Algonquin Power & Utilities Corp (AQN) 2010 Q1 法說會逐字稿

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Algonquin Power & Utilities Corp. Q1 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. (Operator instructions.) I would like to remind everyone that this conference call is being recorded today, Friday, May 7th, 2010 at ten a.m. Eastern Time.

I will now turn the conference over to Ian Robertson, Chief Executive Officer. Please go ahead, sir.

Thank you, and good morning, everyone. As mentioned, my name is Ian Robertson, and I'm the Chief Executive Officer of Algonquin Power & Utilities Corp. I'd like to welcome you this morning to our 2010 first quarter results conference call.

With me here in the room in Oakville today is David Bronicheski, our Chief Financial Officer, [Louisa Reed], our Controller, Kelly Castledine, our Manager of Investor Relations, and [Andrew Ingram], our Treasurer.

For your reference, the Q1 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, which 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 detail will be provided by Kelly at the end of this call.

We'd like to start with a few highlights in the quarter and provide some extrapolation to our views on 2010 more generally, outlining the expected impact of our committed value initiatives. Following that, our CFO, David Bronicheski, will talk about the financial results. And at the end of the call we'll have a question and answer period.

With respect to the first quarter of 2010 our results have not met Management's expectations. The results in the first quarter were affected primarily by two factors. Firstly, last quarter we discussed the unplanned outage at our Energy-from-Waste Facility and the earnings impact of this is now being felt. During this outage we will replace boiler and economizers [twos], some of which were scheduled for replacement in any event as part of the current year CapEx plan.

We will advance other capital maintenance originally scheduled for the second and third quarter to also be completed during this outage. Following this refurbishment the facility is expected to operate with a higher level of availability and lower operating costs, which will allow us to make-up for some of the lost cash flow and earnings in the second half of 2010. Nevertheless, with the return to service scheduled now for early July, the outage will continue to impact earnings through Q2.

The second challenge we faced in the quarter stemmed from lower than average wind resources, which by all reports have plagued many North American wind farms. From the APUC perspective we experienced a dramatic 25% increase in wind resources, a decrease, pardon me, in wind resources at our 99 megawatt St. Leon Wind Facility in Manitoba. While the good news is that April results indicated general return for us to average wind resources, the Q1 impact of the below average wind resource is evident in our results.

In summary, as we stated, this quarter's results have not met our expectations. While some of the factors leading to this performance are beyond our reasonable control, such as the St. Leon wind conditions, we offer this up by way of explanation and not by way of excuse. We remain committed to managing our businesses to deliver on our commitments, notwithstanding such underlying reliance on uncontrollable factors.

We'd like now to provide some broader comment about our 2010 expectations and intentions. As we have communicated, Algonquin Power & Utilities Corp. is an organization making the transition from an income trust to a growth focused Corporation. Coming into 2010 Algonquin Power & Utilities Corp. has set in motion a number of value creation initiatives, and these initiatives are still on track to deliver cash flow and earnings growth, with the lion's share beginning in the latter half of this year but with the full year impact of all initiatives hitting, as expected, in 2011. Therefore, we believe that Algonquin Power & Utilities Corp.'s overall value proposition should be viewed in the context of the full year 2011 impact of these initiatives.

I'd like to take a bit of time now to provide a quick update on six 2010 initiatives, which are either now or expected by the end of 2010 to be positively contributing to Algonquin Power & Utilities Corp. 2011 earnings and cash flow picture.

Firstly, our Liberty Water rate cases. As discussed in our MD&A, Liberty Water is continuing the pursuit of seven cases in Texas and Arizona. In this regard, we are pleased to have reached settlement at all three of our Texas based utilities, achieving all of the revenue growth that was expected. This will allow us to earn the expected return on the investments that we have made in that State.

We also have four rate cases underway in Arizona, where we have requested CAD16.9 million in additional revenue requirements, based on the investments we have already made in that State. These rate cases will be completed in 2010. We are working with our Arizona regulators to prioritize the rate cases in an effort to help address the shorthanded staff and heavy workload present within the Arizona Corporation Commission.

Secondly, our electric utility acquisition in partnership with Emera. This California electric utility acquisition by our wholly owned Subsidiary, Liberty Electric, is proceeding through the regulatory approval process before the California Public Utilities Commission. Based on the current regulatory procedural schedule, the closing of the transaction is expected to occur in the fourth quarter of 2010. With the completion of this transaction the additional EBITDA, our share of which is approximately CAD10 million, will bring the percentage of our 2011 consolidated EBITDA generated by regulated utilities to close to 40%.

Next, the recently announced commencement of construction of the Red Lily Phase I Wind Farm. The Red Lily Phase I Wind Farm is a 26.4 megawatt wind project in southeastern Saskatchewan. While the facility is owned by an independent investor, under the financing structure Algonquin Power Company, Algonquin Power & Utilities wholly owned power subsidiary, will provide CAD17.5 million of senior and subordinated debt to the project and provide development, construction, operation, and supervision fees to the facility.

APCo is anticipating fees and interest payments to provide approximately CAD3 million annually. We will have the option to take-up 75% of the equity in the facility after five years in exchange for our debt commitment to the project. With all the construction agreements now signed and activities underway, commissioning of the Red Lily Wind Project is expected in early Q1 2011.

Fourth, our Tinker Hydro acquisition. In January this year we expanded APCo's renewable power portfolio with the completion of the acquisition of 336.8 megawatts of hydroelectric generating assets in New Brunswick and Maine. This facility is expected to contribute EBITDA for approximately CAD6 million annually, which represents growth of more than 10% in our hydroelectric renewable energy business. As can be seen from our MD&A, the additional geographic diversification and above average hydrology from our new Maritime Region has helped to offset lower hydrology and production elsewhere in the portfolio.

Next, our nineteenth water utility acquisition. During the quarter Liberty Water completed the acquisition of its nineteenth water distribution and wastewater collection system located near Galveston, Texas. The system provides water distribution and wastewater collection to approximately 260 residential connections, and the operation and administration of this asset will capitalize on economies of scale from Liberty Water's Regional Office located in Tyler, Texas. The expected EBITDA contribution from this acquisition is expected to be approximately CAD450,000 annually.

And, lastly, achievement against our Windsor Locks Facility transition plan. As previously discussed, APCo is currently in the process of completing an operating model shift for our 54-megawatt Windsor Locks Facility, following expiration of the previous Connecticut Light & Power off take agreement. While the facility is continuing to meet the steam and electrical needs of its host under the existing 2017 expiration energy services agreement, we are pleased to announce that APCo was successful in bidding 28 megawatts of remaining available capacity into the 30-minute operating reserve market at a market clearing price of approximately CAD14 per kilowatt month, which deliveries commence in June.

In summary, we believe that 2010 is the consolidation year that brings together all of the value creation initiatives we started following our transition from an income trust to a growth oriented dividend paying corporation. We are now focused on earnings per share and GAAP earnings payout ratios rather than the cash available for distribution metric of an income trust.

Our stated commitment remains to provide total shareholder return, which includes capital appreciation through dividend growth supported by GAAP earnings. In this regard, while shifts in the timing of the materially sized Liberty Water rate case completion and Calpeco acquisition have made 2010 GAAP earnings guidance challenging. We are confident that the full year 2011 impact of our committed value creation initiatives remains on track to deliver 2011 earnings per share in line with our targeted dividend payout ratio of between 75% and 100%.

Now, I'll hand it over to David to speak about the financial results.

Thanks, Ian.

As we've disclosed in our quarterly results, revenue in Q1 2010 came in at CAD45.8 million, that compares to CAD43.4 million in Q4 of 2009 and CAD52.2 million in Q1 of 2009. Our adjusted EBITDA in the quarter was approximately CAD17.9 million and this compares to approximately CAD18 million in Q4 of 2009, and CAD21.1 million in Q1 of 2009.

Now, I'd like to touch on a few first quarter highlights from our operating subsidiaries, beginning with Algonquin Power Company. In our Renewable Energy Division, during the first quarter of 2010 net energy sales totaled CAD20.1 million and the Division generated electricity equal to 90% of long-term projected average wind and hydrology.

Most notably, our production at our St. Leon Wind Farm was 75% of long-term averages. The decrease in revenue compared to the same period last year is mainly a result of lower weighted average energy rates in the U.S., decreased average hydrology and wind resources compared to the same period last year, partially offset by increased average energy rates at our Canadian facilities.

For the first quarter of 2010 operating profit totaled CAD14.2 million as compared to CAD13.9 million during the same period in 2009. Overall, the renewable Energy Division did not meet our expectations due to lower than expected wind resources in the Manitoba Region.

In our Thermal Energy Division net energy sales revenue for the first quarter of 2010 totaled CAD8.1 million as compared to CAD8.7 million during the same period in 2009. The decrease is mainly due to decreased energy rates due, in part, to lower natural gas prices and a decreased demand for steam.

During the quarter production decreased by 1,000 megawatt hours at our Windsor Locks Facility and 2,000 megawatt hours at our EFW Facility. Throughput at the EFW Facility was 6,500 tons of waste, which was significantly less than the comparable quarter due to the unplanned outage in January.

For the first quarter of 2010 operating profit totaled CAD2.9 million as compared to CAD5.5 million during the same period a year ago. Overall, the Thermal Energy Division did not meet our expectations, primarily due to the unplanned outage at the Energy-from-Waste Facility and lower demand for steam from the Division's cogeneration assets resulting from the economic slowdown in the U.S.

Looking ahead to next quarter, our Renewable Energy Division is expected to perform at or below long-term averages in the second quarter of 2010 based on wind and hydrology conditions. In particular, as Ian noted, based on our April 2010 results wind conditions in Manitoba appear to be returning to more normal conditions.

The EFW Facility is expected to operate below expectations during the second quarter of 2010 as a result of the unplanned outage late in January. The outage will affect Q2 operating profit by approximately CAD900,000 compared to a year ago, but given the higher availability and productivity improvements we expect the full year impact of this outage is expected to negatively impact our operating profit from EFW by approximately CAD1.8 million compared to the same period a year ago.

We expect Sanger to operate at or above expectations during the second quarter, in line with performance from the same time last year. However, hydro mulch sales are expected to remain below expectations due to the slow-down of the U.S. economy.

During the second quarter of 2010 the Windsor Locks Facility did operate in line with 2009 results until the power purchase agreement with Connecticut Light & Power expired in April. Beginning in June 2010 we will sell 24 megawatts of electrical reserve capacity to ISO New England. In the interim, we will be selling between 10 and 40 megawatts of power into the grid based on hourly pricing forecasts.

The main power and steep contract to the local mill remains intact. We anticipate the full year operating profit at the Windsor Locks Facility for 2010 to be approximately U.S.4.5 million compared to historical cash flow of approximately US8 million. But as we make this transition to a forward reserved business model, Q2 being the first quarter we operate under this model, we will see lower operating profit of approximately CAD1.5 million compared to Q2 of a year ago.

Moving on to Liberty Water, revenue for the first quarter of 2010 totaled CAD7.9 million compared to CAD8.2 million during the same period in 2009. Water distribution revenue was lower due to a decrease in commercial water sales, but wastewater treatment revenue was up due to the implementation of rate increases at the Texas Silverleaf Facilities.

The wastewater treatment customer base grew by 0.9% and the water distribution customer base grew by 1.7% over the total customers at the same time in 2009. This increase is primarily due to the inclusion of customers from the acquisition of the utility assets in Galveston, Texas.

For the first quarter of 2010 operating profit totaled U.S.2.7 million compared to U.S.2.9 million in the same period a year ago. Overall, Liberty Water did meet our expectations for the quarter. During the quarter Liberty Water provided approximately 1 billion U.S. gallons of water to its customers and treated approximately 525 million gallons of wastewater, and sold approximately 30 million gallons of treated ethylene.

Looking ahead to the next quarter for Liberty Water, we do not expect any material change in the water or wastewater customer base during 2010. As Ian mentioned, we are proceeding through rate case processes at a number of facilities in both Arizona and Texas. Liberty Water anticipates that approximately CAD7 million of additional revenue from rate cases will be achieved in 2010 with the full annualized impact hitting in 2011. The full details on these rate case applications are contained on page 19 of our MD&A.

I'll now hand it back to Ian to wrap-up.

Thanks, David.

While the first quarter obviously presented challenges with respect to revenue decreases from the temporary shutdown of our Energy-from-Waste Facility and lower wind resources at our St. Leon Wind Facility, we are confident that both of these matters are being addressed. The EFW Plant will be returned to service in accordance with its schedule, and APCo's Renewable Energy Division results to date at least indicate a return to close to average wind conditions.

Nevertheless, to reiterate the broader perspective, we believe that 2010 is a value consolidation year for Algonquin Power & Utilities Corp. in completing our Corporate transition. Our stated commitment remains to provide total shareholder return, which includes capital appreciation through dividend growth supported by GAAP earnings. We are confident that our investors share the vision that the overall value proposition for our Company is considered in the context of the completion of our committed value initiatives.

In this regard, as we mentioned, while shifts from the timing of the completion of the materially sized Liberty Water rate cases and Calpeco acquisition have made 2010 GAAP earnings guidance challenging, as previously stated we remain confident that the full year 2011 impact of these committed value initiatives remain on track to deliver 2011 earnings per share in line with our targeted dividend payout ratio of between 75% and 100%.

With that, we'd like to open up the lines for questions.

(Operator instructions.)

Your first question today comes from Carolina Vargas with Clarus Securities. Please go ahead.

Good morning, everyone.

Good morning.

Two questions. I would like to know what kind of margins do you expect once it is completed, the upgrade from the Energy-from-Waste Facilities? It's obvious that this quarter was very weak, bringing down your gross margins I assume because of the overhead and everything else, so going forward once it's up and running in July what kind of margins, what kind of improvement can we expect?

We're going to be seeing a return to the margins that we've typically experienced in the past. I mean, in fact, with the productivity enhancements we are actually expecting perhaps even an increase in the margins because our expectation is our gas consumption will be less once we get through this refurbishment.

Okay, so [certain level] than historical margins for the facility?

Yes, and perhaps a slight improvement over what we've experienced historically.

Okay, and then on your rate base review status, I know you mentioned you have Texas done and are working on Arizona, but can you provide a little bit more detail? It's taking Arizona quite a bit of time to come-up with an outcome, so what makes you think that we will see this solved this year?

Sure. As you said, we are pleased that we have been able to complete, largely complete the process in Texas. The Arizona process obviously differs in its structure. I guess I would point out that the Arizona Corporation Commission, the regulator who is responsible for this is a body that obviously has a great deal of workload, and it's very difficult sometimes to predict how long it'll take to move a process through.

While the staff are continuing to work on our rate cases, I think predicting an actual date outcome is going to be difficult. I think we are confident that during 2010 we will resolve those rate cases. We have been working, frankly, with -- constructively with the regulator to attempt to prioritize those rate cases of the ones that are in front of the ACC so that the time which the regulator has can be focused on the ones that are most important to us.

So I think our -- the statement we're making is it will happen in 2010. I think it's just difficult to pin an actual date to it. I think we are comfortable and confident that, as we mentioned in our remarks, that the 2011 full year impact of these, that we'll be seeing that, as I mentioned, in 2011. I wish I could be more specific, but in some respects the process needs to unfold at the time that the process takes.

Okay. Thank you.

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

Hi, guys. I'm just looking at the debt facility that you're renegotiating right now. Do you have some sort of timeline that you expect to have that concluded?

We've started talking with our lenders now. I mean we expect that certainly over Q2, early Q3 we would expect to have that wrapped up. There's nothing that would indicate that there's any issues in that process.

Okay, and the terms, is there anything notably different from the current terms?

Well, the facility we have now was negotiated back in the context of January 2008, in the fall of 2007 even you could say, and so I think everybody is aware that the banking market has shifted substantially since that. I mean I think fortunately the worst of the affects on the banking sector kind of are behind us now, and so as we enter into these discussions, I mean we're pleased that there seems to be generally more of a balance in the negotiation process than what might have occurred say a year ago.

Right. And then the size would probably be about the same?

We're thinking about that right at the moment. I think, quite frankly, we have a facility right now that has an accordion feature that could go up to CAD225 million. We're -- as we go through this renewal I think our view is we likely don't need a facility quite that large, that a relatively short-term bank facility isn't necessarily the best way to be financing the capital structure. So we're going to be looking to place longer term debt, and so kind of reduce the reliance that we have on a relatively short-term bank credit facility.

Okay, and then with the Sangor Facility, is there any update on the marketing of the additional capacity there?

It's obviously continuing on. I think, in short, I don't think we have any specific update for you at this time. I think to the extent that we're able to conclude either a bilateral or an extended agreement with PG&E we'd certainly announce it. But our discussions are ongoing.

Okay, for the closing of the Calpeco acquisition there, the partnership, you said it's going to be in Q4, is that early or late? I'm just trying to get an idea of whether I should be modeling that full quarter?

Well, the procedural schedule I think calls for a final order, I want to say November, I'll make it the 10th, I think it is. It might be a day or two before or after that. And so we would obviously hope to close promptly following the receipt of that final order.

Okay. Okay, that's great. And then you were just saying to Carolina's question there, that you're prioritizing your rate cases with the Arizona utility there. So would it be safe to say that the [Litsco] assets would be the first thing to be announced? Or the next thing to be announced?

Yes, certainly in attempting to be sensitive to the workload that the regulator is under, we have been looking at prioritizing those. And you're absolutely correct, the Litsco rate case obviously is the one that has the most material impact on our results and the one to which we have, we are working with the regulator to try to put at the front of the line, if you will.

Okay. Okay, thanks, guys. That's all my questions.

Thanks.

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

Good morning, everyone.

Good morning.

Good morning.

I was looking at the EFW Facility. How much of your estimated CAD8 million in CapEx have you spent so far?

We spent CAD3.9 million in the quarter.

Okay, great. And when would you expect to have some direction on the possible expansion of that facility that you were discussing in your release?

Well, we're continuing our discussions with the [Region of Peale]. Obviously, in the context of their refurbishment of the facility I think probably to be frank the refurbishment of, you know, this unplanned outage and the refurbishment of the facility kind of has pushed those discussions a little bit to the rear of the agenda. And, obviously, the region understandably is quite focused on our efforts and plans to get the facility back in service. Certainly we haven't heard anything from the region that leads us to believe they are heading in a different direction, but I don't think this quarter has been one in which given the focus of returning it to service we have really prioritized the expansion discussions.

Okay, great. And then turning to a couple of other potential areas for growth. Can you comment on potential for any additional acquisitions this year? If we look at BC and Ontario there seem to be a number of small independent power producers who've won contracts recently and maybe they are going to be in need of some capital for developing those projects. Do you have an active pipeline in this area? And do you think we could see more acquisitions or investments this year?

Well, I think that's definitely a great opportunity that we are hoping to exploit. I think winning a PPA is frankly just the first step in bringing a project through to fruition, and obviously the capital requirements are substantial for these types of projects. We are hoping that our access to capital and frankly our history as being an independent power developer will bring value to some of those developers who have been able to receive the PPAs.

I guess the last thing that I'd obviously mention is while we're certainly, the door is open and we are carrying on conversations with a number of those parties we obviously have our own pipeline of projects within the [Fed] Program and elsewhere in Canada that we are definitely chasing. So I think we are actively active in this business. We don't necessarily only need to develop projects to which we've given birth. We're happy to partner up with other people. And so, yes, to all of that. Rupert, I don't know if that answers your question?

Yes, it does. And looking at the Ontario [Fed], you have the Loyalist Project on the ECT, do you have any color on when transmission capacity might become available to that area?

Well, actually, I don't think frankly that the big issue with that project is necessarily transmission capacity. It is -- it really revolves around the upgrade of a relatively short line between our facility and the substation. So the good news is that I don't think that we're looking for sort of major transmission [backhaul] reinforcements to make that project a reality. As you know, the ECT work is expected to at least have some announcements from the Government in this summer. But I think we are optimistic that the work that's necessary to allow ours to proceed is actually reasonably small in quantum and in scope, and so consequently we are optimistic about hearing something positive.

I guess, to be frank, I guess I would say that we are right on the edge of whether we would, if you will, kick the box to take those costs or not. We elected not to just because we were a little bit concerned about the challenge to the economics of kicking that box. But again the fact that I would say that should give you some comfort that what needs to get done is not a major transmission upgrade to allow that project to proceed.

Right. Okay, great. Thank you very much.

Your next question comes from John Safrance with Fraser Mackenzie. Please go ahead.

Hi. I'm just looking for a little bit more color on some of the RFPs. In terms of your Red Lily Phase II submission with Fast Power, how long do you think the termination on their end will take? And when do you expect to hear back on that front?

Thanks, John. I'd like to turn that question over to Jeff Norman, who is our Vice President of Project Development. And maybe he can provide a little bit more color. Jeff?

Great. Thank you, Ian.

The project, the request for qualifications, as you know, was in Q1 and that's been submitted. And we're expecting feedback on that and an announcement from the Province on when the RFP process will be undertaken. But we expect all of those to take place in this fiscal year.

Okay, perfect. And just in terms of the upcoming Hydro Quebec process, I guess May, May 19th, are you anticipating -- because you do mention in your MD&A that you're looking at at least probably one 25-megawatt project, and then maybe a couple others. So is it possible then to say that you're looking at a total of about 75 megawatts bid into that process?

Yes, we have three active projects and the date has been pushed back from May 19th to July 9th, but you're correct on the [quantum].

Okay, and just kind of shifting a little bit in terms of your energy business services, can you maybe give us a little bit more detail in terms of if you were to net that out what the revenue and op cost line would look like?

Well, I mean I guess right now I think the way we're looking at it is that the energy services business is there to provide an uptick over the otherwise available options for selling our energy, which you might argue is the [NEISO], and you, too, should know but probably Keswick is a good one.

I think the intent is that at least in the first instance that group will in effect pay for themselves. And so that the cost of running that group will be recouped in the additional margin that they generate by perhaps managing the off take of our off contract hydroelectric assets in a more sophisticated manner than we've done historically.

So I don't think at least in 2010 we're forecasting that there'll be a major contributor to net EBITDA over and above what we would otherwise have forecast. I think going forward, though, it's very much our intention and expectation that that group be tasked with expanding their services beyond just the Tinker, and [Caribou], and [Squaw Pan] assets to the balance of our portfolio of primarily New England hydroelectric assets which are off contract.

At which point in time since there won't be any additional costs associated with that we would expect some net EBITDA contributions over and above forecast. I think it'll probably be our intention as we start to see how that business develops to give some guidance for that probably later in Q4.

Okay, and just on some more financial side questions. In Q2 then it's safe to assume then that we should just model zero in terms of electricity sales and waste processing for the Energy-from-Waste Facility?

Certainly in Q2. I think the schedule has the plant commencing or recommencing operations the first week in July, so Q2 the plant will still be on outage.

Okay, and in terms of operating costs while it's being repaired, what are we looking at for Q2?

Well, in general, obviously we're capitalizing most of those costs to our construction cost because pretty much all of the activities at that plant are really very much focused on that re-commissioning or refurbishment process.

Okay, so in terms of salaries and so forth with employees, that -- is that being capitalized, as well, or will that show-up as an operating cost?

Well, you may be aware that unfortunately we had to lay-off a fair number of the workers at the plant who were responsible for the typical operations. And so those costs have at least been put out to the side. The management and other forces that are continuing to function at the facility are being capitalized in the refurbishment cost since that's where their activities are totally being focused.

Okay, perfect. And in terms of the -- I mean I guess once all your rate cases on the Liberty Water side are settled and you're looking at 2011, it looks like roughly kind of over 2009 levels you're going to see a bump in revenue of about CAD18 million or so. How much of that do you see flowing to the EBITDA? Because I do know that you obviously are a little bit skinny on the personnel side, so I'm just wondering if you back out the additional hiring and so forth what that was?

Well, let me start by saying obviously while we're pleased with the outcome of our Texas rate cases, the outcome of the Arizona rate cases is I don't want to say it's anyone's guess, while I think we're totally entitled to everything that we've asked for we acknowledge that the outcome is a regulatory process, and we'll have to see how it comes out.

I don't think we are actually anticipating, so having said that, I don't think we are actually anticipating that there would be any major grind to those costs over and above the cost that you currently see in Liberty Water to the -- on the resolution of those rate cases. We are providing service to all the customers to whom the rate cases apply. It's not like we have additional costs frankly that aren't being, haven't been proposed to be recovered.

And so I think, in summary, we're hoping that pretty much every dollar flows directly at least to the EBITDA line, and then obviously it has to then flow through the income statement and taxes. But that top line revenue number shouldn't have much reduction for any increased costs.

Okay, and just one final question, you get it every quarter, but in terms of Windsor Locks, the repowering, are you any closer to a decision there or is that still being determined?

Yes, absolutely. But I think we are pleased that we -- that the transition plan, which includes running that facility as -- in the forward reserve market is -- we were successful in bidding the capacity into the -- into that marketplace, and it's about CAD14 a kilowatt month that we've received. The repowering work is continuing on. As you know, we have that grant that's available to us to help offset the cost of that.

And sort of much like in the same way as we would chase our Red Lily, when we chased that Red Lily Project, I don't think it's our intention to sort of announce anything until we've pretty much got everything locked up from a contractual perspective. And so obviously it's on the books, we're working on it, but I don't think we have anything more to say about it other than, as I said, the announcement about our success in the forward reserve market.

Okay, and I know I'm hogging the puck here, so just one last question. In terms of the power asset acquisition you made in mid-January in the northeast, the 40 megawatts of thermal assets, how much did that contribute to the top line in the quarter?

Actually, in short, not all that much. It wasn't ever really intended to. Those thermal assets are there to provide capacity backup to support the sales of the power off our hydroelectric asset in case of outages or other capacity needs. The good news is they didn't have to operate, and so consequently we obviously didn't experience any significant operating costs. And so, in short, I wouldn't say they contributed very much but they didn't cost us anything either. They were there and really provide capacity backup.

Okay, fair enough. Thanks very much.

Your next question comes from Tony Courtwright with Scotia Capital. Please go ahead.

Thanks very much. Perhaps I'm not quick on the uptake today, but I have had difficulty discerning what is the contribution from the Tinker and the energy services business, the revenue, the costs, and the ultimate contribution to the segment. Could you walk me through that?

Sure. And we do provide disclosure. I could probably refer you to, I believe it's page, around page 10 in our MD&A. And I think it's important to understand that we don't really distinguish between the two, because the primary purpose of the energy services business really is to sell the power from the Tinker acquisition.

And so as we look at the results that happened in Q1 we had, as we disclosed, CAD5.5 million of revenue, CAD2.8 million of operating expenses, so we had an operating profit of CAD2.7 million. And included in that CAD2.8 million operating expense was CAD2.1 million of energy purchases.

All right. I mean I think I discerned that, but it -- I was surprised that there wasn't more reference to Tinker in terms of your results. Without Tinker your results would have been abominable in the sector.

Well, without Tinker we wouldn't have operating profit of approximately CAD2.7 million.

Yes, which would -- is a material amount in relation to the sector in the quarter.

Yes, we had, as we noted, St. Leon was significantly below long-term averages of production, so you're right. When you look at the combined portfolio of renewables, sure. We're happy to have the Tinker asset there because it certainly did help with -- offset some of the other dips.

Now, you also have written that you anticipate, and maybe it's the granularity as a full year, that Tinker might satisfy 80% of your delivery commitments in the energy business service segment, yet in Q1 it was less than 50% or around there?

I'm not sure I follow the question, Tony?

Well, there is a statement saying that you expect to be able to deliver 80% of your load from self-generated sources.

Correct.

And you purchased 38.6 gigawatt hours but yet generated only 31.4 gigawatt hours, suggesting that at least in Q1 it didn't come anywhere near the 80%.

Well, I guess we -- that 80% number is certainly based on the comparison of the load consumption profile against the generation profile. I guess we -- certainly, I don't think we ever did that analysis to say was the generation I guess the load profile sort of consistent with that expected 80%.

I mean thank you for bringing that up. I mean we'll certainly run that one to ground, but I don't think -- I think in general nothing leapt out at us in terms of the operation of the Tinker Facility or the operation of the [EAS] business that led us to the conclusion that something was significantly out of whack that over the annual basis that that self-generation issue accurately pointed -- wouldn't account for about 80% of our total load that we satisfy.

Granted, I mean there could be seasonality in terms of your Tinker production?

And load being satisfied.

All right. Okay.

That it is a winter peaking system in that part of the country and so the demand in the -- from the load also have to be, if you will, stood up against the generation profile. The generation profile is generally lower in the winter months due to obviously the fact that there's ice and snow rather than rain. And, but the generation of it, the load demand is obviously high. Your back-of-the-napkin calculation of that we only generated 50% of what we served might well be correct, but it might well be appropriate in the context of that 80%. And I'll just have to run those numbers, Tony.

Okay, thanks. In terms of Windsor Locks and the 10-minute operating reserve, you mentioned that you have secured a contract for the summer. What happens when you get called away and asked to dispatch under the 10-minute operating reserve? What, do you get paid for your output, and is that enough to cover your costs?

Hi, Tony. It's Jeff Norman. So when we get called we actually are more than recovering our cost. We would be called when the prices are very high, and typically get called when the equivalent heat rate is above 14,000. So we expect to more than be compensated for our costs when we're called upon.

So, and you have adequate capacity of gas delivery and adequate call on the delivery to light-up your turbine?

We do.

Okay.

And I guess I just would mention, Tony, just from the operating regime, that turbine is actually already running as you know to both satisfy the steam and electrical needs of the [Alstom Mill]. And while your question is a good one, that make sure that our gas contract gives us that additional capacity to open the gas valve, just to be clear, it's not a matter of starting the unit up, it's a matter of cranking it up from its current level to its full output.

All right. Just as a Corporate question, you in the past have mentioned potentially considering a drip. What is your thinking and timing on that?

Yes, we expect to have that rolled out in Q2. We're just finalizing the paperwork, actually, on it now. So I think you'd expect to see that over the next six to eight weeks.

Fine. Those are my questions. Thanks.

Thanks, Tony.

Your next question comes from Bob Hastings with Canaccord. Please go ahead.

Thank you. Just to finish-up on the Tinker comments earlier, is the - you've reported CAD2.7 million of I guess EBITDA in the quarter, operating income in the quarter. And your expectations are CAD6 million annually. So I gather there's a little seasonality or is this year doing a little better, or can you give some color?

Well, no doubt about it, the facility did do a little better than expected, but, yes, to the other part of your question in a manner similar to all of our other facilities there is a fair amount of seasonality associated with the hydroelectric operating profile. Obviously, most notably in the summer and early fall tends to be a relatively low flow period, whereas the spring and later fall tends to have a spring and fall [fresh ed] associated with it.

All right. Okay, so then there's no reason to start tinkering with that -- sorry, (inaudible) there -- for changing the CAD6 million expectation for the year at this point?

No, I think we're obviously in the context of the normal hydrologic variability, we're still confident and comfortable with that guidance.

Oh, but you're a little bit ahead in the quarter then?

Yes, and that's good and, you know, and hopefully as we look forward to the rest of the year we'll stay that way, but so I think your answer, Bob, is should you be thinking about from a modeling perspective doing something different. And I don't think we have enough of an operating history to say that there's some paradigm shift that's gone on that would lead us to some other long-term conclusion.

Okay, the Energy-from-Waste, the numbers were a little conflicting. On page six it says that the quarter was impacted by CAD900,000 and for the year you expected CAD1.8 million, and you reiterated that in the call. But on page 12 it says CAD700,000 in the quarter and CAD1.5 million for the year. So I'm assuming the CAD1.8 million is the right number.

Yes, the CAD1.8 million is the right number, Bob. You're quite right, it was -- the latter numbers you were referring to were typographical.

Okay, and on page 11 the table there basically doesn't add-up. The numbers are all right down to the total net revenue of [9174], when you subtract out the other two numbers you get to 3.052, and it's showing 2.852. so I just wanted to make sure I know what is the right number on that. It's only CAD200,000 I know, but?

No, it's -- the correct number is 3.052.

Okay. Thank you, that makes my numbers work out better in my tables. And looking at your new wind operation at Red Lily, I know you're going to get some construction supervision fees and, of course, some interest. Are there any expenses against the construction fees? I mean is it right to look at that as being an EBITDA kind of number? Or is there something that's going to be some natural expenses that will have to come out of that?

Those services are generally performed by all of the staff that we currently have baked into our operating overhead, so I think from a modeling perspective it's probably fair for you to pretty much include it all. I mean obviously we'll have incremental travel cost and that sort of stuff, but it's not like we have to hire a major contingent of new people.

Okay. Thank you very much for that. And on Liberty Water, the -- clearly we're still waiting to see, and who can ever guess what the numbers will be, but as you're going through the process and judging how you did in Texas, are you more confident or where do you think you stand now?

Well, first of all, I'd start by saying it is a different process, as you know, Bob, between Texas and Arizona. The -- in Arizona we are still awaiting ultimately the recommended order from the judge. I don't think we have either become more or less optimistic, if you want to think of it that way. We obviously believe that we're entitled to every dollar that we have asked for or we wouldn't have asked for it if we didn't think our costs and return on our investment justifies that.

Having said that, we kind of acknowledge that there can be a debate on things like return on capital or rates of return. I think the recommendations that have been made by staff perhaps, you know, aren't crazy. There's -- obviously, the judge has to make a decision. I think a fair number of them have been in this 9% to 9.5% ROEs. We'll have to, obviously, we think our [Cap M] model supports a higher ROE, but it'll be up to the judge to decide.

I think I would like to think that the primary bid out spread, if you want to think of it that way, in this process would arise from rates of return rather than from some dispute on investment or costs. I mean, hopefully, those are pretty objective, so at the end of the day you can make your own estimate, but I think that's really primarily where, as I said, the bid out spread rests.

Yes, so I guess I was suggesting you're already through the hearing and so you know what the big hot spots were or the hot points were, and really it seems to be around the ROE?

It is that very much so.

It's normal.

Yes, everything else, you know, it's on the margin, let's put it that way.

Okay. Thank you. And just sort of the big general wrap-up sort of question, you mentioned the -- 2010 was challenging to meet the guidance. Can you remind us what your guidance, what guidance you were referring to and if you have any sort of new updated guidance having seen the first quarter?

No, I think what we meant -- mean by that is we've made obviously a statement, we've made it publicly that as we think about this business over the longer term we think about appropriate payout ratio for utilities and power business in the 75% to 100% of our GAAP earnings, you obviously know where our dividends are right now, so I think you can kind of reasonably back into where our expectation is for the current, what the current value proposition and I mean all the existing committed initiatives are likely to deliver.

I think the issue that we're raising for you and the rest of the capital markets is -- are the things that we've talked about today, the timing of those rate cases are material, the timing of completion of the Calpeco acquisition, that got pushed back and it got pushed back for good regulatory reasons but the fact of the matter is there may be major contributors to our value equation.

And so I think what we're really saying is that we really are comfortable that 2011 will reflect the inherent value of the businesses that we're undertaking. But it's very hard in 2010 to say exactly, "Gee, Bob, you should model that we'll get those rate cases all done on August 8th, or is it going to be September 8th, or is it going to be October 8th, or is it going to be July 8th."

And that's the challenge that I think we -- and we're sensitive that you guys are faced with, and that's why we're trying to, if you will, just step a little bit above that because what we don't want to be doing is making predictions about things that are really frankly beyond our control, and the process that I'm speaking of is the regulatory one, that we're trying to work through and be supportive of the regulators in.

All right. Okay. Thank you. So to maybe look at this a little more broadly then, if I were to look at your current equity position and say you got a 10% return on equity, which would be not too far away from a regulated perspective, maybe certainly low on all the new stuff you're doing, and saying that's sort of the goal from where you are today without investing any new capital in these projects, it'd give me about just over CAD0.40 per share in earnings, and that roughly lines up with when you announced the start of this transition, earnings around CAD0.40. And I remember doing that call when you announced the change that that's where you thought earnings were.

So yet when I look out to 2011 sort of guidance, if I say 75% to 100% on the CAD0.24 it gives me a CAD0.24 to CAD0.32 spread, and I'm just wondering if you're seeing still some challenges next year?

No, I think though to be fair when we look at the CAD0.40 that we had, that we talked about at the time when we had that call, I think it is important to keep in mind that there's a fair amount of noise in those kinds of earnings that comes from GAAP figures such as the tax issue. And while those are sort of real things that need to be addressed in the context of the -- of preparing GAAP financial statement, I think really we look at it as on a more typical adjusted earnings basis where should this -- where do we think our -- the current value initiatives will bring this Company in line.

I think it is fair to say that the CAD0.24 to CAD0.32 is probably a realistic expectation in that we shouldn't get confused by some of the impacts that the changes to the way the CICA suggests that we need to look at some of these factors are. So I mean I think -- I don't think it's fundamentally changed our expectations of the business, but we're just trying to give you some ideas as to our thoughts as we run our own models and look at these without affect of some of these extraordinary items.

Okay, and then obviously with the new projects your hurdle rates are going to be generating higher than 10% returns on equity I assume?

Well, certainly we're not going to do anything unless it's accretive. I mean that is the bottom line commitment that this organization is focused on.

Can you remind us what your hurdle rates are for the project?

Well, I mean they're obviously different for different projects and different generation, but I think as we've said in the past we probably wouldn't want to undertake, for instance, a wind project that didn't have and we'll look at it on an unlevered IRR basis, of something north of 9% to 10%. And you can figure what that would translate to an equity IRR perspective, but --

And that's fully taxed?

Yes, obviously, and the nice thing about that for a wind project is the difference between pretax and post-taxes is actually pretty minimal given the accelerated tax depreciation that's afforded to these types of projects.

Okay. Thank you very much.

Thanks, Bob.

Your next question comes from Matthew Akman with Macquarie Capital. Please go ahead.

Thank you. On water utility, what was the impact in the quarter, was it -- of the settlements in Texas? Was it just CAD0.1 million?

Those rates, I believe we note that in the table, the way it works in Texas is you actually are able to implement your rates at the time that you file the application. So in our table we actually outline when those rates went into effect. And so when we do reach a final settlement, like there is no bump per se because those rates are already in effect. Like there might be, given the timing, I guess when you look to what it was a year ago in the quarter, yes, there'd be an increase. But in the table we highlight when we put those rates into effect.

Yes, you've already been booking rates at this level, right?

That's correct.

So there's no real -- okay, thanks. And I just had a -- that's all the questions, though, I just had a comment. I cover companies that are 20 times the size of Algonquin and calls take half the time, and I'm not blaming it on you guys but you may have to put a limit on the amount of questions analysts ask because there's a lot going on out there. Thank you. Those are all my questions.

Thanks.

Your next question comes from Matt Gowing with Mackie Research Capital.

Good morning, and thanks for taking my questions. I'm -- actually, my questions have been answered, but thanks anyways.

Okay. Thanks.

Your next question comes from Michael McGowan with BMO Capital Markets. Please go ahead.

Good morning. Now most of my questions have been asked, as well, but I was just wondering your utility segment, on the -- in your local currency basis, results there are actually down quarter-over-quarter, as well. Is there anything that's affecting that? Are you seeing cost pressures across the board or really what was responsible?

No, I mean on the margin, you could imagine that revenues fluctuate up and down by local consumptive patterns which can be influenced by weather and other factors. There obviously haven't been major rate changes or cost pressures that have caused that. I think it's really just generated by local -- the consumptive patterns of our rate, of our customers.

Okay, so no material change in the number of customers, just people are maybe using a little less water?

Sure. You can imagine people are not going to turn on their sprinklers to water their lawn in Arizona when it's raining, it just doesn't happen. So consequently we lose volumetrically because some of our profit is tied to delivery of volumes. And consequently when it's hot and dry we make a little bit more. The intent obviously is it's supposed to be on the margin that it does that. I think our general conclusion was that Liberty Water pretty much performed in accordance with expectations subject to that variability.

Okay, great. Thank you.

Thanks.

(Operator instructions.)

We have no further questions at this time. please continue.

Thanks, everyone, for joining us this morning. Obviously, we'd like to -- everyone remain on the line for a review with respect to our disclaimer.

Certain written and oral statements contained in this information 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 climate in which it operates.

These forward-looking statements include, among others, statements with respect to the expected performance of the Company, its future plans, and its dividends to shareholders. Statements containing expressions, such as, "believes, anticipates, expects, may, will, project," and similar expressions generally constitute forward-looking statements.

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 although we believe our assumptions are reasonable in the circumstances these risks and uncertainties give rise to the possibility that our actual results may differ materially from the expectations set out in the forward-looking statements.

Material risk factors include the continued volatility of world financial markets, the impact of movement in the exchange rates and interest rates, the effective changes I environmental and other laws and regulatory policy applicable to the energy and utilities sectors, decisions taken by regulators on monetary policy and taxation, and the state of the Canadian and the U.S. economy and accompanying business climate.

We caution that this list is not exhaustive and other factors could adversely affect our results. Given these risks, undue reliance should not be placed on forward-looking statements which apply only as of their dates. 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. You may now disconnect your lines.