Algonquin Power & Utilities Corp (AQNU) 2010 Q2 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Algonquin Power & Utilities Corporation second quarter analyst conference call. At this time all participants are in a listen-only mode. Following the presentation we'll 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 is being recorded today, Friday, August 13, 2010, at 10 AM Eastern Standard Time. I will now turn the conference over to Mr. Ian Robertson, Chief Executive Officer. Please go ahead.

Thank you, and good morning, everyone. My name is Ian Robertson, I am the Chief Executive Officer of Algonquin Power & Utilities Corporation, and I would like to welcome you this morning to the 2010 second quarter results analyst conference call. With me here in Toronto today are Chris Jarratt, our Vice Chairman, David Bronicheski, our Chief Financial Officer, and Kelly Castledine, our Manager Investor Relations. For your reference, the Q2 financial statements and management's discussion and analysis are available for download on our website at Algonquin Power & Utilities.com. I would like to not 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 at the end of the call. As the short agenda for today's call we would like to start with I couple highlights in the quarter. Next we will provide some additional color on the continued execution of our corporate plan as outlined in the current MD&A, and following that our CFO, David Bronicheski, will talk about the financial results and at the end of the call Chris Jarratt will host a question and answer period.

With respect to the second quarter of 2010, what we are continuing to make progress on our previously announced growth initiatives. The financial results for the second quarter were below management expectations primarily for two factors. Firstly, we discussed last quarter the overall related outage at our Energy-from-Waste facility and as we outlined at that time the shortfall in revenue, EBITDA and earnings would continue through the balance of Q2 2010. With this major refurbishment we replaced boiler and economy tubes and advanced other 2010 and 2011 planned capital maintenance which was also completed during this outage. With the facilities returned to full operation in early July, we now expect the facility to operate with a higher level of availability and lower operating costs which will hopefully allow to us make out for some of the lost cash flow and earnings in the second half of the 2010. The second challenge we faced in the quarter resulted from the apparently widespread lower than average hydrology in most of regions in which we operate hydroelectric facilities. In particular, Quebec was down 9% below long-term averages. Ontario was 43% below. The New England region was down 38% and western Canada and the Maritime regions fell short of long-term averages by 28%. While providing no comfort, these dry hydrologic conditions appear to be widespread within Canada and the US. As a side note, we were gratified to observe the St. Leon wind facility in Manitoba saw a return to close to average wind resources in this past quarter. While such naturally occuring hydrologic fluctuations are obviously disappointing we are pleased to highlight a couple positive operating event which occurred during the quarter. Firstly, as already noted the refurbishment of our Energy-from-Waste facility which partially contributed to Q2 shortfall of the successfully completed in the facilities back in service. Additionally the Windsor Locks facility made a successful transition to a forward reserve marketing operating model following the expiration of its legacy power purchase agreement with Connecticut Light and Power. Higher than anticipated dispatch factors and strong spark spreads in the New England ISO market in which we are participating delivered results which exceeded our preliminary forecast for this new operating regime. As we have outlined, 2010 is an important year for the consolidation of a number of value creation and corporate transition initiatives. I would like to take a couple of minutes to provide a quick update on these initiatives which are the focus of the balance of 2010.

First, our Liberty Water rate cases. As discussed in our MD&A, during Q2 Liberty Water continued the pursuit of seven rate cases in Texas and Arizona. We're pleased to have reached settlement for the three Texas-based utilities and have received an initial recommended order for Liberty Water's Black Mountain Sewer Company in Arizona. The Texas rate settlements provide essentially all of our revenue increase entitlement. Under the recommended order for Black Mountain the proposed revenue increase represents approximately 73% of the revenue increase requested in our rate filing. We have three additional rate cases in Arizona still awaiting recommended orders in which we have requested $16.9 million in additional revenue to support the investments we have already made in that state. Based on discussions with the Arizona regulator staff, we are hopeful that the recommended order for Liberty Water Litchfield Park Service Company, the largest of these outstanding rate cases will be available in early September.

Secondly, our electric utility acquisition and partnership with Emera. The California Electric Utility operation acquisition by Liberty Electric is proceeding through the regulatory approval process before the California Public Utility Commission based on the current regulatory procedural schedule the closing of the transaction is expected to occur in the fourth quarter of 2010. As we have pointed out, with the completion of this transaction the additional EBITDA, our share of which is approximately $10 million, will bring the percentage of our 2010 consolidated EBITDA generated by regulated utilities close to 40%. We think that this further emphasizes APUC's subtle shift to greater percentage of regulatory utility earnings. 2011 EBITDA.

Lastly, the continued construction of the Red Lily Phase I Wind Farm. The Red Lily Phase I Wind Farm is a 26-megawatt wind project in southeastern Saskatchewan. We're pleased that Q2 saw the commencement of this project with commissioning expected in early Q1 2011. APCo's interest in this facility is by way of senior and subordinated debt financing with the option to acquire 75% of the equity in the facility after five years in exchange for our debt commitments. In addition, during the construction phase we are earning a construction supervise fee and after construction we have been engaged by the equity provider to provide ongoing operational supervision services for which we will earn an annual service fee.

I would like now to take a quick minute to summarize our progress in the Corporation of Algonquin Power. The legal conversion to a Corporation and internalization of the management team were completed by the end of Q2 2010. As noted in the MD&A and previous disclosures there are a number of ongoing business associations between Algonquin Power and the former externalize management team including certain generating facilities in which legacy partnership arrangements exist. Disclosure of the complete universe of these business associations has been included in the recent MD&A for ease of reference. The Board believes that appropriate and desirable to work on simplifying and streamlining these relationships going forward. I would point out that no transactions will be entered into in respect of such simplification or streamlining process unless the Board believes it makes sense for the Company. I will now hand things over to David Bronicheski to speak to the financial results for the quarter.

Thanks, Ian. Now a review of the Q2 2010 results. Just as a note we use adjusted net earnings to assess the net earnings without the effects of gains and losses on foreign exchange and forward exchange contracts and interest rate swaps as we believe these are not reflective of the performance of the underlying business. In Q2 2010 our revenue was CAD42.7 million, and this compares to CAD46.5 million in the previous year. Our adjusted EBITDA was CAD18.7 million in Q2 2010 compared to CAD20 million in Q2 2001. On an adjusted net earnings and loss basis we recorded negative CAD100,000 loss in Q2 2010 compared to a CAD3.8 million adjusted net profit in Q2 2009.

In APCo's renewable energy division during the second quarter of 2010 net energy sales totaled about CAD19.2 million and the division generated electricity equal to 81% of long-term projected average and wind hydrology. The decrease in revenue compared to the same period last year is mainly a result of below long-term average hydrology in the Quebec region and resources significantly below long-term average in the Ontario, New England, New York, Western Canada and the Maritime region. For the second quarter of 2010 operating profit totaled CAD15.2 million as compared to CAD12.4 million during the same period in 2009. Overall the renewable energy division did not meet our expectations due to lower than expected hydrology in all regions. In APCo's thermal energy division total net revenue for the second quarter of 2010 was CAD6.9 million as compared to CAD13.2 million during the same period in 2009. The decrease is mainly due to the expected impacts of the shift to the new operating model at the Windsor Locks facility following the expiration of the power purchase agreement in April as well as the overhaul related outage at our Energy-from-Waste facility which continued through the second quarter.

For the second quarter of 2010 operating profit totaled CAD1.6 million as compared to CAD5.6 million during the same period in 2009. Overall the thermal energy division did not meet management's expectations primarily due to the unplanned outage at the Energy-from-Waste Facility. Looking ahead to the next quarter, APCo's renewable division is expected to perform at or below long-term averaging in the second quarter of 2010 based on wind and hydrology conditions. The Energy-from-Waste Facility returned to full production in mid-July and is expected to operate for the remainder of the year processing 475-tons of waste each day. We expect the Sanger facility to operate at or above expectations during the third quarter of 2010 and this is in line with the performance from the same time last year but we would note hydro mulch sales are expected to remain below expectations due to lower demand. Following the recent change in operating model at the Windsor Locks facilities we expect operating profit for the full year to be approximately CAD5.3 million compared to the historical CAD8 million.

Moving on to Liberty Water, revenue for the second quarter of 2010 totaled $9.2 million as compared to $8.6 million during the same period a year ago. Water distribution and wastewater treatment revenue both increased primarily due to increased interim rates at four facilities in Texas. The wastewater treatment customer base grew by 1.9% in the water distribution customer base grew by 1.8% over the total customers at the same time a year ago. This increase is due to some organic growth and also the inclusion of customers from the acquisition of the utility asset previously announced in Galveston, Texas. For the second quarter of 2010 operating profit totaled $3.9 million as compared to $3.5 million in the same period a year ago. Overall Liberty Water did meet our expectations for the quarter. 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 previously mentioned, we are proceeding with rate cases at a number of facilities in both Arizona and Texas. Delays in the progress of rate cases through the regulatory process in Arizona has resulted in Liberty Water experiencing longer than expected delays in receiving approval for the rates but we understand these are due to an unusually high number of active rate cases that are being processed at the Arizona Corporate Commission. While we cannot provide an estimate of the extent we will realize further increased revenues in 2010 from the rate cases we still do expect the full annualized impact of additional revenue from rate cases will be realized in 2011. In further details on these rate cases are disclosed in our MD&A on pages 28 and 29.

Finally, just a brief word on financial reporting frameworks and our conversion to IFRS. As most of you are aware, in 2011 publicly accountable enterprises in Canada will be required to change the accounting framework under which financial statements are prepared to international financial reporting standards. During the quarter, thought became clear that rate regulated accounting would not be available for publicly accountable enterprises in Canada reporting under IFRS. So as a result we are APUC is an SEC registrant and also has a significant and growing portion of its business in regulated utilities. As a result, we now have three alternatives before us that we are evaluating with respect to the accounting framework under which we are able to prepare our financial statements. First, we can still adopt IFRS and in this regard we made significant progress and we will be ready to report under this framework if it is selected and our progress is widely disclosed in our MD&A, but I would note this option would not currently permit continued rate regulated accounting.

Secondly, the IASB is working on a project to address rate regulated accounting, but the conclusions of that are not expected to be finalized in time for Canada's adoption of IFRS in January. As a result on July 28, the accounting standard boards of the Canadian Institute of Charted Accountants issued an exposure draft proposing that certain entities of which APUC would be one with rate regulated activities to allow those enterprises to continue using Canadian GAAP for an additional two years. A final decision in regards to the exposure draft is expected in the fall and if it is approved as expected, this would allow Algonquin to defer adoption of IFRS until 2013.

Finally, Algonquin is able to shift to reporting under US GAAP here in Canada. We are an existing SEC registrant and we currently do report under US GAAP in the United States. US GAAP reporting is permitted by Canadian Securities Laws and the TSE for companies subject to reporting obligations under US Securities Law. This option would result in actually minimal changes having to be made in our financial statements as there are actually very few differences between Canadian GAAP and US GAAP in our circumstances. So we're currently evaluating the three options before us in order to assess which of the three accounting framework options would provide shareholders and other interested readers of our financial statements the most useful basis for financial reporting and we will make a final determination for this in Q3.

I will now hand it back to Ian to wrap up.

Thanks, David. I would like to spend a couple of minutes just updating you on some of the growth prospects in our various subsidiaries. Within APCo we did participate in the recent Hydro Quebec call with two 25-megawatt community based wind power submissions and are waiting Hydro Quebec's analysis. In Ontario our 42-megawatt Prince Edward county wind project is awaiting results of the economic connection test pursuant to the Ontario fit program. Our 80-megawatt Amherst Island wind project in Ontario is not subject to the economic connection test process is located in the area where we are confident the connection availability exist and is awaiting an OPA fit contract response. In Saskatchewan we were pleased that three projects representing 500-megawatts of wind power potential were qualified to participate in SAS power's upcoming RFP process In Manitoba on our 80-megawatt wind power expansion of St. Leon received both Federal and Provincial environmental approvals in Q2 2010. In Connecticut as part of this successful operating model shift at Windsor Locks we are continuing to refine our repowering plans at Windsor Locks to further enhance economics with the planned installation of a 14-megawatt natural gas combustion turbine to augment the existing 54-megawatts of installed capacity.

Lastly, as outlined last quarter, we commenced the process to actively engage in discussions with a number of parties previously awarded power purchase agreements with the intention of bringing APCo's financial and technical resources to bear to support completion of their projects. Within Liberty Water we are pleased to note organic growth albeit modest is returning to our service territories. In addition, our business development efforts are focused on continued roll up of additional utility interests such as our Galveston, Texas assets, and we expect such efforts to yield additional results during 2010. Lastly, while Liberty Electric is engaged in the operations transition work for our California Utility, attention is being directed to several follow-on electric distribution utilities and transmission related growth opportunities.

In conclusion, we have a number of already committed value initiatives which are being pursued and in which we expect to complete during the course of 2010. We remain absolutely focused on providing total shareholder return which includes capital appreciation through dividend growth supported by GAAP earnings. In this regard while timing uncertainties and items such as the larger Liberty Water rate cases and the [Calquqo] acquisition have made 2010 quarterly guidance challenging. We remain confident that the full year 2011 impact of these committed value initiatives remains on track to deliver 2011 earnings per share in line with our targeted dividend payout ratio of between 75% and 100%.

With that I would like to turn things over to Chris Jarratt, our Vice Chair to chair the question and answer session.

Thanks, Ian. We'll open the lineup for questioning, please.

Your first question is from James Morrison from Cormark Securities. Please go ahead.

Hi, guys. Would you mind just taking us through what the plan is for refinancing the CAD106 million of debt expiring in January?

Sure. David Bronicheski will take that.

Absolutely. As we have previously noted, our bank credit facility that is matures in mid-January of 2011 we currently have approximately just over CAD100 million drawn on that facility as at the end of Q2, and as we note on page 36 of our MD&A we are expecting to conclude a debt financing that would actually see permanent debt being brought in and the proceeds of which would be used to reduce the amounts outstanding under the bank credit facility. Our view is for the most part given the nature of the assets that we have that relatively short-term bank debt really shouldn't play a significant role in our permanent capital structure and so we're simply looking to go into the medium to long-term note market to permanently term out that debt and that's pretty much what we can say at this time.

So you can't comment on like a kind of a goal for timing or anything like that to have that wrapped up by or if you're in late stage negotiations?

As we have noted in the MD&A, we do expect to conclude financing in Q3.

Okay. And do you have like target debt levels that in relation to your EBITDA, your total Cap that you're looking to reduce your debt to?

We're guided by what we do view ourselves as being which is essentially an investment grade power and utilities company, and so our view is that we would be managing our capital structure basically to investment grade metrics.

Okay. And then on the development pipeline in Ontario specifically how much wind is subject to the economic connection test again?

Right now we have 42-megawatts in down in prince Edward county which was submitted to the FIT program which is subject to the ECT. Our any megawatt Amherst Island project is not subject to the ECT and obviously we tick the box on that one that we are prepared to pay the cost in that one. 42-megawatts.

Thanks. Just finally, like do you know like what kind of backlog there is in that area, like are you going to need connected or lines or larger expansion lines, incision.

For which project?

The Prince Edward county.

We do. I mean, there are a couple of project that is are pancaked around and so it is hard to predict where each one of those is going. It is not -- 42-megawatts is not a huge project, and so consequently the congestion isn't mapped and the upgrade costs we're not expected to be massive, but it is a windy area, and so there are other projects there. I guess we're just going to have to wait to see how hydro one starts out.

Do you think the project could support the CapEx of the line and then you could consider that a facilitator line if everybody else connected into it?

Well, the area there, the substations aren't huge. The good news is to upgrade to support our 42-megawatts is not a massive you should undertaking. Whether that is going to be a facilitator or not, I am not sure there is enough land in the area to support a whole bunch of other projects in addition to ourselves, so I am not sure that it would be like we'll get to build out a generator, a lead, and support 300-megawatts project. I don't think there is the land to support that. I think it is pretty much we spend half -- we spend 3 to CAD5 million supporting our own project and really that would be it.

Okay. And finally just COD dates for both projects approximately?

Well, obviously in the case of somewhat depend on when they actually get back to us, but I got to imagine it is probably 18 months to a couple of years before COD on both of those.

Okay. I will get back or that's it for me. Thanks, guys.

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

Hi. Thank you. You guys did a major refurbishment at the Energy-from-Waste Facility, and it is back up and running since July 14, I think it was. Can you give us a little bit more update on how that's actually performing and how successful that was and sort of what you might expect on annualized basis looking out to next year?

Sure, Bob. I will answer that question. We just recently went through a complete overhaul of all five boilers, and we came online mid-July, and since then the plant has been running extremely well. It is a little early to come up with a definitive estimate for what we will expect to do for the balance of the year or going forward, but I would think just going back in history we typically locked about 5% of our plant's availability to boiler tube failures, so with our relatively high degree of confidence expect that to be gone, and that represents about 7000 additional tons per year of waste. Secondly, we didn't make quite a few other alterations to the plant, and this is probably a bit more speculative, but I am expecting probably a pickup of about 3% or 4% in plant availability which equates to about an additional 5000-tons per year. So in general the overhaul went very well, and since then the plant just has been performing extremely well.

Can you use that expertise or knowledge to get into other facilities elsewhere? You talked about it maybe expanding that. I don't know if there is also other ones in the US or Canada that you would be looking at?

No, I don't think we would be. We are engaged in conversations with the region appeal about extending the contract as we mentioned a few times. One of the possibilities of that is an expanded facility, and we are as I said in conversations with the region appeal.

With no timeline on when you might have a sponsor a decision?

I would expect that to happen probably in Q2 or Q1 of 2011, and unfortunately that is tied a bit to the anticipated or the scheduled municipal elections which are in the fall of this year, so likely nothing is going to happen until after that.

Right. Thank you. Changing gears, looking down at the states in the water business, some delays in the rate cases which is not at all abnormal during an economic downturn but in conversations with them we understand the staff is down to about half count or something after layoffs. Do you have any comments on sort of how it is going in terms of the quality of the process? Has it degraded quality or is it everything sort of just delayed but still expect the same good results?

No. Actually, I would actually suggest that -- let me start by saying, Bob, you're right. The guys and we're speaking obviously specifically the ACT are incredibly shorthanded right now. Budget constraints haven't allowed them to replace people that have left, and so everybody down there is kind of doing yo man's duty. Having said that, we have undertaken a pretty significant process to try to improve the quality of the information and that we have been providing back to them and I think in response we have had quite a constructive relationship with staffer and with the intention of providing greater transparency on the way we have worked and the way we manage our utilities, and I think it has been well received, so I think the recommended order that came out with respect to Black Mountain, in kind of response to the positive -- the positive work that was done by the ACC, we elected to file no exceptions to that order, and it is hopefully on the public meeting agenda for the open meeting agenda for August of this year, and so I think, yes, that things are going slower, but I wouldn't suggest that the quality of the outcome that we have concerns about and I appreciate time obviously always remains a concern, and I wish there was something we could do to kind of help the process out more directly, but it is not like that we're concerned that the delay is also going to result in lower quality work on behalf of the ACC.

Okay. I see one of your Canadian not quite competitor but another water company has gone down and bought a water utility down not too far away from you. Can you give us any comments on what you thought of pricing? Is there opportunities to sell? Would you look at selling if the prices were great and just some general comments?

Sure. In short to answer your second part of your question first, everything is for sale always, and frankly if the valuation metrics which to our understanding which were applied to that transaction got applied to Liberty Water there is probably CAD60 million or CAD70 million worth of uptick in the value of our business which is sort of good news for us. I got to tell you, though, that on the acquisition front we are going to continue to demonstrate what we would like to think is more discipline than that. Ultimately the end of the day when an asset gets sold you always got to wonder if you're the winner or really the loser from our perspective if we can't complete acquisitions that deliver accretive value to shareholders to be Frank ask yourself the question what are you doing it for, so it is good news, and then I think it sets a great bar from a evaluation perspective from our assets. Maybe it is not so great news and it sets the expectations of sellers, and that's okay if maybe we'll become one of them, so it is an interesting data point, but it certainly isn't reflective of what we would be paying, Bob.

You haven't been approached?

No.

Okay. Thank you very much.

Thanks, Bob.

Your next question comes from Tony Courtright with Scotia Capital.

Thanks very much. I guess this may be a question for David Bronicheski. It is relating to your mention of refinancing. You expect to close this quarter, and you discussed the possibility of going to a medium to long-term note market, but I see references as well to potentially refinancing certain specific project financings, and what I am interested in is just your financing approach in terms of do you see yourself granting creditors security interest in assets and how that might impact your ability to continue to have committed bank credit availability given that they're sitting as secure lenders at the moment?

David Bronicheski. Thanks, Tony, for that question. We have clearly been quite active in this area for the last several months and so as part of that process we kind of have to go into it with a wide open mind and a view to seeing what is the best formula for creating the lowest cost of capital for our Corporation, and so we have already done a quite detailed analysis on the full spectrum from specific project financing to private placements to public bonds, so we looked at that, that whole spectrum. We didn't want to rule anything out in that process because really at the end of the day this is about creating the lowest cost of capital for our business in the long-term. That being said, as we look at project specific financing and the covenant packages that are expected for that, there does seem to be somewhat of a lack of a competitive tension I guess is the way to say it and the Canadian market for that, so I would say if you're looking at the balance of probabilities, it is project specific refinancing is likely the least probable of the alternatives before us.

Right. And then in terms of lowest cost so you're prepared to say if you were to do a medium term note, have it as a secured rather than unsecured claim?

Again, that's another consideration. Clearly, I think Corporations always prefer to have unsecured facilities, and it is just really makes life easier for everybody. That certainly, again for us would be our preference.

Right. And in relation to your liquidity, I see you borrowed some additional funds for the projects here undertaking I guess investments in Red Lily, but your credit availability or I guess has come down. Is that just trailing EBITDA impact?

Yes. That's correct. What you're seeing there is just a small amount of the effects of the lower EBITDA due to the hydrology, the lower wind resource in Q1 and obviously the EFW outage, so as those things naturally correct itself through mother nature and as we previously noted, EFW is back online and I think we do have an expectation that will widen.

And that's based on what, a trailing four quarter?

Yes, that's correct.

So a bit of a lag effect. In relation to the divisional outlook for renewable energy, there is a point here that plans are under way to expand the energy services business to include marketing the output of New York and New England region hydro generating facilities. Could somebody give me some color as to what's going on here? I thought that those -- the output of those hydro facilities was being sold on sort of an avoided cost basis to the utility given I guess it is presumably those facilities as contracts have matured?

Sure, Tony. It is Ian. Those facilities right now in New England are as you said selling their power largely based on slot prices, and I think it is our belief obviously that there is an opportunity to do something a little bit more insightful with that energy rather than just deliver it based on a day ahead pricing, and the energy services business or Algonquin Energy Services as we call it internally is marketing with medium term one and two-year forward commitments the energy out of the Maritime region from our hydro facilities. I think the intention is to expand that expertise to include some of our other generating assets and so rather than just selling on the day ahead spot price, we'll enter into some longer term agreements. Obviously just given the unpredictable and somewhat seasonal nature of the energy that comes off hydro electric facilities, those sales obligations need to be supported with purchases in the New England ISO and that process at the EAS Group based in Caribou, Maine, are totally familiar with, so really, Tony, it is about expertise that the organization has largely acquired in the context of the particular acquisition and starting to apply that if you will getting smart on the management of the off take of our generation to some of our other assets that you might argue we have been a little bit more simplistic in terms of a managing that off take just a day ahead pricing. I don't know if that's the color you're looking for.

That's fine. I appreciate it. Thank you.

Thanks, Tony.

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

Hey, guys. Thanks. Nice to see there is progress in Arizona. I am just wondering if you could just again maybe detail the timelines for LPSCo. You said that something is on the public docket for August?

Good morning, Matthew. What's on the public docket for August is the Black Mountain recommended order or BRU. In speaking with the regulator we have been advised that the LPSCo, the largest but by far the largest rate case which we have in front of the ACC that we're expecting that recommended order in early September with the help that it is available to be discussed and ratified on the September open meeting. There is open meetings held generally on a monthly basis, so the Black Mountain one we're hoping to be on the agenda for the August open meeting with LPSCo hopefully being able to be on the September open meeting assuming that's the case those rates, those new rates go into effect on the first of the month following the open meeting, so Black Mountain would be September 1 and LPSCo October 1.

We're hoping for an ALJ ruling or decision recommendation early September?

Correct.

That's good. Just shifting to Manitoba for a second, you have mentioned I think there was an environmental approval received for expansion of St. Leon. I am wondering what the process is there for actually getting a contract on such expansion?

That's obviously the next step in the process. The nice thing is we now have sort of fully permitted, fully technically feasible project, and now we -- and we are continuing but now it is the process is getting back to Manitoba Hydro. As you know they went through a few fits and starts and in terms of their own internal process it kind of didn't exactly unfold the way it originally hoped. Manitoba Hydro has continued conversations with us, and we are hopeful that project is -- I don't want to say it is a lay down, but because of the infrastructure which is already supporting it, the available grid capacity, it is quite an economically attractive opportunity, and so we're hopeful that will be apparent to Manitoba and we're able to either negotiate an extension or expansion of our existing PPA or even a new one, so you're absolutely right, Matthew, continue on and it is full court press in Winnipeg right now.

It doesn't have to necessarily be an RFP process, could be a one-off negotiation.

Absolutely. As I think the process that ultimately resulted following I won't say failed RFP because ultimately they did enter into a contract with one of the participants in the RFP, but I think we would all acknowledge that the process, the outcome of that was originally con seem plated in the RFP, and so I think we are confident and comfortable that Manitoba hydro, our prepared transfer into discussions rational discussions to look at fulfilling the expectations of the 600 meg watts they were originally seeking.

Great. Thanks, guys. Those are my questions.

Thanks, Matthew.

Your next question comes from Carolina Vargas from Clarus Securities. Please go ahead.

Good morning, everybody. Question related to APCo and your idea to support to promote Air Force to develop projects. I was wondering what kind of capital lease you're going to incur if any for that initiative?

For which?

APCo.

Go ahead.

Sorry, I didn't catch which project you're referring to?

Overall you said that projects that have BPAs you're going to try to help and develop the projects going forward in your opening remarks, and I was trying to get some clarity what kind of projects are you going to do and what kind of investment you're going to make if any?

Sure. I think we came to the conclusion and as owe outlined in our remarks last quarter and sort of confirmed this quarter, is that we believe that there is an opportunity to bring APCo's technical financial resources to bear to support some of the developers who may have won PPAs in the last round and some respects kind of like the dog who caught the car and what do they do with it, and we're hoping we can be part of that solution. Our primary focus given our development expertise is obviously on renewable resources, and our focus, so wind and hydro electric and not surprisingly BC and Ontario are two of the primary areas where those sort of opportunities exist, and I think all one needs to do is kind of look at the list of the award of power purchase agreements and both those jurisdictions to kind of get in some insight into our initial list for contacts. I think we have -- as I said in my opening remarks and can certainly confirm here, we have actively pursued that process. We are in discussions with a number of parties who are obviously examining their alternatives to bring their projects through to fruition in both the wind and the hydro electric side. Most of those projects as you can imagine are kind of between 10 and 100-megawatts worth of size. If you to get the sense of it, we are not lenders. I would point out that we are investors in projects and so it is not like we're chasing around opportunities to provide debt. We really do want to participate in the projects in a much longer term and more meaningful manner, and so this isn't about competing with the life co-s and the debt market. It is about being a solution for the equity needs of those facilities.

Okay. Thank you. And then the next question is a few weeks into Q3 now and if you can comment on the hydrology conditions for this quarter? Have you seen any improvement in the reservoirs getting a little bit more water?

Yes. It is Chris Jarratt. We are still seeing dry conditions in most areas. It has been a fairly dry summer, and the drought is quite widespread, but we are seeing a continuation of some of those conditions. We're not through the quarter so it is hard to quantify where we'll end up in the end. Regarding the wind, the wind resource at St. Leon which is our largest facility has returned to more normal conditions. We expect that to continue.

Thank you.

Your next question comes from Mat Gowing from Mackie Research. Please go ahead.

Thanks and good morning, everyone. You spoke a little bit in your disclosure about Red Lily two and the potential 106-megawatt expansion and you also include the caveat that expansion is conditional on performance of Red Lily 1. Can you just elaborate on what exactly you're looking for? Is it really wind conditions or is it more kind of the financial returns to that structure of investment on that project?

I think it is exactly the former rather than the latter. Part of the intention of construction of Red Lily 1 and if you looked at the placement of the turbines, you will see sort of counter intuitively widely spread over a large area, and that's to give us an opportunity to get some realtime monitoring of the wind production potential at the site, so what we're hoping to do is get Red Lily 1 up and going and nothing like having actual existing turbines on site to reduce the wind risk or resource risk associated with putting a couple of hundred million dollars into Phase II, so it is really about the production potential.

Thanks. Could you quantify the annual maintenance and operating fees associated with the ongoing operation of Red Lily 1?

We have entered into a long-term ten-year contract with [vestas] to provide kind of bumper to bumper if you want to think of it that way maintenance and operation expenses. I am not sure, it is a commercially reasonable contract, and I am just trying to recall if I am not mistaken I think it is in the CAD50,000 turbine per year range.

I don't have that number off the top of my head.

It is basically a commercially reasonable arrangement. The nice thing about it, it really takes care of pretty much all of the turbine operations and maintenance.

Great. Just one more question around the outlook for Sanger. You talk about how the outlook is for that plant to perform better than long-term averages in Q3 despite continued sluggish demand for hydro mulch and revenues there. Could you just discuss why you expect plant revenues to improve and provide some color around that improvement, please?

Sure. As you probably are aware, the Sanger facility actually consists of two things. One is an BLM 6000 powered [CC GT] generating station, and an off take thermal host is a hydro mulch production facility. Let's take the second first. Obviously in the hydro mulch business you're selling this product which is sprayed on the sides of the road and used as a construction product and with continued sluggishness in the US economy sales are down. The good news is that's a very small portion of the business, and so having those sales down isn't all that material. The Sanger facility and the reason we're expecting it to perform at or above long-term averages is that the BLM 6000 which a couple years ago was repowered onto the facility is performing extremely well, efficiencies are better than we had originally forecasted when we put the thing in. Down time is much less. We embarked on a relatively aggressive spare parts acquisition program which has shortened outages, so all in all that machine is performing extremely well both in accordance in comparison with our experience and also in comparison with the BLM 6000 fleet, so I guess it is a much larger element of the value proposition down in Sanger, so we're pleased that it is working well, and it is too bad we're not selling more hydro mulch but in some respects a bit of a side line.

Okay. Thanks very much.

Your next question comes from Michael McGowan from BMO Capital Markets.

Hi. Good morning.

Good morning.

I just have a question about the 80-megawatts wind facility you tendered into the feed and tariff program. Is there any reason that facility wasn't awarded a contract with the initial batch back in April?

I guess it was a bid process and it was a bid process we were not successful in.

And just actually just add a little bit more color to that, I think to be frank, in the first as we looked at it in the first time I am not sure we felt comfortable in the economics being able to not inquire the economic connection test. In this case as we have kind of further looked at it and further refined our economics, we subsequently submitted it on the basis of not requiring an ECT, and so I don't want to say it was a little late to the game but it really wasn't part of the first round of projects because we were grappling with the issue of whether we could -- whether the economics could support the required network upgrades. I think we came to the conclusion that we could, and so consequently submitted it without the ECT box ticked if you will.

So you will be required to actually perform grid upgrades in that region in order to connect that facility as well?

We will, and if you're familiar with the geography, you'll be aware that Amherst Island is literally across the sound if you will from the Lenox Oil Fire Generating Station that's owned by the OPG, and so consequently I think we're comfortable and this is what led to my remarks earlier about the facility and located in the area where connection availability shouldn't be an issue. I think we're comfortable that the upgrades if any are well within the capital budget for the facility. I would point out that one of the biggest issues associated with building a generating station on an island is the cost of the submarine cable to get it across to actually connect over to the other side on Wolf Island.

And do you own 100% of that project? Or would you be own with somebody?

We are partners with from a development perspective with a local developer based out of Kingston. Ultimately at the end of the day it would be a relatively significant undertaking and so from an equity investment perspective I think that we really think of Algonquin as being the sole provider of the better part of CAD100 million that may need to go into it from an equity perspective, and so but from a development fee perspective there are other participants, but we don't expect them to actually step up for the portion of the equity.

Okay. And can you provide maybe a timeline with respect to when you think the OPA will be in a position to finalize their review of that application?

You know what, I think to be frank, we're hopeful that it is imminent. They had the OPA had initially said that we're hopeful that 60 days might be a reasonable horizon for giving some response to some of these. We're obviously well past that, and so they have exceeded their own timelines. I am hopeful that they'll get back to us any day now, and so we are sitting there staring, waiting for the phone to ring. Not sure what else we can do. it is hard to push a little bit on a rope but we are hopeful and the project has been submitted some time ago.

So you would have submitted this in early June?

Oh, before that.

Okay. Great. Those are my questions.

Thanks.

(Operator Instructions) Mr. Robertson, there are no further questions at this time. Please continue.

Great. Thanks, everyone, for joining us this morning, and please remain on the line for the review of the obligatory disclaimer.

Certain written and oral statements contained in this information are forward-looking within the meaning of certain securities laws and reflect the view of Algonquin Power & Utilities Corporation with respect to future events based upon assumptions relating to among others the potential assets and the business, financial and regulatory climate in which it operates. These forward-looking statements include among other statements with respect to the expected performance of the Company future plans and dividends to shareholders. Statements containing expressions such as believes, anticipates, expects, may, will, project, and similar expressions generally constitute forward-looking statements. Some forward-looking statements relate to future events and continues by their very night require to us 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 the continued volatility of world financial markets, the impact of movements and exchange rates and interest rates, the effects of changes and 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 US economy and accompanying business climates. We caution this list is not exhaustive and other factors could adversely affected 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 participating. Please disconnect your lines.