Algonquin Power & Utilities Corp (AQN) 2012 Q1 法說會逐字稿

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Q1 2012 Algonquin Power & Utilities Corporation analyst call. At this time all participants are in a listen-only mode. Following the presentation we will conduct a question-and-answer session. Instructions will be provided at that time for you to queue up for questions. (Operator Instructions). I would like to remind everyone that this conference call is being recorded today May 11, 2012 at 10 a.m. Eastern time.

I will now turn the conference over to Kelly Castledine. Please go ahead.

Good morning, everyone. I would like to welcome you to the call this morning to discuss our first-quarter 2012 results. With me today are Ian Robertson, our Chief Executive Officer, and David Bronicheski, our Chief Financial Officer.

For your reference, additional information on our Q1 2012 financial results is available for download from the top link section of our home page on our website at Algonquin Power & Utilities.com.

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

As an agenda for today's call, Ian will start with a discussion regarding a few of the highlights in the quarter. Following that, David will review the financial results and then Ian will provide updates on some of our growth opportunities.

At the end of the call we will host a question-and-answer period. I ask that you limit your initial questions to two and then requeue for any additional questions in order to allow for the opportunity for others to participate.

I will now hand it over to Ian.

Thanks, Kelly, and good morning everyone and thanks for taking the time to join us on our call today.

I would like to start with a focus on some of the highlights that occurred during the quarter before I turn things over to David. As you all will have seen from our press release last night, Emera and Algonquin have moved ahead with the principles established in our strategic investment agreement announced last April by way of a further commitment by Emera for CAD105 million equity investment in Algonquin Power & Utilities Corporation or APUC as we affectionately call it.

This investment has been structured into a number of tranches timed and sized to correspond with the closing of the major committed growth initiatives we have in front of us. We would note that the pricing of this investment continues the tradition of Emera pricing its investment in APUC at a premium to the current market.

This equity commitment has materially positive implications in the context of our committed growth initiatives. I trust that our investors will conclude that with this forward equity investment commitment in hand the equity needs for our utility and power investments are now largely addressed.

With the funding considerations largely addressed, I would like to highlight some of the significant events of the quarter surrounding these growth initiatives. Firstly on the utility side of our business, we are extremely pleased that our previously announced growth investments are nearing completion.

In New Hampshire, a unanimous settlement agreement was reached with all parties to the approval process and to the extent any of them are listening in today, I did want to thank all for their constructive efforts to making Liberty Utilities entrance to the state of New Hampshire a successful one. We are currently awaiting the final order from the commission and we anticipate closing this acquisition within 60 days or so.

A similar situation exists with respect to our Mid-States utility acquisition. Approvals are in hand for Missouri and Iowa and a favorable administrative law judge decision was issued in Illinois pending ratification of that Illinois proposed decision by the Illinois Corporation Commission. Closing of this acquisition is expected in late July.

Lastly, our first general rate case for our California electric utility was filed during the quarter and if approved as filed would provide an EBITDA increase of approximately CAD7.7 million.

Perhaps as importantly against the backdrop of the dramatically warmer winter this year which is obviously fresh in our minds, this rate case includes a request for a mechanism to decouple our earnings from delivered energy volumes which as expected fluctuate based on weather.

Lastly, we were pleased that the California Commission approved our vegetation management account which will allow us to seek recovery of continued investment this year in vegetation control costs in advance of the completion of the current rate case.

On the power side of our business, we were pleased to announce during the quarter a commitment by APCo to acquire a majority interest in a 480-megawatt portfolio four wind projects in the United States from Gamesa. APCo, Algonquin Power Company, our independent power division, will acquire a 51% controlling ownership interest in these projects which are located in Illinois, Texas, Iowa and Pennsylvania. This collection of projects sells this energy pursuant to long-term fixed-price power sales contracts with a weighted average life of approximately 12 years and resulting in 73% of energy revenues to be earned under these contracts.

As we advised at the time of this announcement, our obligation to acquire any of these projects arises following the successful completion. With the commissioning and closing checklist being addressed, we would anticipate closing for the first two of the projects late this quarter or early next and the remaining projects in early 2013.

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

Thanks, Ian, and good morning everybody. Now I would like to discuss our Q1 2012 results.

There are really two things that affected our results in the quarter. First, a warm and relatively short winter in Lake Tahoe reduced electricity demand by just over 15% affecting the results at our Liberty Utilities West. Second, lower power prices and lower electricity demand in the northeast affected our power sales at our Windsor Locks facility.

So in all, revenue in the quarter came in at CAD64.4 million as compared to CAD71.7 million a year ago. Our adjusted EBITDA was CAD23.3 million compared to CAD26.9 million last year and our adjusted net earnings came in at CAD5.5 million compared to CAD5.3 million last year.

So now I would like to go into just a little bit more detail in our operating subsidiaries beginning first with Algonquin Power Company or APCo.

In our renewable energy division during the first quarter of 2012, net energy sales totaled CAD21 million as compared to CAD20.1 million in the same period in 2011 representing an increase of about 4%. During the quarter, the division generated electricity equal to approximately 100% of long-term projected average wind and hydrology as compared to 95% in the same quarter last year.

Strong hydrology in some regions particularly Quebec offset below average hydrology in other areas such as the New England region. This demonstrates the value of the regional diversification in APCo's renewable energy portfolio.

For the first quarter of 2012, operating profit totaled CAD15.3 million as compared to CAD15.2 million during the same period last year. In the thermal energy division, our thermal energy division came in below our expectations for the quarter posting an operating profit of CAD3 million compared to CAD4.4 million during the same period last year. The decrease is mainly due to decreased production and energy rates at the Windsor Locks facility as I mentioned and as a result of reduced revenue from the Sanger facility as a result of that facility being off-line since January due to a planned major maintenance.

Our Sanger facility returned to full production effective May 1 and the second quarter will begin to show those improved results as a result of that. At Windsor Locks, we are nearly finished the repowering of that facility which when complete will reduce the impact of market-based energy pricing although the effects of this won't be fully felt until the third quarter.

Looking ahead to the next quarter for the second quarter of 2012, APCo's renewable energy division is expected to perform based on long-term average resource conditions for wind and hydrology with the exception of New York and New England that are expected to perform based on below average hydrology.

The thermal energy division's, Sanger facility returned to full production as I said May 1 as a result of the transmission system upgrades being undertaken by PG&E and we took that opportunity to perform additional upgrades at the facility to accommodate the higher voltage. The return to service of the facility will show in the results for the second quarter but overall, we expect revenue to be CAD400,000 lower in Q2 compared to the same period a year ago.

At our EFW facility, the waste supply agreement with the Region of Peel has been extended through October 2012. We are expecting the second quarter production to be in line with the previous year and our pricing will now revert back to the start of year pricing levels.

Moving on to Liberty Utilities, our Liberty Utility South region continued to be a solid performer really a steady-Eddie in our portfolio. Liberty Utilities South's wastewater treatment connections grew by 3.6% and the water distribution connections grew by 3.9% over the number of connections that we had a year ago. Revenue for the first quarter of 2012 totaled CAD10.6 million as compared to CAD9.8 million during the same period in 2011, an increase of 8%.

Water distribution and wastewater treatment revenue increased due to increased revenue from more customers and from the implementation of previously approved rate cases.

Moving on to Liberty Utilities West, Liberty Utilities West utility being a winter peaking facility was affected by the warm and relatively short winter in the area which reduced energy consumption by about 15%. Net energy sales revenue for the first quarter totaled CAD7.6 million compared to CAD9.6 million in the same period last year.

Liberty Utilities West operating profit for the first quarter of 2012 was CAD3.1 million compared to CAD5.9 million for the same period last year. Looking ahead to the next quarter for Liberty Utilities, we are expecting continued modest customer growth in both South and West.

I would like to take a moment now to review our recent financing activities. Again it has been another busy quarter for our treasury team. On January 19, Liberty Utilities entered into a senior unsecured revolving credit facility with a three-year term. Initially, it is a $40 million facility to support current operations of Liberty Utilities and the facility will automatically increase to CAD100 million upon the first closing of either the New Hampshire Utility Acquisition or the Midwest Gas Utility acquisitions. The facility is led by J.P. Morgan Chase.

Additionally during the quarter we redeemed CAD57 million of the 6.35% Series 2a convertible debentures by issuing 9.8 million APUC shares. With APUC's lower cost of capital redeeming the debentures for equity represented an accretive transaction on both an earnings per share and a cash flow per share basis and further strengthens our investment-grade balance sheet.

Subsequent to the end of the first quarter, APCo received commitments from its banking syndicate to increase the credit available on our banking facility from CAD120 million to CAD155 million. The increased facility will be sufficient to fund the requirements and working capital needs of APCo's planned capital commitments for 2012.

And on a final note, we are now nearing the end of our regulatory approval process for our utility acquisitions, as Ian mentioned, so we are about to enter the US private placement market to raise the debt required for those acquisitions. The financing will be an NAIC2 investment-grade US dollar offering and will be about $200 million in size. This financing together with the Emera equity commitment that Ian mentioned earlier will complete the financing plan for these utility acquisitions.

I will now hand it back over to Ian.

Thanks, David. And before we open it up for questions, I would like to do a quick update on our growth strategies and prospects starting with Liberty Utilities. As mentioned, we are very pleased to progress through the majority of the regulatory process for our announced regulated utility acquisitions in New Hampshire and the Mid-states and as we move towards final approval on both acquisitions in the second quarter, we look forward to the integration and welcoming of these new assets, employees and regulators into the Liberty Utilities family.

With respect to the previously announced transfer of Emera's 49.9% direct ownership in our California electric utility, with a settlement agreement reached and filed with the Commission during the quarter, we believe that the process remains on track for closing in mid-2012.

With respect to continued expansion of our utility portfolio, we continue to see assets of interest in the rate regulated electric natural gas and water distribution utility and transmission asset class in the United States and continue to evaluate these opportunities for accretive growth to our utilities portfolio.

Moving onto APCo, we are seeing progress on our 350 megawatt pipeline of wind development projects with power purchase agreements that we have outlined in our disclosure today. Each of these projects is currently advancing on schedule to the various development cycles.

In 2011, APCo executed a 25-year power purchase agreement with Manitoba Hydro in respect of St-Leon 2, a 16.5 megawatt expansion of our existing St-Leon wind energy project located in the province of Manitoba. Mechanical completion of all turbines was achieved in the first quarter of 2012. The facility is currently in the final interconnection and commissioning stage and is expected to achieve commercial operation under the power purchase agreement during the second quarter of this year.

The total capital cost of the project is expected to come in as expected at approximately CAD30 million.

In our thermal division, we are advancing through the repowering of the Windsor Locks facility following the execution of an agreement with the steam host Ahlstrom for a revised and extended energy services agreement which now continues through 2027. The re-powered facility consists of the installation of a 14 megawatt solar T1 30 turbine more appropriately sized to serve the mill requirements and leaving the existing 50 or so megawatt electrical generating equipment to sell into the ISO New England market when market conditions warrant.

The primary objective of this repowering project is to decouple returns from this facility from the fluctuating market electricity and gas prices which obviously impacted our results this quarter as highlighted by David. The total expected net capital cost of this project are forecasted to be approximately CAD19 million which takes into account certain grants and tax credits for which we believe we are eligible.

Looking ahead, we are anticipating that the next time we will have the opportunity to present to you we will have completed our utility acquisitions, finalized commissioning of our St-Leon 2 wind facility and brought our re-powered Windsor Locks facility online.

And with that, we are ready for our question-and-answer session. Operator, could you open up the lines for questions please?

(Operator Instructions). James Morrison, Cormark Securities.

Hi guys. On the Calpeco I see that five large commercial customers were lost. I don't know if that is recent or not but what happened there and how impactful will that be going forward?

Well actually I guess you caught me on that one because certainly the impact that we saw from an energy consumption perspective was really driven by warmer than average conditions rather than customer loss. So certainly have to look into that one, James, but that's certainly one of the root cause of any reduced customers. So I get it that the customer count has gone down but that certainly wasn't the issue.

Right, so it is not that you are seeing some of your customers leaving the area or going out of business for some reason or another?

No, no. It really was driven by weather fluctuations.

Just the weather. Okay, and then that water lease litigation of CAD2.1 million, should we expect another CAD3.3 million in the next quarter to get you up to the CAD5.4 million?

No, in fact actually we would like to see it go the other way which is CAD2.1 million go down to zero. We actually believe we have a very strong case. There is a very specific indemnification included in our lease going forward and I think really what even as you see that CAD2.1 million inclusion in our financial statements, that is really probably more a reflection of the way GAAP looks at the issue rather than we would look at it commercially.

So look we are obviously going to fight the good fight and believe in it and so I think we are looking at it the other way, James.

So is that going to be I guess clarified anytime soon?

In August of this year, we have a meeting with the federal government who are the counterparty to our lease and counterparty to our indemnification clause and so depending on the timing of that meeting and the timing of our Q2 call, we may have some more information for you at that time.

Okay, I'll just get back in the queue. Thanks.

John Safrance, M Partners.

Thank you, good morning. The shortfall at Calpeco, do you have the ability to claw some of that back through the remainder of the year?

Well look, it certainly is a fluctuating situation. I mean it is definitely tied to energy consumption but I will highlight and I think I tried to make a note of this in my opening comments is that in the 2012 rate case that is filed, we are actually seeking a decoupling mechanism that would allow the returns to the utility to be decoupled from actual energy production and when you think about it, I mean in some respects that is common sense. I am not exactly sure why the provider of the wires and transformer equipment should somehow -- the returns for the commitment of those assets to public good should be tied to energy price or energy consumption fluctuations.

Obviously to the extent that the summer happens to be hotter than normal and the air-conditioning loads are higher, we will see higher than average energy sales. Our hope as I said, is that that decoupling mechanism gets approved and we won't be having a conversation with you about whether it is has been a warmer winter or a hotter summer going forward.

Okay, fair enough. But if things perform seasonally as expected then we should assume that sort of that CAD4 million or CAD5 million shortfall won't be recovered during 2012?

Certainly not if we continue to meet the averages going forward, then in some respects -- and this is the sad part about the obviously the revenue is lost going forward -- we obviously hope that that is not the construct that we will be operating under following this rate case.

Okay. And then in terms of assuming that you receive approval in Q1 of '13 next year in terms of decoupling that, will we still see some seasonality as far as -- like will it be structured that way or will we basically see a consistent operating profit each quarter going forward?

No, I think really the way these decoupling mechanisms tend to work is there tends to be a reconciliation but you in effect still ride the seasonality cycles if you will going forward. It is just that as you had pointed out in your opening question, is that the revenues that were quote lost would have been recovered at a later date. So it is not about equalizing them so there are four equal quarters so you are still right, this is a winter peaking utility and our EBITDA will continue to be in effect winter focused.

And then just one other question with respect to the Emera subscription receipts. So I am just curious how the CAD5.74 and the CAD6.45 were arrived at in terms of pricing them?

Sure. As everyone will recall, Emera made a forward commitment to us back in April of last year at CAD5.37 which was in fact a premium to market at the time and it was a commitment that was made to us in connection with our acquisition of an interest in the first wind portfolio. We made the decision -- I say we -- Algonquin made the decision not to proceed with that portfolio but kind of being respectful and mindful of the fact that that equity commitment made by Emera wasn't sort of -- wasn't impacted by that decision the board felt it was appropriate to continue in effect to respect that commitment.

The CAD5.74 if you do the math, I think you will see it is really just the weighted average of that original commitment of CAD5.37 that was made back last year and a CAD6.45 price for the balance of the equity commitment what really is in fact as I mentioned in my opening comments, a continued tradition of investing at a premium to market.

I see. Thanks very much.

Nelson Ng, RBC Capital Markets.

Great, thanks. Just in terms of I guess acquisition related costs, what are your expectations for the rest of the year just based on the current pending transactions?

I think it is safe to say that the bulk of the acquisition related costs I think are behind us. There will be certainly be some costs incurred as we move to close the utility acquisitions but we are not expecting to see quite the same spike that we had in the first quarter.

That being said, I mean I will certainly point out that these costs were all costs that under a previous GAAP framework would have just been capitalized as part of the cost of the transaction and it really is just an accounting construct as everyone knows that causes us to expense them each quarter as they are incurred.

Great, thanks. And then just on Emera's stake in Algonquin, are they participating in I guess when all the transactions are completed, their stake would be roughly 25%. Have they mentioned what their intention is in terms of maintaining that 25% whether they are participating in the DRIP program or anything like that?

With respect to the DRIP program, actually I am not sure and obviously you know, Chris Huskilson might be a good guy to direct the question to. I can kind of give you sort of the general discussions that we have had is obviously Emera in our strategic investment agreement contemplated a 25% economic exposure to Algonquin's fortunes. And I think it would be logical that once having got there maintaining that through their anti-dilution rights would be the logical step to go. But I guess obviously Emera is free to participate in future equity offerings going forward, enter into new subscription receipts as we perhaps announce new transactions going forward which I think unto itself has materially positive implications.

I think to the extent that for each acquisition we can take 25% of the potential overhang off the table, I think that is a good thing from the market's point of view.

Great, thanks. I will get back in the queue.

Rupert Merer, National Bank Financial.

Good morning, everyone. It looks like we had a big increase in rate base for Liberty South to CAD206 million from CAD156 million quarter over quarter. Can you give us some color on that and how it breaks down between increases related to acquisitions, investment or regulatory adjustments?

Well, I mean I think I guess I wonder if it represents some investments in -- it went from CAD202 million -- is that what you're speaking of to CAD206 million, Rupert?

CAD156 million.

I guess I am looking at the disclosure here seeing that -- assets for regulatory purposes.

Yes, well, maybe it was just a restatement.

Okay. Well let's put it this way, during the quarter we would have completed our acquisitions of KMB and Noel Water, a couple of tuck-in facility acquisitions. Look, I don't think there has been any material investment. We are continuing to invest in additional treatment capacity in our Litchfield Park facility. It is kind of ongoing investments but nothing material that would come to mind.

Okay, great. And then if you can give us some detail on the PP&E additions in the quarter, CAD10.6 million, how does that break down between your various growth initiatives and what are your expectations for PP&E in Q2 between Sanger, Windsor and St-Leon? Thanks.

Okay, certainly in Q1, the capital if you really look at it, I will say on a division by division basis, it was pretty much consistent year-over-year for all divisions except for our thermal division and there we have two capital projects that are underway. I think we have talked about both of those.

So within thermal, we had CAD4.5 million that we invested related to the repowering of that facility. We had about CAD1.7 million invested in Sanger because as you know, that facility was down in the quarter for facility upgrades and changing out the transformer due to PG&E requirements. So that was really what accounted for the spike in capital there going forward.

I think for the balance of the year and I will say it is harder for us to sometimes parse it out by quarter but certainly we are looking at about CAD45 million of capital for the balance of the year. In the water division, we are looking at approximately CAD12 million which will include an expansion to the wastewater treatment plant down in Arizona.

Liberty Energy is expected to kind of come in on their capital budget which is about CAD9 million for the balance of the year. Windsor Locks and Sanger as they complete their capital upgrades, we are looking at about CAD9 million there.

And in the renewable, as we finish up our St-Leon 2 facility and as we do the -- we have a G5 runner replacement scheduled for our Tinker facility, that is about a CAD15 million project. That will likely be timed while the Tinker replacement will likely be timed closer to August as I recall so that will most likely be a Q3 phenomenon.

So I hope that gives a little bit of more background on our capital plan for the balance of the year.

That's excellent. Thank you very much.

Juan Plessis, Canaccord Genuity.

Thank you. Just getting back to the topic of the subscription receipts, one tranche of the new subscription receipts will convert simultaneously with the close of the new US or with the US wind acquisition. Does this refer to the close of the first stage which will occur either late this quarter or early Q3 or the close of the second stage in 2013?

It is really to be frank either and I think, Juan, we are obviously looking at it in the context of sort of matching the equity needs for the demand. And so I think we appreciate the flexibility that this gives us going forward. So in fact, either.

Okay. And can you take us through the rationale of converting the CAD12 million receipts now instead of concurrent with the close of the New Hampshire acquisition?

Yes, I think the short answer to that one I think it was Emera's request that they'd like to kind of get that behind them. They obviously got a favorable response from the main PUC and I think the short answer was that they would really like to increase their ownership interest. I don't think there is sort of a material impact to us because we are likely going to need the money in June anyway and so really it fits without major negative arbitrage.

Okay, thanks for that. Just as a follow-up here with regard to the EFW facility, I think there is a statement in the MD&A that said that you are now entering into contracts for alternative waste streams. Can you give us an update on that? Does that mean you have already signed contracts?

Yes. Look, right now it is a process. We have a bogey if you will of replacing the 160,000 or so tonnes that the recent appeal currently gives us and I think we mentioned perhaps in a previous call that it is four plus million tonnes a year of waste generated in the GTA area so there is in fact loss of haulers of waste and so we have the big thermometer if you will that we will talk about 160,000 tonnes and we have entered into agreements with a couple of haulers already. And I don't think we are disclosing specific names, I think we are well on our way to having that thermometer get up to the 160,000 tonnes we need.

Okay, do you have any color on the tipping fees?

Well, it is a competitive process but I think they are generally in line with what our expectations were with the recent appeal.

Okay, great. Thanks very much.

Matthew Akman, Scotia Bank.

Hey guys. On Calpeco, a couple of follow-up questions. When you talk about around CAD7.5 million EBITDA uplift if you get what you are asking for in the rate case, are you talking about that on a weather normalized basis? In other words I guess it would be more than CAD7.5 million based on what you are actually earning in 2012. Is that right?

They are always on a weather normalized basis so you are right in that when we look at the revenue increase request that we are asking, you are kind of comparing weather normalized revenues against actual costs and so you know kind of doing a hypothetical income statement to go into the regulator with.

Yes, thanks for that. You mentioned vegetation management tracker recovery. Would that include anything retroactively to 2012?

Yes, that is in fact the entire point of the vegetation management account is that from the date of its approval on I think it was May 10 of this year, showed throughout the balance of 2012 to the extent that we spend money on vegetation management -- and don't get me wrong -- vegetation management is a big line item in the expense of our Tahoe-based utility expenses, we are going to get to collect those going forward.

If your specific question was about retroactivity for the first part of 2012 before the May approval, to be frank, you don't do much tree trimming in the winter notwithstanding the fact that the winter was even warm so it is not even that big an issue.

Okay, and final question related to Calpeco, the reduction in purchase power expense that you have applied for, is that a forecasted amount or something that has already been purchased and locked in?

It is a forecasted amount. As we look at the current prices going forward, they have dropped obviously from lower gas prices etc. which we will say played or at least they are certainly without editorializing present across the US. And so I think that the rate payers in Tahoe are going to get the benefit of that and as we forecast what the costs are going forward, we take into account that forecast of electricity prices.

Now as you know, every year there is a final true up of those actual costs through the energy cost adjustment clause in the agreement so while it is just forecasts, we are not actually wearing the risk of that going forward.

Okay, great. Thanks. Those are my questions.

Sean Steuart, TD Securities.

Thanks, good morning everyone. One question on the Emera subscription receipts. To take it up to 25% of the equity base, can you just talk, Ian, about I guess the approvals you need in Maine and that process and is that basically a rubber stamp?

Well I am sure it's certainly not going to say those words because that would obviously fly in the face of the authority of the main PUC. I think it is a reasonable observation that the deliberation that took place surrounding the last process kind of acknowledged that to the extent that Emera wanted to increase their investment from 20% to 25% to the extent that that was related to or arose in the context of work and initiatives of Algonquin that were outside of the state of Maine, I think even the commissioner kind of to quote them said that would be a pretty dry proceeding because it is -- I am not so sure how it would impact the rate payers in the state of Maine.

So I think we are optimistic that the process will be an abbreviated one because there are very few issues at trial there but I would never use the words rubber stamp. I think we are comfortable that those subscription receipts really provide the basis for bringing that regulatory application and that it will be concluded kind of long before we actually need the funds that are referenced by that tranche of the subscription receipts, Sean.

Okay, understood. The rest of my questions have been answered. Thanks.

Matt Gowing, Mackie Research Capital.

Good morning, everyone. A couple of questions here. First question on Sanger and then a couple of questions on your solar project. So on Sanger, you did say in the disclosure that the drop in production was offset by a CAD0.7 million increase in pricing. Does that pricing increase relate to the previous repower that you did there or is there something in that formula that caused that price to increase? And just wondering how we should think about that pricing formula going forward impacting pricing at Sanger. Thanks.

Look, the short answer is to your question is no -- that right now the pricing that is driven within Sanger is only related to I won't say the existing capacity because it is obviously all integrated into a single plant that right now is capable of producing 56 megawatts but has a contract to sell 42. So it is really in the context of the 42. So it is not related to that.

But maybe the follow-on point that I would make in that is that the upgrade of line voltage from 69 kV to 115 kV has increased the capacity available at the PG&E system to accept all 56 megawatts of the Sanger capacity which currently exists. So with no further capital upgrade, we would in effect just pour more gas into the prime mover and get up to the 56 megawatts.

We are in negotiations with PG&E for a revision to our existing contract to provide us a tolling opportunity to sell that increased power. And so we are hopeful over the next few months to conclude an arrangement with PG&E that we will see that additional 14 megawatts which was largely trapped if you will behind that 69 kV transformer to be freed up and delivered to market.

Okay, great. I am actually going to switch over to a different question I have relating to Energy North. You talked about a rate case expected two years after the closing, the acquisition closing. I was wondering if you could give us some order of magnitude on how much you could expect from that rate case. Thanks.

Sure. I guess it is important to note that Energy North just concluded our rate case I guess it was about 14 months ago now. And so it is a pretty healthy earner if you want to think of it that way.

The rate case that we will undertake following completion of the closing as you point out a couple of years after closing, will really just be a matter of course rate case to address inflationary pressures, continued investment in the utility which we expect to be kind of modest and moderate. I mean it is not -- the utility has been maintained in good shape -- it is not like there is any major capital projects that need to get done in the utility. And so while I don't actually have a number, I think that rate case will be -- I wouldn't say a nonevent but it will be a matter of course if you will.

Okay, great. That's very helpful. Thank you.

(Operator Instructions). Ian Tharp, CIBC World Markets.

Good morning. So just going back to Calpeco for a minute, if you can remind us when the rates roll in and I mean you have talked about the 7.7 incremental EBITDA. Is that rolled in over a period of time and that is the final incremental run rate EBITDA or is that what it starts out that? Thanks.

Sure. Well, look, the way it works obviously as the gavel comes down, the order becomes final and the rates in the billing system get increased to the new tariff. The CAD7.7 million is a run rate number that would start if you will, accumulating on the days that the gavel comes down. But over the course of the year, we would expect the CAD7.7 million to come in but largely sculpted if you will on the same profile of the existing earnings from the utility as we mentioned earlier that the utility is a winter peaking utility. So to the extent that we are hoping for an early 2013 proclamation of the new rates, hopefully we would be in line to collect the lion's share of that with our 2013 winter earnings.

One point I'd like to make and I don't know if it was Rupert who asked the question, but I just wanted to hit on it and while we are sitting here did a little bit of reading on that drop in customer counts. In fact, it was really just a recognition of kind of a reclassification of bills. We actually didn't lose any customers during the year.

Everyone -- well you may or may not be aware as part of the transition of the utility from NV Energy to ourselves, we transition to our own internal customer care or customer information system and through frankly really just administrative reorganization of the accounts that kind of shows that those accounts dropped from 60 to 55. In fact there was no loss of customers, it is really just a reconciliation of kind of meter identification. We just do it slightly different than NV Energy did. So I just want to make sure that kind of got back out there.

Okay, I think it was James that pointed that out. So just to reiterate, you don't have to roll in that tariff increase over kind of an extended period. It is really the next 12 months after as you say the gavel comes down. On a seasonal basis, you see that increment within each of the quarters?

No, look, phase-in of rates, if you will, are something that are obviously uniquely determined in the context of any particular rate case. We have had a phased-in as you know in our LPSCo water utility in Arizona but it was largely driven by the magnitude of the rate increase trying to deal with potential rate shock.

In this case, we are asking for a 10% increase in rates which really represents the better part of four years of inflationary pressures and continued investment in the utility. So look, without speaking obviously on behalf of the Commission, historically those kind of levels of rate increases at least during the NV Energy watches were never accompanied with a phase-in if you will. So we don't anticipate one in our case but ultimately it is the Commission which ultimately decides that.

Okay, well we will stay tuned for that. So just moving on to the energy from waste facility, we have talked about it a bit but I wonder if you can talk about of the 160,000 you get from Peel, what proportion are you actually seeing from external sources now? And then I would assume that you are starting to entertain discussions around longer-term contracts with these folks so if you could give updates on that it would be helpful.

Sure. Right now we actually don't take very much from other haulers as you may be aware, their Region of Peel produces waste far in excess of the 160,000 tonnes that we consume and so we are really just diverting a portion of that river of waste so there isn't a lot of capacity in the plant left over to today take waste other than the Region of Peel.

So I think we are meeting and reaching agreement with other haulers. It is really quite a -- it is a binary thing when the Region of Peel stops delivering waste to us and in fact even as I say that, we are hopeful with discussions of Region of Peel that maybe they will want to continue to deliver some portion of the waste to us following the end of October, end of our contract.

But we are right now we are anticipating that at the end of that we will be replacing all 160,000 tonnes with alternative haulers as I said, there is an ocean of waste that flows every day out of the GTA and so 160,000 tonnes is but a sliver.

Okay. So you are confident in terms of volume, a little less certain in terms of price given that you will be more spot pricing based following the expiry?

Yes, though I think look, our objective is ultimately to reach long-term arrangements with haulers and obviously the best counterparty from with whom to contract for long-term waste are municipalities and other regional -- other governmental bodies but they take a long time to react. And so I think we see kind of this in two phases.

One is we will fill the gap that will be left with the Region of Peel waste leaving and we will fill that with short to medium term contracts. And let's call it a year or two years but we will use that intervening time to continue discussions which actually are ongoing right now with other governmental agencies to enter into kind of the longer-term, the five-, 10-, 15-year arrangements with those governmental agencies. So I think we kind of see it along that line.

Okay, helpful. I was going to ask about your outlook for the renewable power facilities in New York and New England. You said it will be below the long-term average in Q2. A small difference but are you expecting the same type of shortfall as you saw in Q1 extend into Q2 in those areas?

Well, look, it is all driven by hydrology and I think perhaps you have to look at it in the context of the seasonality of the various -- of those regions and so to the extent that a 10% deduct in the summer is not the same as a 10% deduct in the spring or winter.

I would point out that look, the outlook that we give, we are not weather forecasters. The best we can do is look to how the production was kind of up to date so we have sort of April under our belt and got some line of sight to how April has done. And if we look across the portfolio and I guess this is what our outlook statements are saying is, it looks relatively healthy in line with averages across the entire portfolio saving except for New England and New York which I will point out are relatively small divisions where it has been drier than average.

But heck, we have got two-thirds of the quarter yet to go and I guess it is at the largess of God to make it rain. So I guess the best we can kind of give you is a little bit of insight to how April works and so you shouldn't read more into that than that.

Fair enough. And if I may just one quick question on your wind facility. So clearly two phases here. You have got the final two hopefully reaching COD in Q4. So is it fair to say that it is more of a -- you don't have financing risk there on the tax equity side because you seem to have your counterparties, it is more really around the timing of COD which is a risk there but it doesn't seem like it is your risk given that you have still got an option on those acquisitions. So is that kind of a fair characterization of your involvement in that risk?

Yes, I hesitate to use the word option but I think the result is the same. We are not taking the development risk on these facilities and I think that is an important observation. So to the extent that any or all of the conditions precedent to this transaction were satisfied and they weren't satisfied because of a development risk, we are not on the hook for this. And I think this is part of the value proposition that we negotiated with Gamesa is that in this case, they are the developer.

Obviously we are developers in our own facilities so we know what those risks are. To the extent that they are -- those risks are -- do or don't materialize, that is Gamesa's problem. So I don't look at it as an optionality but I do look at it as kind of risk shifting if you will and it is important to know where that risk lies and what the implications of that risk could be.

And you are absolutely right. If the risks do materialize and end up causing a problem, I mean I think the good news is from Algonquin's point of view, we are not going to be buying a project which is prejudiced or compromised on that. I guess the downside is we won't get the opportunity to invest in what we had hoped we were going to get to invest in.

But I think one of the pluses about the relationship that got announced with Gamesa or with Emera today is we really don't suffer if you will negative arbitrage from having equity sitting around on the hope that those risks do or don't materialize that to the extent that we need the capital, it has been committed and so we are I think the capital market should be comfortable that we have the equity on a just-in-time basis assuming that everything works out from Gamesa's point of view.

Okay, fair enough. Those are my questions. Thank you.

Jeremy Rosenfield, Desjardins Capital Markets.

Good morning everybody. Thanks. Most of the questions answered so far. Just a few quick ones. On the Gamesa topic, are there any updates that you could provide us with just in terms of how the construction is proceeding so far?

Sure. Pocahontas, the Iowa-based facility was brought online during last quarter or certainly if you take the period up to the end of April, as was Sandy Ridge. So there's two operational projects. And they are madly digging holes for foundations in Texas and Illinois for the Senate and Minot projects.

So as we sit here today, there is nothing that to our knowledge that stands in front of Gamesa's ability to build those projects. I will point out though that there are a number of conditions precedent to our proceeding and frankly every one of the boxes needs to be ticked from our perspective before we want to put money in harm's way.

So I think that nothing has arisen that as of right now I don't believe Gamesa can get over but there are outstanding boxes that need to be picked, Jeremy.

Okay, great. Let's move onto something else then. Just from a strategic perspective looking at the overall portfolio, is there anything that you might be interested in to sort of to monetize at this point? I am looking at some of the smaller assets perhaps even in New England where they haven't performed quite as well just this quarter?

Look, it is a totally fair observation that our portfolio needs to be reviewed. Its composition needs to be reviewed in the context of the organization that owns it. And that as this organization has grown, we have actually made the decision to sell off some of the smallest of the hydro sites that maybe when the organization was CAD150 million in enterprise value made sense to hold but as the organization is heading over to and perhaps towards CAD3 billion, they don't make sense going forward.

So it is an ongoing process. We are looking at it all the time. I think you obviously highlight and know that the asset that would most likely get the focus of that review some of the smaller hydros that are located in the New England and New York regions but we haven't made any decisions but I think you should rest assured that we look at it all the time.

And don't get me wrong, I think the fluctuation of hydrology kind of gets accentuated with smaller facilities because of the implicit operational leverage that exists that the operating costs and the percentage of revenue are higher on a smaller facility. And so a 5% or 10% reduction in revenue on a smaller facility translates to a much bigger reduction in EBITDA than it does on a larger facility and so we get the comment and I think we feel the same way.

Also maybe just going the other way in the US Northeast recognizing that we are in a low price market environment at the current time, are there any opportunities do you think to add to that portfolio, maybe even in merchant capacity for example that you might be able to underpin with some sort of capacity payments so that it is not an entirely merchant dynamic? Based on market prices for some of those assets, does that look attractive to you right now or is the strategy still 100% contracted here?

As we have always pointed out, this organization is not founded as a kind of participant in the commodity markets. That is not the value proposition that we are trying to offer to our investors. And so I think we would be hesitant to sort of say we are oh so smart that we can go and buy a merchant power facility and we know more than the market and we can make it work. Don't get me wrong, I think we have through our Algonquin Energy Services Group a group who can bring stability to those markets but to be frank fundamentally, you can't -- the best you can do is kind of smooth out those markets.

And so I think first prize is and will likely continue to be for this organization like the 25-year Chaplin wind project in Saskatchewan where we get stipulated rates from a highly creditworthy counterparty.

And so there may be opportunities there, Jeremy, but I don't think that is where our focus is from a growth perspective. We have got lots to do and I don't think we just need to kind of step out from a risk profile to meet the growth objectives we set for ourselves.

Sure, okay. And then just maybe one final question in terms of the updated FIT program, are there any updates that you could provide to us on how your solar pipeline looks relative to the new rules?

I don't say it is an update but one of the things that the OPA has permitted and you may be aware that historically transfers of project applications under the FIT process were somewhat problematic. You had to jump through a few hoops and do a couple of back flips to allow the transfer of a project application from one party to another. And kind of a one-time opportunity OPA has sort of freed up or removed those constraints. So that's obviously good news as we think about those 10 projects that I think you referenced that are in our solar pipeline going forward and so that is good news.

I think the bad news of the FIT review and just to kind of give a little bit of color on it, is I think OPA or the FIT programs tightened up some land use regulations. I think the support of (inaudible) or hydro 1 in terms of transmission. You know, look I don't think it is as robust as it was when the FIT program came in.

So if I had to handicap it and maybe that is not what you are asking me to do, but if I had to handicap the number of those 10 projects that we believe would continue on in the context of the lower FIT prices which is obviously a fundamental change, I would probably knock a couple of three of those projects off the list just due to -- if I was handicapping it. I don't know if that is kind of where your question was focused, Jeremy.

Sure, that is pretty much precisely what I was asking. Okay that is it for me. Thanks a lot.

There are no further questions at this time. Please continue.

Well, I would like to thank everyone for taking the time this morning and please remain on the line for an exciting review of our forward-looking disclaimer.

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

These forward-looking statements include among others statements with respect to the expected performance of the Company, its future plans and its dividends to shareholders. Since forward-looking statements relate to future events and conditions, by their very nature they require us to make assumptions and involve inherent risks and uncertainties. We caution that although we believe our assumptions are reasonable 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 those presented in the Company's most recent annual financial results, the annual information form and most recent quarterly management discussion and analysis. Given these risks, undue reliance should not be placed on forward-looking statements which apply only as of the date. Except as required by law, the Company does not intend to update or revise any forward-looking statements whether as a result of new information, future developments or otherwise.

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