint-Damase and 24 megawatt Val-Eo wind power generating projects for the community-based call for offers announced in the spring of 2009.

The first 24 megawatt phase of the Saint-Damase wind project is currently envisioned to consist of 12 2 megawatt ENERCON E-82 wind turbine generators, producing approximately 86,000 megawatts hours annually.

Construction of Saint-Damase is expected to begin in early 2013 with a commercial operations date in late 2013. The first 24 megawatt phase of the Val-Eo wind project is expected to be comprised of 8 3 megawatt ENERCON E-101 wind turbine generators, producing approximately 66,000 megawatt hours annually. Construction of Val-Eo is expected to begin in early 2015, with commercial operations occurring in late 2015.

As recently as a week ago today we announced that the Ontario Power Authority, or OPA, as part of their feed-in tariff program awarded a contract to our 75 megawatt Amherst Island wind project, located on Amherst Island approximately 25 kilometers southwest of Kingston, Ontario.

The project is currently contemplated to use newer, more efficient wind turbine generator technology, that based on historic wind resource data is estimated to produce approximately 247,000 megawatt hours of power annually.

We are now beginning to the permitting and other pre-construction work, and we will announce capital funding plans for the currently estimated CAD220 million project once all of this work has been completed.

The submission of the renewable energy application is targeted for the summer of 2012 with construction to commence shortly thereafter following approval of this application. We estimate that the project will take approximately 12 months to construct.

Finally, earlier this week we announced that the 26 megawatt Red Lily I wind generating facility in southeastern Saskatchewan had commenced commercial operation. While our CAD19.6 million commitment in Red Lily has been initially structured in the form of senior and subordinated debt, with returns to APUC from the project coming in the form of interest payments and other fees, APUC has the option to formally exchange this debt and fee interest for its 75% equity interest in the facility in 2016.

These successes in the renewable energy sector reinforce our continued focus on economic longevity, environmental respect and community engagement.

I would like now to hand it over to David Bronicheski, our Chief Financial Officer, to talk about the quarterly financial results.

Thanks, Ian. Now a review of the Q4 and entire year 2010 results. Just as a note, we use adjusted net earnings to assess the net earnings without the effects of gains or losses on foreign exchange, foreign exchange forward contracts and interest rate swaps, as these are not reflective of the performance of the underlying businesses.

Revenue in Q4 2010 was CAD48.9 million, and that compares favorably to Q4 of 2009 where we had revenues of CAD43.4 million, and compares favorably with Q3 2010 where we had revenues of CAD45.4 million.

Our adjusted EBITDA was CAD20.7 million in the quarter ended December 31, 2010, and that compares favorably with a year-ago Q4 2009 EBITDA of CAD18 million, and the EBITDA in Q3 of 2010 of CAD17.8 million.

Adjusted net earnings were CAD18 million in Q4 2010, and again that compares favorably with Q4 of 2009 where we had adjusted net earnings of CAD11.5 million, and in Q3 2010 adjusted net earnings of about CAD1 million.

Now some fourth-quarter highlights from our operating subsidiaries, beginning with Algonquin Power. In Algonquin Power's Renewable Energy Division during the fourth quarter of 2010 net energy sales totaled CAD21.4 million, and the division generated electricity equal to approximately 100% of long-term projected hydrology and wind.

The increases in net energy sales compared to the same period last year is mainly the result of above long-term average hydrology in the Maritimes and Quebec regions.

For the fourth quarter of 2010 operating profit totaled CAD15.1 million as compared to CAD10.4 million during the same period in 2009. Overall, the Renewable Energy Division did meet management's expectations due to improved hydrology in Quebec and the Maritime regions.

In APCo's Thermal Energy Division, net revenue for the fourth quarter was CAD11.1 million as compared to CAD12.9 million during the same period in 2009. The decrease is mainly due to the impact of the shift of the new operating model that we have now at Windsor Locks and the closure of our land-fill gas facilities. As an additional note, the generating assets at the LFG facilities were sold in the fourth quarter.

For the fourth quarter of 2010 operating profit was CAD5.1 million as compared to CAD5.9 million during the same period in 2009. Overall the Thermal Energy division did not meet our expectations due to lower earnings from the Windsor Locks facility.

Looking ahead to the next quarter APCo's Renewable division is expecting to perform at long-term average resource conditions for hydrology and below long-term average wind and resources in the first quarter of 2011. The Red Lily Wind facility is now in full operation, and APUC will receive interest payments on its debt financing of the facility in addition to approximately CAD1.3 million for supervisory fees during 2011.

Total interest and fees in 2011 are estimated to be approximately CAD2.4 million.

The capital upgrade completed at the EFW facility is expected to continue operating at a higher throughput through lower operating costs, which should positively affect our operating profit generated by the facility in 2011. Our Sanger facility is expected to meet our expectations for the first quarter of 2011 and be in-line with 2010 results.

Hydro mulch sales are expected to be similar in 2011 compared to 2010 due to continuing low demand for hydro mulch in the US.

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 electrical capacity available to be sold either into the ISO New England day ahead market or to industrial customers through the energy services business of Algonquin.

The facility did not commit any portion of its remaining capacity to the forward reserve market for the winter of 2011 due to unacceptably low auction prices. We anticipate that performance during the first quarter of 2011 will be good, resulting from moderate gas prices, together with a cold winter in the Northeast US that have resulted in high electricity prices.

Moving onto Liberty Water, revenue for the fourth quarter of 2010 totaled CAD9.9 million, as compared to CAD8.7 million during the same period in 2009. Water distribution and wastewater treatment revenue both increased, primarily due to increased demand and implementation of rate cases.

The wastewater treatment customer base grew by 2.1% and the water distribution customer base similarly grew by just over 2% over the number of customers at the same time in 2009.

For the fourth quarter of 2010 operating profit was $4.6 million compared to $3.7 million in the same period a year ago. Overall Liberty Water's operating profit did meet our expectations for the quarter as a result -- or rather, did not meet our expectations for the quarter as a result of delays in receiving some of the decisions on rate cases.

Looking ahead to the next quarter for Liberty Water, we are expecting in 2011 a continuation of the modest customer growth that we experienced last year. Revenue increases from rate cases completed in Arizona and Texas on an annualized basis are expected to contribute CAD10.2 million in revenue for Liberty Water.

Additional rate cases with revenue increase requests of CAD1.1 million in annualized revenues are expected to be settled in the first quarter of 2011. And, of course, these details can be found on page 28 of our MD&A.

Moving onto Liberty Energy, we completed the Calpeco acquisition on January 1 at a purchase price of approximately $131.8 million. The acquisition was funded in part with the proceeds of our CAD70 million senior unsecured private debt placement and proceeds from the CAD8.5 million Emera subscription receipts. We look forward to reporting our first-quarter results for Liberty Energy at the beginning of May.

With respect to the Granite State and EnergyNorth acquisitions we are expecting closings to occur in the fall of this year, and we are working on the state and federal regulatory approvals required for closing. Financing to the acquisitions is expected to occur simultaneously with the closing of the transactions. And we are targeting a capital structure of approximately 50% debt to total cap, consistent with investment-grade utilities.

In connection with these acquisitions, Emera has agreed to a Treasury subscription of subscription receipts convertible into 12 million APUC common shares upon closing of the transactions at a purchase price of CAD5 per share, representing an approximate premium of 5% to the closing price on December 8, 2010. The proceeds will be used to fund a portion of the acquisition of Granite State and EnergyNorth.

I would like to comment briefly on our income tax recovery of CAD15.5 million recognized in the quarter. There are two reasons for this income tax recovery. First, we recorded an additional recovery of CAD2.4 million related to the recognition of deferred credits from the utilization of future income tax assets, which were acquired as part of our conversion to a corporation in late 2009.

Secondly, in the fourth quarter of 2010 APUC completed the Liberty Water portion of its overall capital structure project. The objective of the capital structure project was to ensure that APUC's operating subsidiaries each had the capital structure that is appropriate for the business sector and functional currency in which it operates. Therefore, as part of this process, APUC converted certain Canadian dollar denominated intercompany notes with Liberty Water into US dollar denominated notes, resulting in a realized foreign exchange loss for tax purposes, which created a future tax asset of approximately CAD12 million that is now available to shelter taxes in future years.

I would like to just touch on a couple of our financing activities. In late December Liberty Water and Liberty Energy entered into private placement debt financings. Liberty Water completed a senior unsecured CAD50 million private placement financing with proceeds used to reduce outstanding indebtedness under APCo's senior credit facility. And Liberty Energy entered into a senior unsecured CAD70 million private placement with proceeds going towards the acquisition.

Most recently we announced that we have now renewed our bank credit facility with our syndicate of four Canadian banks. It is a CAD142 million senior secured revolving credit facility with a three-year term. We view this renewal as a major element of our capital structure to support our operations and growth initiatives.

With that, I will now turn things back over to Ian.

Thanks, David. I would like to wrap up with an update on some of our growth strategies and the prospects for 2011, starting with APCo. We are continuing development work on four sites in Saskatchewan, representing over 500 megawatts of wind power potential, including Red Lily Phase II. A number -- or three of these projects were qualified to participate in SaskPower's upcoming RFP, where SaskPower will be procuring up to 175 megawatts of additional wind power.

In Ontario for our 40 megawatt Prince Edward County wind project that was submitted under the Ontario feed-in tariff program, we have received confirmations from the OPA that the project is now being reviewed under the economic connection test.

Switching to Liberty Utility, the business development objective for this group is by the end of the year to have committed assets and initiatives which can deliver assets and earnings to match or exceed those provided in and through APCo.

With the completion of the Calpeco acquisition in our Liberty Energy business, the announcement of the Granite State and EnergyNorth acquisitions, and our Liberty Water rate cases, we do expect that by the end of 2011 the percentage of EBITDA generated by regulated utilities will be more than half of APUC's total EBITDA.

For Liberty Energy we are focused on follow-on electric and natural gas [distribution], utility and transmission-related investment opportunities. As we have discussed, our strategy is to acquire portions of large utilities that are located in non-core state jurisdictions. While these target acquisition opportunities are small from the utilities' parents' perspective, the CAD100 million to CAD200 million transaction and size is exactly in Liberty Energy's sweet spot.

Acquiring these utilities will allow us to continue to execute on our strategy of sharing common administration and customer service infrastructure between utilities to generate economies of scale which support best-in-class customer care for all of our utility ratepayers.

In conclusion, our primary focus in 2010 was to deliver on the value consolidation initiative we outlined at the outset of the year. While weak hydrologic conditions and the strengthen of the Canadian dollar over the course of the year were challenging in terms of our 2010 earnings, we are pleased to be able to celebrate successes in our growth initiatives.

We expect 2011 to demonstrate the full-year impact of these activities, notably the completion of rate cases in Liberty Water, the commissioning of Red Lily Phase I wind farm, and the commencement of utility operations at the California Pacific Electric Company.

Looking forward, 2011 objectives include further growth in the Liberty Utility's business with the closing of the Granite State and EnergyNorth acquisitions, together with announcements of additional in-scope Liberty Water and Liberty Energy acquisitions. We expect that with the recent power contract awards in Quebec and Ontario APCo will be able to move a number of its development projects into the committed growth initiative category.

Lastly, as many of you may have noted, our Board of Directors decided to increase the annual dividend paid by Algonquin Power & Utilities Corp. by 8% to CAD0.26 annually. This decision was in response to the successes we have been able to achieve against the value consolidation objectives established in 2010.

For APUC the determination of appropriate dividend payout reflects our Board's consideration of multiple factors, given our two distinct power and utilities business units. These factors include free cash flow, a metric commonly used by our er independent power peers; gas earnings, which is more commonly used in the regulated utility sector; and lastly, an assessment of our attractive investment opportunities.

2011 will be an active year for APUC, and we look forward to communicating our hopefully continued successes as we achieve our goals. With that I would like to turn things over to Chris Jarratt, to chair our question and answer session.

Great, thanks, Ian. We would be happy to answer any questions anybody has right now.

Ladies and gentlemen, we will now conduct the question-and-answer session. (Operator Instructions). James Morrison, Cormark Securities.

I think you said that you didn't sell any power at Windsor Locks into the forward reserve market. Did you deliver anything to the energy services business or was it just producing enough to supply Ahlstrom?

No, what we didn't do is commit to the forward reserve auction. We actually sold a fair amount of power into the New England ISO market. So, yes, we did serve -- continue to serve Ahlstrom's electrical load, but rather than committing our energy and taking the hit, if you will, to the energy price that you got in return for capacity payment, we elected to just participate on a merchant basis.

I think in some respects it turned out to be the right decision. The revenues that we earned through participation in the merchant market, given the spark spreads that existed in the fourth quarter, turned out to actually be a better deal than we would have achieved had we elected to take the lower auction prices, which were down in the CAD6 or CAD7 range than we got participating in the merchant market.

Okay, and then you have been discussing repowering that facility for a while. I just want to understand what the bottlenecks are in the discussions with Ahlstrom and what is preventing that decision from being made one way or another. Is it just confirming that you qualify for all the subsidies that you believe or are there issues with Ahlstrom that (multiple speakers)?

No, no. In fact, I was down meeting with the Managing Director of Ahlstrom a couple of weeks back. Ahlstrom is a big company. They are based in Europe and things just take time.

The other thing -- and I think it is just a practical issue. As everyone knows, the energy services agreement we have with Ahlstrom does continue for another seven or so years, and so we are really talking with them about issues that really don't kick in until 2017. While those are important for everyone, you can appreciate it is hard to get a lot of time and attention since it is not a burning issue from their perspective.

Having said that, we are pleased with the response from Ahlstrom. We are actively in discussions with them, and the project is continuing under active review. So certainly not dead. And I would hope by the end of this quarter -- for Q1 2011 -- we will be in a position to give you more definitive feedback at what we are going to do with that facility going forward.

Then just quickly, with that CAD12 million tax shelter that you got from the debt conversion, where does that put you in terms of where you see yourself being taxable?

That adds about six more months to our expected window. Right now based on existing taxable income we are expecting to continue to be tax-free through to at least the end of 2013, so this will add on approximately another, at least, six months to that.

Okay, great. That's all my questions. Thanks, guys.

Nelson Ng, RBC Capital Markets.

What is your expectation in terms of the run rate for admin costs? And do you think they will be generally seasonally higher in Q4 going forward?

Our admin costs did spike near the end of 2010. We had a number of corporate initiatives to restructure ourselves internally to -- although we have been operating for some time as two separate business units within our corporate structure, we actually had in a sense a single business unit. So we have now completely separated that, and that did add to our corporate admin costs in the fourth quarter.

On a go forward basis we were expecting our corporate admin costs to settle in at a number less than what we experienced in 2010, probably to the tune of 5% to 10% lower.

Okay, great. In terms of the -- I guess the Litchfield Park rate case settlement are you still looking to appeal the rate case decision or are you happy with it?

Well, you asked two questions. The answer isn't with the one you offered, which is, are we happy with it. No, I think we are -- we continue to be disappointed. I think we are not going to continue -- we are not going to appeal it. I think the reality of the situation is that the court -- that there is significant, I guess, latitude afforded to the commission in terms of making decisions. And I think the biggest disappoint we had in the hearing was the low ROE of 8% or so versus the 9.2%, which was recommended.

So I think our position is that we will not appeal it. I would point out, and I am sure you have all done the analysis, that 8% or so ROE is on an equity thickness of 80% equity, 20% debt. I think if you do the relatively simple math to map that against APUC's corporate structure, it translates into a 10.6 or so ROE on our corporate structure. And I am certainly not defending in any way that decision of the Arizona Corporation Commission. I think it is unacceptably low. It is out of precedent, and frankly, I don't think it reflects very well on the Arizona Corporation Commission and their determination. So it is what it is, but I think we're just going to have to live with it.

So, I guess more generally in terms of Liberty Water, will you be looking to file more rate cases like more frequently over the next several years, given that maybe it was partly due to like sticker shock in terms of the rate increase? So would you like in let's say two years' time would you try to file a rate case for a higher ROE?

Insightful comment. I think certainly sticker shock or rate shock is something we should always attempt to avoid. I think there was a little bit of the perfect storm that ended up with a rate increase for Litchfield Park coming in so high, including the global financial crisis, which knocked down growth rates from a housing perspective, the imposition of the EPA's arsenic treatment requirements which mandated substantial capital going into the business, some change in operating cost structures with chemicals and electricity prices.

All in all I totally agree with you that those things all came together at one time tend to having us go in for a much larger increase than we otherwise would have liked.

I think as our strategy for managing rate cases going forward is to try to go in more frequently, to try to make sure that we are not in front of the Commission asking for something which comes with a rate shock, which brings rate shock associated with it.

Just to put that in perspective, at Calpeco, our California utility, we are on a mandated three-year filing cycle. So absent something massively untoward happening from a capital or cost structure perspective, the rate increases in Calpeco are happening periodically, and therefore are somewhat muted. I think that practice is something that we are likely to export back to some of our Liberty Water utilities.

Just one more question. In terms of the Red Lily project, you mentioned that you expect to earn about CAD2.4 million in interest income and fees. I guess part of that relates to the construction cost management fees. So what is your expected operating management cost fees going forward?

That is frankly all net of the operating costs. Our interest in the project -- the return on our investment, if you want to think of it that way, has been structured as debt and fees. But that CAD2.4 million actually wouldn't include any of the operating costs. They were all, if you will, above that line.

So if you think about the net cash flows off the facility, some were being in about the CAD3 million range in nice round numbers. Our CAD2.4 million of the net after operating cost, cash flows and after debt service represents about 75% of that.

So just to clarify, so going forward like let's say in 2012, would you expect a similar level of about CAD2.4 million or 75%? Or I was just thinking whether that CAD2.4 million includes like management's like profit relating to the construction portion of the --?

No, no. You were correct with your statement. Think about it as our run rate interest in the project.

Okay, got it. Thanks.

Rupert Merer, National Bank Financial.

First of all, congratulations on your recent success with the wind development contract win. With respect to Amherst Island, I am just wondering if you could give some thoughts on the political environment in Ontario?

Of course, we have an election coming up, and the OPA recently put this moratorium on offshore developments. How do you think some of this might impact the project?

It is Chris Jarratt. I don't -- it is hard to speculate on what might happen. I think from our point of view the government has put some tons of money into this program. If it is doing anything like offshore, which has never been done before, it is very conventional. It is in an area where we have strong community support like -- I don't think -- it is always a risk, but I don't think it is something that we are expecting by any means.

It is Ian. I might also mention -- I don't know if everyone was able to note in the Globe today, the Ontario Supreme Court reaffirmed the Ontario government's right to establish those 550 meter setbacks. Which is, I think it is an important victory, if you will, for wind power going forward.

Right, oh, definitely. With regards to approvals and permits, can you discuss the work you need to do over the next 12 months before final submission of the Amherst budget?

Yes, there is a number of studies that need to be done. We have done some already. We did some back in 2008, primarily avian studies. We have to do some more. And we have to make a submission under the renewable energy approvals process. We expect to have that all in order, probably by summertime of this year.

Okay, very good. Thank you very much.

Juan Plessis, Canaccord Genuity.

Congratulations on your dividend increase.

It wasn't hard. They just decided.

Now with respect to the dividend, I know you give consideration to your free cash flow, GAAP earnings and prospects going forward. I wonder if you could talk a little bit about your dividend policy with respect to a targeted earnings payout range?

I think as we looked at the dividend issue, I think we are mindful of the fact that APUC currently is a business that participates in two pretty distinct business sectors, the IPP sector, as well as the regulated utility sector.

I think you are bang on when you -- if your comment was aimed at the observation that within the regulated utility sector payout of dividends, the primary metric against which those are measured, is GAAP earnings. I think that makes common sense given the pureness, if you will, of the Corporate Finance Proposition associated with regulated utilities.

On the IPP business, I think we are -- everyone in this sector would agree that there could be a potential mismatch between depreciation rates and economic useful life. So that perhaps GAAP earnings, which obviously includes full depreciation of assets over a period, may not actually be the most appropriate measure of cash off that facility.

So as our Board looks at the business, to the extent that we remain in both of those businesses, I think both those factors need to be considered. And as I said, of you look at our peer group, Emera and Fortis, who are in the regulated utility business, GAAP earnings are definitely a factor.

I think the mean, if you will, of that group is probably in about the 75% range for GAAP earnings, which doesn't seem unreasonable. And if you look at the independent peer group, obviously, the [Intergest's] and Northland's of this world, the appropriate metric tends to be cash available for distribution. And the mean tends to be a little bit higher, maybe in the 80% range.

So as our Board looks at it, I think they factor all of that in. And you will also point out, they include the prospects we have in front of us going forward. I don't know if that gives you the insight into how the Board thinks about this.

Yes, that is very helpful. Thank you. Now I can appreciate that you have your plate full with the pending acquisition of Granite State and EnergyNorth, but you can't always time when acquisition opportunities present themselves, so I'm wondering what your capacity might be for near-term acquisitions if the right ones come along?

Well, I think you have to look at -- again, I get back to the two businesses. I think our APCo Group, they really just finished off Red Lily and they are roaring to go on both getting their teeth into some of the developments we already have under way, and in fact, are looking at some continued acquisitions on the power side. So I don't think capacity is a challenge for us right now from APCo's perspective.

On the Liberty Utilities side there is no doubt about it, I think the first December and January and February were a very busy time getting the regulatory approval application completed for Granite State and EnergyNorth. We are pleased that it will be filed today, March 4.

So in some respects I think it is now over to awaiting to respond to the data request to come back. And I think that in some respects frees up a little bit of the capacity at the Liberty Utilities Group to focus on some of the other pots that are on the stove right now.

It certainly isn't that we are just going to sit on our hands until September when Granite State and EnergyNorth close. But I think if your observation was we have had our hands full for the past three months, you wouldn't be wrong.

Okay, thanks. Now, just finally, I noticed you have made some changes to the timing of the capital spending for the Bill C93 remedial work in Quebec, the capital deferred to later years. I am just wondering if you can give us a little color of what has changed there?

It is Chris. The end goal certainly hasn't changed. It is just the process of scheduling the construction and finalizing exactly what needs to be done. So we are just in a process -- it is primarily at two of our dams, and all the others are relatively minor. But it is really just a scheduling as things start to come into focus a little bit.

Okay, great. Thank you very much.

Tony Courtright, Scotia Capital.

Could you outline how you will be accounting for Liberty Electric, I guess, the Calpeco you own fractionally more than 50%?

We are working with our auditors on that right now. It is our intention and hope that we will get full consolidation treatment related to that acquisition, but it is still an open manner at the moment.

But I will note that regardless of whether it is equity accounted or full consolidated accounting for that, the actual, obviously, cash flows and net earnings will be identical.

Do you anticipate cash flows being able to be dispersed out of that or will you be reinvesting in ratebase growth?

There will be some free cash flows coming out of the utility, for sure. But our intention without a doubt is to grow ratebase for the utility. So we would expect to not only reinvest the, in essence, regulatory depreciation, but also look for opportunities to invest the free cash flow that is over and above the regulated depreciation rates.

Then turning to the reference to further in-scope acquisitions in Liberty Water or Liberty Electric, magnitude of these relative to something like New Hampshire, can you give color?

It is Ian speaking. I think at Liberty Water, and I don't mean to be dismissive at all, but that is a game of quite small bunts and singles, if you will. It is a very fragmented industry. And what we are hopeful to continue to add to ratebase it is likely going to be in quite bite-sized pieces.

So if I had to look for forward to 2011, I think we would be happy to add 10% to the CAD150 million worth of ratebase or so nice round numbers that might exist in Liberty Water now.

Liberty Energy is obviously quite a different animal. It is targeting of electric and gas utilities is much more meaningful in terms of the size of the opportunities that come our way. I think you would probably concur with the observation that Granite State and EnergyNorth, while being significant to us, are actually almost a rounding error to National Grid.

So as we look at other opportunities, and are out in the industry speaking to a kind of follow on our Feed the Orphans campaign that we had articulated at our Investor Day, they tend to be in the CAD100 million to CAD200 million range, those orphans, if you will.

I think the opportunity for significant move the meter growth from an asset perspective is likely to arise in the Liberty Energy subsidiary. I don't know if that is where your question was headed.

Well, then what -- you sort of said by the end of 2011 you expect to have a balance of EBITDA between -- maybe on a run rate basis between the IPP type business and the utility business.

Yes.

Beyond 2011 where do you -- if you're looking for more chunk-size acquisitions in utility, do you -- it might get ahead of where your IPP wind farm bill that gets to?

It could. I would also mention that reasonable IPP assets come -- even a small one comes CAD100 million out of the box as we -- Red Lily within the -- in the CAD70 million range. We have mentioned Amherst Island being in the CAD200 million range.

And so it is -- we obviously look at capital allocation based on the risk-adjusted returns from the sectors. I think we would probably say right now that acquisition of contacted assets will probably be a difficult one to go up against buying that next electric or gas distribution utility. On the other hand, the development of some of our wind projects is probably equally attractive.

So I am not so sure that -- they certainly shouldn't be interpreted as we are out of the IPP space. We like the business. It is where our D&A and roots are. We think we are reasonably good at it. But I think we do see the opportunity to continue to grow another business which we think we are reasonably good at, which is managing utilities.

So I think the opportunity does exist, at least in 2011, for Liberty Energy to catch up, if you will, to APCo, but I wouldn't look at that as being a forecast for where this business is going. That's it.

I appreciate it, thank you.

Matthew Akman, Macquarie.

I have a question on Calpeco and then just a couple of pick key questions on taxes and FX. So first on Calpeco, what are you seeing in the first little while of owning it? And can you just please update us on the timing of your rates filing?

Sure, we are pleased that the ski lift kept operating and the lights stayed on in Lake Tahoe on January 1. I would point out, and as things unfolded, they got the storm of the century on December 28, two days before we took it over. And so we were handed a thing where 10,000 customers were out of service on January 1.

The good news is crews continued doing the work, just as we expected them to do, with the support, as the agreements contemplated, from some of the Carson City and Reno crews of Nevada Energy, power got back on. The good news is, in accordance with demand, expenses, revenues kind of running according to plan. So that is good news.

We are only a few and a bit months into it, but customer service stats are the same, if not better, than [the] energy. We are out in the community touching them to communicate the new proposition, and I think it is working pretty well.

With respect to the rate case, we are on, as I mentioned earlier, I think in response to perhaps James' questions, or sorry, Nelson's question, we are on a mandated three-year cycle. That is the CPUC regulatory filing cycle. Our rate case will go in probably around August or so of this year. We have already met with the CPUC and the Department of Rate Care advocates on the rate case, and so it is already in advanced process.

It is something we started before. We knew before closing, and we are down there talking to them about cost allocation methodologies, and so it is proceeding.

Okay, thanks for that. On taxes, I guess this is for David, what -- not that earnings are the primary factor here, but we do have the obligation to try and estimate earnings, and taxes makes it tough. What can we expect for 2011?

For 2011 there is going to be two factors that enter into the tax. Obviously, it is going to be the continued utilization of the tax shelter that we stepped into during our Hydrogenics transaction. That amount is highlighted in the MD&A and so you can essentially expect a repeat of that in 2011.

The Liberty Water financing, obviously, created a one-time benefit from, as we described, changing the functional currency of the intercompany notes that we had between APUC and Liberty Water. So that is a one-time item that existed in 2011.

We are still working through the analysis to see if perhaps there is further opportunity for that, because clearly it creates helpful tax shelter for us. And we are always looking for opportunities to forestall that day that we have to actually start paying tax. But at this point in time we haven't reached a conclusion that there is anything further that we can do.

David, for purposes of modeling 2011, should we use a 0% GAAP tax rate?

I guess it is not for me to really say what people should model. But one way of looking at it is the marginal tax rate for corporations is approximately 27% and we get, I will say a [five-sixth] benefit from the corporatization conversion that we did in 2010. So you could actually look at it -- one way of looking at it would be one-sixth of whatever the marginal tax rate is you want to assume.

Okay, thanks for that. And on FX you give guidance on what a change in the exchange rate means for earnings, I think. I think you said something like CAD0.10 change in the C dollar/US dollar relationship is CAD4 million. Does that go forward also a cash impact or would the cash impact still be less?

No, that would be the cash impact. We are largely on a transactional basis, I will say, unhedged now because we have now opted for hedging ourselves on a translational basis and getting a permanent hedge by way of placing US dollar debt on our US dollar assets.

Okay, great, thanks guys. Those are all my questions.

Matt Gowing, Mackie Research Capital.

It is fantastic to see the dividend increase. And, Ian, I am very interested in your comments around some of your peers, both in the regulated space and the independent space, having payout ratios 70% and upwards. I am wondering if your comments should be interpreted that that is Algonquin's long-term target? And if so, what would the timing look like for Algonquin to get to that sort of level in line with peers?

It is an interesting question. I think as we look forward, I think one of the -- at what is right for our organization -- I draw back to Tony Courtright's comments about reinvestment opportunities in Calpeco and elsewise. I think the Board needs to consider those things as we look at our business. I think we have some strength of momentum in terms of the growth of our opportunities.

So I think the Board would be -- it is going to be cautious in terms of -- in terms of dramatically increasing the payout ratios. While I think everybody can do the math to say the Board would have the latitude to do that, the question is, is that the most effective thing for the organization going forward?

So I think we think of our value proposition with shareholders being -- as total shareholder return, which is our dividend plus capital appreciation, arising from an expectation of some measured and continued increase in those events that are reflective of some growth in our cash flows and solid earnings and our prospects.

So I wouldn't be -- from your perspective I don't think the Board is headed that they should be paying out whatever they can. I think there are great opportunities for this organization to redeploy capital in ways that those nickels will come back to us dressed like dimes.

So I think it is about being measured. I don't know if that answers your question, but I think there is greater latitude than what the Board has demonstrated, and I think they believe that is the right thing to do.

Well, that is helpful. Thanks for that. One last quick question on Windsor Locks. I noticed that the higher landed gas cost at Windsor Locks resulted in a CAD0.5 million operating expense increase. So previously you had talked about your cash flow guidance from Windsor Locks being at a CAD4.5 million annual run rate. I'm wondering if as a result of the higher gas costs we should be taking that down by about CAD0.5 million or so?

That is a hard one to forecast. I think the issue that we stare at going forward with Windsor Locks, and I guess it was a little bit in the context of, I think, James' question was that as we think about that forward reserve market and the decision not to participate in it, and while it was the right decision to participate in the merchant marketplace, I think that comes with that is a greater reliance on spark spread, therefore, making it difficult to make some accurate forecasts going forward.

I think it is difficult to be looking at that business and being able to rely on it from an earnings point of view the way we might have done previously under the old long-term contract. I think the moderation of gas prices in the New England ISO is largely driven by shale gas.

I think that is the reasonably expected to continue on though for the long haul. And given the general decoupling of prices, or the less coupling of prices in New England -- of electricity prices in the New England ISO, I think we are optimistic that we will have continued opportunities to positively exploit spark spread in the New England ISO.

I just don't want to go out on a limb and say -- gee, you should continue to put CAD4.5 million into your model, for the simple reason that is -- they are market-driven and it is the confluence of a couple of different commodity price curves.

Great. And one quick follow-up question. If you do make the investment into the 14.2 megawatt turbine annually what kind of step-up in cash flow could we expect from Windsor Locks?

Well, I think what we obviously are negotiating with Ahlstrom is to the extent that we are going to put more capital into the facility going forward to deal with this new turbine, which is largely there to provide more attractive or more optimized operation curve, and therefore heat rate performance to Ahlstrom, we are going to expect capacity payment.

You can do your own modeling in terms of what is a reasonable capacity payment to be obtained for putting -- it is going to be about CAD14 million net of those grants that we talked about into your model.

But we are going to proceed with it if Ahlstrom -- if it doesn't provide value to Ahlstrom going forward. The good news is we have had conversations with Ahlstrom. They are understanding of the issue going forward, and I think they are receptive to -- we are in discussions with them right now.

So I think we are optimistic that ultimately if the project goes ahead, we would be earning a reasonable return on that capacity -- on that capital investment through capacity payments.

Great, thanks very much.

Michael McGowan, BMO Capital Markets.

I just had a couple of questions about some of the wind developments you're working on. Red Lily, it looks like it turned into more of a debt investment initially than a pure equity the way you structured it. How are you thinking about investing in these assets as a pure equity investment or are you going to structure it somewhat similar to Red Lily?

It is Chris speaking. I think for the project that we are talking about now it would be a much more conventional structure. I will point out that Saskatchewan project we fully anticipate to convert that to an equity position, because we do have that option in five years. So that is the way we view that project as well.

Okay. It looks like some of your energy yields at these projects are pretty decent. I'm just wondering how long -- how much wind data do you have just to back up those predictions?

On Amherst Island we've got about three years right now. And so we have a pretty strong grasp of the wind resource there. You are correct that they are little higher than what we have seen elsewhere in the province, and I think that is a function of two things. One is it is an excellent wind resource. And two, you can see from our MD&A that we are proposing using some of the newer and larger more efficient wind turbines.

What about the Quebec facilities?

In the Quebec facilities we are proposing using the re-power equipment, because (multiple speakers).

ENERCON.

Sorry, the ENERCON equipment. And the capacity factors there are a little bit more in-line with what you have seen elsewhere.

Okay, and just in terms of the length of study?

That one I don't have off the top of my head, but I think it is -- we obviously would not proceed without sufficient wind, that is just not our style.

Yes, [bigger mass], we have been collecting actually wind data there since we bid it in and lost, frankly, to a couple of calls ago (multiple speakers).

That one we probably have, I would estimate at least five years of wind data.

Great. Okay, thanks. Those were my questions.

Sean Steuart, TD Newcrest.

A lot of my questions have been answered. Just one, Ian. You touched on the Saskatchewan request for qualifications for wind projects, and an expectation of 175 megawatts for the next RFP. Do you have any context on when you might expect that RFP to be formalized and rolled out?

Yes, in fact, I think right now the bids are due July of this year. So given the normal kind of utility evaluation period we would be ecstatic if before the end of the year results were announced, but I think probably Q1 '12 is a reasonable time to have an expectation. Obviously, when those bids come in we will be able to give you some more clarity on that.

Okay, that's all I have. Thanks, guys.

Nelson Ng, RBC Capital Markets.

So just one quick follow-up on the Amherst Island wind project. You mentioned that you will be investing in it conventionally, but will you be looking to partner with anyone, such as like First Nations, or let's say tax equity or an infrastructure investor?

On that project, no, I think we would be anticipating doing that entirely at Algonquin.

Then in terms of the, I guess, the tax pool that facility provides, would it be able to -- like does that project shelter the taxes in the US assets in any way through any kind of intercompany loans?

You are referring to Canadian wind assets, sheltering US?

Yes, actually.

No, the way our structure would work is that would -- that likely would not work in our tax structure. But we've got plenty of taxable income that comes up to Canada from the US. And, yes, from that point of view we will be able to utilize it here in Canada.

So I may have just most misunderstood the slant of your question. We can't send Canadian taxable income -- or Canadian tax shelter down to the US, but we can use Canadian tax shelter for income coming up from the US, if you know what I mean.

Yes. That is what I was kind of referring to, intercompany loans and things like that. That is all my questions. Thank you.

We have no further questions at this time. I will now turn the call back over for closing remarks.

Great, thanks very much. We would ask you to stay on the line for some information from Kelly Castledine.

Certain written and oral statements contained in this call are forward-looking within the meaning of certain securities laws, and reflect the views of Algonquin Power & Utilities Corp. with respect to future events based on assumptions relating to, among others, the performance of the Company's assets and the business, financial and regulatory climates in which it operates.

These forward-looking statements include, among others, statements with respect to the expected performance of the Company, its future plans and its dividends to shareholders.

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 financial results, the Annual Information Form, and most recent quarterly Management's Discussion and Analysis.

Given these risks, undue reliance should not be placed on forward-looking statements, which apply only as of their date. Except as required by law, the Company does not intend to update or revise any forward-looking statement, whether as a result of new information, future developments or otherwise.

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