Algonquin Power & Utilities Corp (AQNU) 2012 Q2 法說會逐字稿

Good morning, ladies and gentlemen and thank you for standing by. Welcome to the Algonquin Power & Utilities Corp. Q2 analyst and investor 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.

(Operator Instructions)

I would like to remind everyone that this conference call is being recorded today Friday August 10, 2012 at 10.00 AM Eastern time. I will now turn the call over to Mr. Chris Jarratt. Please go ahead, sir.

Thank you. Good morning everyone. My name is Chris Jarrett and I am the Vice Chair at Algonquin. I would like to welcome you to our 2012 second quarter results conference call. With me on the call today are Ian Robertson, or Chief Executive Officer, David Bronicheski, our Chief Financial Officer, and Kelly Castledine, our Director of Investor Relations. For your reference additional information on our result is available for download at our website, AlgonquinPowerandUtilities.com.

I'd like to note that on this call we will provide information that relates to future events and expected financials position that should be considered forward-looking. And Kelly will provide further details on this at the end of the call. In a few moments, in addition to discussing the highlights for the quarter, Ian will also touch on the recently announced acquisitions of two additional regulated utilities in the United States. David will follow with a review of the financial results, and then we will open up the lines for questions on both the results and the recently announced acquisitions during the question-and-answer period. I would ask that you restrict your questions to two, and then requeue if you have additional questions to allow others the opportunity to participate. And with that I will now hand it over to Ian.

Thanks, Chris and good morning, everyone. Thanks for taking the time to join us on the call. As you know we've been busy in recent weeks with a number of announcements regarding the current and future expansion of both our power and utility operations. In Liberty Utilities, we were very pleased to have successfully closed the acquisition of additional operations in New Hampshire, Missouri, Illinois, and Iowa over the past month or so. The closing of these transactions marks a significant milestone in the continued growth of our regulated distribution utility in the United States, and together with the recent announcements our customer base will be well over 400,000 connections ensuring that Liberty Utilities has the scope and scale to provide reliable high-quality local and responsive service to all of our utility customers, regulators, and employees.

Before I begin with highlights of the recent acquisitions, I would like to take a moment to touch on our announcement yesterday regarding the Board of Directors' decision to increase Algonquin Power & Utilities Corp. or APUC as we affectionately refer to it, annual dividend by CAD0.03 to CAD0.31 annually. We have recently completed several power and utility acquisitions that will contribute significantly to the earnings and cash flows and yesterday we announced two additional utility acquisitions which our firms are continuing growth trajectory. Following our strategic planning session, which is held annually at the midpoint of the year, the Board believes that in the context of the profile of our earnings and cash flows including the expected contributions from these recently announced initiatives, an increase of the dividend was appropriate.

We are pleased to have been able to deliver these growth initiatives and believe that the dividend increase is consistent with our strategy of providing total shareholder returns comprised of attractive dividend yield and capital appreciation founded on dividend growth underpinned by increased earnings and cash flows. As you will have seen from our press release on Wednesday, Liberty Utilities continues to grow with the announcement of our agreement to acquire two regulated utility operations -- a water distribution system in Arkansas, from United Waterworks Inc., and two natural gas distribution systems in Georgia from Atmos. We believe that the approximately $19 million in near-term aggregate EBITDA from these systems will positively grow per-share earnings and cash flows and the EBITDA to purchase price multiple of less than 9 times represents accretive enterprise growth.

The Georgia utilities systems provide local natural gas distribution service to approximately 64,000 customers in the state of Georgia and is the result of the constructive and positive relationship we developed with Atmos Energy Corporation during the recently completed Missouri, Illinois, and Iowa gas acquisitions. The purchase price for the Georgia utility systems is approximately $140 million, and we expect to acquire net property plant and equipment assets of approximately $128 million, representing an attractive purchase price multiple of approximately 1.1 times. The transition of these utilities to Liberty's operations will be materially eased by the familiarity of our transition team members with Atmos's processes and systems gained over the past year of working side-by-side with their counterparts within Atmos.

The Arkansas utility system provides regulated water distribution service to approximately 17,000 customers in the state of Arkansas. The purchase price for the Arkansas utility system is approximately $29 million and we expect to acquire assets for rate making purposes of approximately CAD25 million representing a purchase price multiple of approximately 1.16 times. Through its reasonable proximity, we expect our Texas operations to support the transition of the Arkansas system to deliver to utilities family.

Closing of these acquisitions are subject to receiving the necessary state and federal regulatory approvals. As recent experience has taught, it is difficult to accurately predict the timeframe to securities approvals. Consequently, for discussion purposes we would suggest mid-2013 for inclusion of these facilities. Financing will occur simultaneously with the closing of this transaction. We believe that these acquisitions affirm our ability to continue to execute on our growth strategy, referred to somewhat tongue-in-cheek as, save the orphans, pursuant to which we source high-quality system assets from larger utilities to add to the Liberty Utilities operation.

Now, just touching on the power side of our business, we recently closed the acquisition of a 51% interest in the 50-megawatt Sandy Ridge wind farm in Pennsylvania. This is the first of three wind projects we expect to acquire in the United States from Gamesa following the successful commercial operation of each of the plants. Parenthetically, and as noted in our July press release, in the alternative to acquiring an interest in a fourth Gamesa project, the Iowa-based 80-megawatt Pocahontas Prairie project, under our amended agreement with Gamesa, we expect to increase our interest in the Sandy Ridge, Senate, and Minonk projects to 58.75%, preserving our total investment value of approximately US $270 million. We believe that this change has materially positive impact implications for the risk return profile of the overall investment by reducing exposure to the volatility and pricing challenges currently faced by the US electricity environment. With that I'll now turn it over to David Bronicheski, our Chief Financial Officer, to speak to the financial results of the quarter.

Thanks, Ian and good morning, everyone. As we look at our financial results for the second quarter there were really three things that affected the results. First, the naturally occurring effect of the hydrology resource compared to the comparable period the year before resulted in a CAD2.5 million decrease in revenue. Secondly, while mostly offset by higher commodity demand in our Liberty Utilities South region, our regulated utility operations in California experienced reduced electricity demand. And finally with the Windsor Locks repowering project not being completed until the end of the quarter, we suffered the reduced power sales impact of the challenging market conditions at our Windsor Locks facility.

Overall our revenue for the quarter was CAD65.4 million as compared to CAD64.4 million in the first quarter of the year. Our adjusted EBITDA for the quarter was CAD24.9 million compared to CAD23.3 million in Q1 and our adjusted net earnings was CAD6.9 million as compared to CAD5.5 million in the first quarter of 2012. And now a bit more detail about our operating subsidiaries beginning first with Algonquin Power Co. or APCo. During the second quarter, in total APCo reported an operating profit of CAD21 million compared to an operating profit of CAD22.4 million during the same period a year ago, a decrease of CAD1.4 million primarily as a result of lower hydrology.

Now, renewable energy division. During the second quarter, net energy sales totaled CAD22.1 million as compared to CAD23.2 million in the same period a year ago representing a decrease of 4%. During the quarter the division generated electricity equal to approximately 96% of long-term projected average wind and hydrology as compared to 106% in the same quarter last year. Above long-term average resources in some regions, particularly Manitoba and Saskatchewan, Western and the Maritime regions, offset below-average hydrology in other areas, primarily Ontario, New York, and New England. Again, demonstrating the value of the regional diversification in our renewable energy portfolio.

For the second quarter of 2012, operating profit totaled CAD17.2 million as compared to CAD18.1 million during the same period in 2011. In our thermal energy division, it came in below our expectations for the quarter posting an operating profit of CAD3.8 million compared to CAD4.3 million during the same period a year ago. The decrease is mainly due to decreased production at the Windsor Locks facility due to the facility being off-line for most of the month of May and June as we installed a new turbine at the facility that is optimally sized to meet the steam requirements of the mill, which will then insulate that operation from the challenges and volatility of the merchant energy markets, and also, as a result of reduced revenue from the Sanger facility, as a result of that facility being off-line in April due to a planned major maintenance.

Our Sanger facility returned to full production effective May 1, and consequently in the third quarter our results will reflect having returned that facility to service for the full quarter. At Windsor Locks, we've now completed the repowering of that facility in July, and this will reduce the earnings volatility experienced by the facility for market-based energy pricing.

Looking ahead to the next quarter for the third quarter of 2012, our 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 regions that are expected to perform below our budgetary expectations for the year due to the continuing challenges of operating at a merchant energy market with merchant energy pricing to which these facilities are exposed. The thermal energy division's Sanger facility, as I mentioned, returned to full production in May following a shutdown for a transmission system upgrade undertaken by PG&E as well as we took the opportunity to make additional upgrades to the plant to accommodate the higher voltage. And the facility returning to service will now show full results in the third quarter.

At our EFW facility, the waste supply agreement with the Region of Peel has been extended through October 2012; APCo is now entering into contracts for alternative waste streams for the facility to ensure continued operation of the facility following the end of the current contract. We are pleased to have closed the acquisition of Sandy Ridge and that will generate additional revenue and EBITDA for APCo in the third quarter. Moving on to Liberty Utilities, during the second quarter in total, Liberty Utilities reported an operating profit of CAD8.8 million compared to the CAD9.2 million reported in the second quarter a year ago. Our Liberty Utilities South region continued to be a steady Eddie, and perform quite well. Liberty Utilities South wastewater treatment connections grew by 1.5% and the water distribution connections grew by 4.6% over the number of connections at the same time a year ago.

Revenue for the second quarter of 2012 came in at CAD12.2 million compared to CAD11.9 million during the same period in 2011. Water distribution and wastewater treatment revenue increased primarily as a result of increased customer connections. Liberty Utilities South operating profit for the second quarter of 2012 was CAD6.2 million as compared to CAD6 million a year ago. In the West, our Liberty Utilities West utility being a winter peaking facility was affected by a milder spring weather which reduced energy consumption by about 13%. Net energy sales revenue for the second quarter of 2012 totaled CAD6.1 million as compared to CAD6.9 million in the same period in 2011. The operating profit in the West was CAD2.6 million as compared to CAD3.2 million for the same period a year ago.

As we look to the next quarter for Liberty Utilities we are expecting continued modest customer growth in 2012 throughout our service territories, and we are pleased to have closed the pending acquisitions of Granite State Energy North and the Midstates Utilities and look forward to reporting these results in our Liberty Utilities division next quarter.

I'd now like to take a few moments just to review our recent financing activities, another busy quarter for us. During the second quarter, APCo received commitments from its banking syndicate to increase the credit available on our banking facility from CAD120 million to CAD155 million. And the increase in the facility will be sufficient to fund the requirements and working capital needs associated with APCo's planned capital commitments for the balance of 2012. On the Liberty Utility side we put in place a master debt platform to support our utilities businesses. This debt platform will allow Liberty Utilities to easily source new debt as required to fund the growth in the business over time.

We received commitments for a $225 million private placement debt financing as the first financing to be issued off of this new platform. The financing was closed subsequent to the end of the quarter in two tranches associated with the closing of each of the New Hampshire and the mid-states acquisitions. We believe the terms achieved for the notes are very attractive for rate payers. The notes are senior unsecured and have an average life maturity about just over 10 years and a weighted average coupon of 4.38%. I'd also note that these notes have been assigned a rating of BBB high by DBRS. I'll now hand it back over to Ian.

Thanks, David and with that, we'll get to the really important stuff and I'd like to open up the lines up for our question-and-answer session.

Thank you. Ladies and gentlemen, we'll now conduct a question-and-answer session.

(Operator Instructions)

Juan Plessis, Canaccord Genuity.

Congratulations on the recent acquisitions.

Thanks.

You mentioned in your MD&A that the thermal division didn't meet your expectations for the quarter and for the year. Was that just due to the outages at Sanger and Windsor Locks or was there something else going on there? And how much did this division miss your expectations?

No, I think the biggest quote, miss, from an expectations point of view were the challenges generally in the Windsor Locks facility. I don't think the outages at Sanger and at Windsor Locks were unplanned. In fact, they had been planned long in advance.

So I think really, when we prepare our budget back in the fall of 2011, for 2012, we make certain estimates of what spark spreads are likely to be and how many hours we're going to be able to operate that three and six turbine down at Windsor Locks. And at the end of the day, obviously it is what it is from a market perspective and those are very difficult to predict. And so to the extent that they've very positively or negatively from the assumptions we made back during our budgetary process we obviously report that as variances.

I would point out that it's a particularly unsatisfying way in general to run the business and it was -- really, that's the primary driver to the investment in the facility to insulate ourselves from that process going forward. That really, frankly from this day forward for the next 15 or so years, we will have much greater predictability as to the revenues and expenses incurred by that facility given that we now have a turbine which is appropriately sized just to serve the needs of the Ahlstrom mill. And to the extent that the merchant electricity prices market do or don't support additional generation and will be something that we'll be forced to generate into, which given the size of the framesticks, we are right now. I don't know if that answers your question, Juan.

No. That gives me a lot of clarity on that. Also in the MD&A, there's some mention that the water utility assets in Liberty Utility South will be reported in Liberty Utilities West beginning in Q3? Does that mean that there won't be any utility operations in the South after this move occurs? And is this where the Georgia Natural Gas utilities will be placed once the acquisition is closed?

I think it really just speaks to a continued, I don't want to say, realignment, but as the footprint of our businesses in the US and speaking obviously to the utility businesses grows, we are sort of standardizing on three regions -- a West, a Central, and an East. And so when you think of the West, California and Arizona would naturally be part of the West. As you think about the Central, and the central swath of the country, you can imagine Missouri, Illinois, Iowa, Texas, Arkansas, and likely Georgia. And in the East, it's currently New Hampshire.

So really think of it as more of a consolidation management tool, rather than any fundamental change. I would point out that just in general, given our proposition of this kind of local and responsive relationship we try to foster with regulators and our customers, we actually very much manage our operations on a state-by-state basis. And the regions are as much for consolidation reporting purposes, rather than actual management perspective., So I really think it's about just trying to consolidate a growing footprint into some manageable regions, Juan.

Okay. Thank you very much.

Thanks.

Rupert Merer, National Bank Financial.

Wondering if you can give us an update on the Amherst Island wind project. I didn't see much discussion about in the MD&A. How is the development progressing and what are the key milestones for that project?

Engineering work is continuing. I think the next big milestone for us is getting our re-application filed. And we are working on some final geotechnical and archaeological work associated with that. We expect to have the re-application in mid-fall.

So look, we're continuing on our consultation process with the stakeholders, and that obviously includes the communities. So we haven't hit any milestones. Work has continued to progress, Rupert, and I think we're pleased that -- certainly one of the things we're obviously pleased at is the continued changes in the turbine pricing environment in which ultimately we're going to be sourcing the turbine. So I think it's all good.

Okay. Great. And looking at the acquisition of utilities in Q3, we saw a small increase in admin costs in Q2.

At the end of Q2, do you feel like you have all the infrastructure in place to manage the new acquisitions? Or do you expect admin cost to increase creep up anymore? And also looking at the infrastructure requirements, how should we expect working capital to move in the next quarter?

Well, Rupert, this is David Bronicheski. As far as the admin costs go, I would say if we were in a steady state, the admin costs that we see in Q2 are likely quite consistent with what we would expect over time. But I will simply say that we continue to grow the business. And as we continue to grow the business, there will be increased needs for additional administrative costs.

So I think yes, if we were in a steady-state, this is where we would expect to be. But I just highlight that we're not really in a steady-state, so over time, I think you can expect to see the admin costs grow. But I would say less than proportionately with the growth in the acquisitions, because obviously there is some efficiencies that are gains with that. So hopefully, that addresses your question.

Yes. And working capital, do you expect much of a change in Q3 with the acquisitions?

Well, the gas utilities represents a different element for us, because there is a working capital element to gas utilities that certainly doesn't exist in water utilities and even for that matter, electric utilities, because there is a storage element to the commodity associated with gas utilities. So as we move into the fall, we do expect that we're going to have to be storing more gas. And so that will obviously have some implications for our working capital requirements.

Thank you.

Nelson Ng, RBC Capital Markets.

Just in terms of some background on the two acquisitions, was it a competitive process, or was it more of a negotiated deal?

In both cases, I'd argue they were a negotiated deal. Let's just start with the Georgia one because it simpler.

We have obviously had a close relationship with the Atmos guys for over a year since we announced the first acquisition of Missouri, Iowa, and Illinois, and that was not a competitive process. It was a negotiated arrangement and educated arrangement, and through discussions and -- we reached agreements with Atmos that adding the Georgia assets to the disposition from their perspective and acquisition from our side made sense. And you can see that there was consistency with the pricing of those. And so it was definitely a negotiated process.

With respect to the United Waterworks disposition, of the Arkansas side plus utility, while they ran a process, it was run internally from their perspective. And I think it was -- I would say is was largely negotiated while they had solicited other bids. We spent a lot of time with United Waterworks to get the transaction in a form that made sense from their perspective and from ours.

And so I think I'd probably put them both in the negotiated category, though United Waterworks did obviously solicit some external participation.

Okay. Thanks. And then in terms of the achieving your approved ROE, just from the description from the fact sheet, it looks like you should be achieving the approved ROE for the Georgia utility. But could you comment on the Arkansas water utility, whether you expect to be achieving the approved ROE or whether you expect a rate case filing to increase revenues?

We certainly expect periodic rate cases in Arkansas in a manner which is not dissimilar to all of our other utilities. I think you accurately point out that Georgia is a somewhat unique jurisdiction in that they have an annual true up of revenues to drive ROEs within a band around the approved ROE, which is 10.7% standard, plus or minus 20 bps. In Arkansas, the ROE which was approved last time is 10.1%.

Obviously, as we continue to invest in that utility going forward, we would expect to go in for periodic rate cases. I think the 10.1%, there's no reason why that won't continue on. And if your question is do we anticipate a rate case in Arkansas, it would just be normal course requirement to address increases in cost and continued investment. And based on our forecast right now, that might happen in 2014 or 2015, just from a forecast perspective.

Okay. Thanks. I'll get back into the queue.

Thanks, Nelson.

Ben Pham, BMO Capital Markets.

Just going back to Pocahontas, just your comments about risks and returns there. I'm just curious, when you look at potential contract there, with Gamesa looking at the that. What type of length of contract and type of counterparty that you would be happy with in terms of meeting your risk and return profile there?

Well, let me start by saying I think our expectation as we go into it at this stage, if I had to handicap the outcome, we actually won't be acquiring an interest in Pocahontas at this stage. And that we have entered into agreement with Gamesa to increase our interest in the other three projects to 58.75%. And I appreciate their -- I would say that's still a fork in the road to which we will be coming. I expect that fork, that we'll be taking a fork which has a larger interest in the three projects.

But to specifically answer your question, I think we would be looking for a credit-worthy counterparty, so you think of the counterparties we have in the current arrangement, of JPMorgan, think of tenor, and we probably have an average of 12.5 years. If you want to think of it that way on the rest of those projects.

And so I don't think we would really want to look at anything that was materially different than that. I think our objective in our discussions with Gamesa was to pick up and improve the risk return profile, particularly in the context of the continued volatility and the merchant energy markets in the US. And so I think if we were to acquire an interest in the Pocahontas project as I mentioned that's probably the low probability approach, it would have to be consistent with the terms of the other three projects. I don't know if that helps shed some light, Ben.

That's very helpful. And on the Georgia acquisition you talked about the allowed ROE's there, I wanted to double check -- you do list CAD128 million in terms of PP&E. Correct me if I'm wrong, I think rate base is a little bit lower than that. I think it's about CAD100 million or so.

And just to answer your question, rate base is obviously unique to the owner of the assets in the state of Georgia. And since this is an asset transaction and not a share transaction, we'll be creating a brand-new utility and we'll be acquiring that CAD128 million worth of net PP&E and that will be in, if you will, the opening balance sheet that we will have as a utility.

In terms of rate base if you want to think of it that way, from Atmos' perspective, obviously that's combined of a whole bunch of regulatory assets and regulatory liabilities which net out to be CAD105 million or CAD107 million as you accurately point out. Our opening balance sheet, which won't have any of those regulatory assets and liabilities associated with it will have the entire CAD128 million on it. And that probably is the difference between the two. It's really, as a matter of course, as a result of an asset transaction rather than a share transaction.

Okay. That's very helpful. Thanks a lot.

Matthew Akman, Scotiabank.

Ian, just to follow up directly on that question, what would you anticipate as timing for rates case to go in and actually get that new asset base/rate base approved?

Well, this is the interesting aspect of the whole Georgia regulatory environment. In effect, you do instantaneous annual rate cases, Matthew, that as a result of something some the called the Georgia Rate Adjustment Mechanism, or GRAM filing, which gets done in October of each year., Your then current assets, operating expenses, all get trued up and your revenue requirement gets set and put into effect in February of the next year.

And so we would expect our first GRAM filing -- and you can imagine the timing so you can imagine it plus or minus 11 months if you want to think of it that way, just because of the timing of it. But we would get in pretty promptly as a result of this whole regulatory construct. And so you would think it would hit in pretty short order.

So maybe October 13, depending on when it closes?

The rate's go into affect in the February of the following year, so I would imagine our first GRAM filing would be in October of 2013 with rates in effect in 2014. Which as you can appreciate from a regulatory lag point of view, is actually pretty short.

Right. Sticking with the Georgia acquisition, how do you plan on handling customer care for that utility? For those utilities?

We're going to do it in the exact same way as we do all of our other states as I mentioned in response to, perhaps it was Juan's question, that we look at our operations on a state-by-state basis. And so while we have a centralized delivered CIS system, the CSRs that we have answer customer calls are actually located in the state offices. And so this is part of the proposition that we advanced to all of the regulators in terms of these acquisitions is that we are repatriating jobs and just as we did in Missouri and Illinois. We are repatriating customer care jobs that are currently in Waco, Texas, back to into the state. So it will be done just the way we're doing it in Missouri which is local CSRs, local customer care, Matthew.

Okay. Thanks for that.

Shifting for a second, wanted to talk about renewable acquisitions. In particular, Western Wind. Western Wind obviously has been out there. You guys were mentioned publicly as being involved in that previously.

I don't know how much you can comment on this, but now that you've done the Gamesa transaction anyway, is Western Wind in principle something that you'd still be interested in? Or that kind of acquisition or do you have enough now on US wind with Gamesa?

I think we continue to be interested in contracted renewable generating assets. And so to the extent that Windstar and perhaps some of the other Western Wind assets came to market in a legitimate process, we would be interested in pursuing it. And to be frank, I think we're endorsing -- and I'll just call it the, dissident shareholders -- approach to managing that process.

Okay. Thank you very much, guys. Those are my questions.

John Safrance, M Partners.

With respect to just the Georgia acquisition again, historically how have ROEs trended there? And how regular is the process in adjusting those ROEs and when might we expect to see that next?

It's a great question. The ROEs, I mentioned to Matthew's question about how the revenue requirement is set on an annual basis, that doesn't change some of the fundamental constructs of the rate of care, such as ROE capital structure, that sort of thing.

So on a reasonably periodic basis, and from our perspective, we think of this as every three or four years, we would be going in and making the application to have ROEs and capital structure reflect our current thinking. But I think our expectation is we will assume the 10.7% that was recently given to Atmos for the foreseeable future, but certainly until we get and complete a full rate proceeding. So I think for the purposes of your analysis over the short term, that 10.7% would be expected to continue.

Okay. Thank you. And just on the ESB business, year-over-year, it's a little difficult to read through the tea leaves a little bit but can you compare performance there? I noticed that you had a fairly large relative increase in the pass-through cost there. And was the return on that business commensurate with what you did last year?

Well, our Energy Services Business is there primarily to support the energy sales of that exist in our Tinker facility, although they do help to also support some of our other facilities. And so they enter into, say, a multi-year contract to supply electricity. And then in order to make sure that we're supplying that electricity at a profitable basis, they will go in and they will enter into some hedges to ensure that we're we are able to meet that with a predictable margin.

And so that's the way the Energy Services Businesses work. And the Tinker facility then can respond to increases in the retail demand. So a long answer to basically the Energy Services Business is performing as we expect it to.

Okay. Thanks. And one final question for me and my apologies if I missed this in your comments but how is Minonk and Senate progressing with respect to a Q4 commissioning?

As you know, not our risk, obviously, that's a development risk that's being worn by Gamesa. But our development team are on weekly update calls with Gamesa and I wouldn't say fingers crossed because it's not a luck thing, but the current plan shows that they're going to get it done in time. So that's all good.

Okay. Great. Thanks very much.

Thanks, John.

Robert Whiteley, Macquarie.

Just a clarification question. Can you clarify the regulatory assets for rate making purposes at Georgia? Is it the CAD107 million figure you mentioned or closer to the balance sheet figure?

For rate making purposes, it would be the CAD128.1 million. That rate base, Rob, raw figure, that number was really actually taken from Atmos's press release. And if you want to think of it as that was what they had on their books, which reflected a whole pile of regulatory assets and liabilities, obviously primarily liability since its lower than CAD128 million, that we wouldn't be assuming and won't be coming to us as part of the transaction, just as a matter of course because it's an asset transaction. So I think for the purposes of your analysis, the CAD128 million is the number that we're obviously buying, net PP&E, that will be on our books, that's the opening balance sheet for us.

Thank you. That's how I interpreted the response. Just on the EFW waste facility, what progress are you making there in terms of re-contracting the capacity that you'll have available there? And maybe can you give us some color on that in terms of how much you've contracted to this point and the relative change in rates?

Sure. It's Chris Jarratt here. Yes.

We were able to extend the existing contract by six months, which gave us time to out and source a different waste stream and we've been working very hard at that. And I would say we've been making very good progress at that and we fully expect to have the waste stream fully sourced by the end of the existing contract at the end of October. There's so much waste in this area that I don't think that's a problem. The issue is of course the price, which you point out.

And the price at the start will be down slightly from what we were expecting from the Region of Peel if they were to extend the contract. But the other good thing we've been able to do is identify a number of, what we call, high-value waste streams. And these are people who have waste that they're paying a significant amount for non-hazardous medical waste and product destruction, things like that. So we have identified a number of those as well as a couple of municipalities, fairly close. So over the longer-term, we expect to increase the rates that we'll get back to what we would get, what we expected from Peel.

Okay. So time will tell on that one, then? Finally, on -- you took the ITC wording out of the Windsor Locks description. Is that still on the table or do you no longer think you'll get that tax credit?

No. In fact, we fully do -- great catch, Rob, in some respects it was a bit of an oversight deletion from our perspective. There's nothing that has led us to believe that we won't quality for the ITC.

Perfect. Thank you, guys.

Thanks, Rob.

Bill Cabel, Stifel Nicholas.

Congrats on the acquisitions.

Thanks, Bill.

Previously on your acquisitions, you've announced a co-investment by Emera at a stock price above market. This time you didn't do that. Is this a shift, or how do you see that unfolding?

No, I think it actually probably represents probably more significantly just the growth in the size of the organization, perhaps the relative size of these acquisitions in the context of the larger organization. Our relationship with Emera, I won't say obviously because we obviously have insight that you don't, but it remains strong. As recently as last quarter they have announced their additional subscription receipt for a couple of the transactions that were announced back then or were pending back then.

The Emera has gone and filed application in the State of Maine to get that last 5% authorization to increase their ownership up to 25%, which would give them, in the context of that CAD60 million or CAD70 million of headroom. Maybe the back-ended question is, how do you think about financing those acquisitions going forward?

Yes.

I won't say their relatively small, obviously CAD170 million is significant, but when you look at it in the context of the organization, we think there's three ways that we could finance it. First and foremost, it's obviously between now and a year from now when these acquisitions close we will have internally generated cash flow. Second of all, I mentioned that we do have the continued relationship with Emera and that regulatory process in Maine is expected to be completed within six months, so that's going to be a flexibility we have. And the last one that we shouldn't lose sight of is, the balance sheet is relatively robust from an equity perspective.

I think with the conversion of the existing series of CDs from CAD62 million, poised to occur in January of next year and shifting CAD62 million from the liability side to the equity side of the balance sheet, we'll have a relatively unlevered balance sheet. Which we could, I won't say quite easily, but I think if you do the math you'll see that we have the capacity to borrow a fair chunk of the needs of those acquisitions without changing our debt to total cap fundamentally from where it is today.

And so I think -- as you and I have spoken, I think this is exactly the situation that the capital markets want us to be in, where we won't have a need to have to come to the capital markets based on anything that we've announced. And so I think those levels of flexibility exist, if that's where your question was headed, Bill.

That's great. And one last question. With the Gamesa expected to close the second phase mid-next year and now these two acquisitions expected to close in the same sort of timeframe, maybe talk about your appetite for continued growth and how you view that going forward?

Well, let's talk about the utilities side of the growth equation. We've built an organization, we like to think, that has a core competency of pursuing regulatory acquisitions and the transition of additional utilities into the portfolio. And it's important, given the protracted nature of the regulatory approval process and frankly the transition process that we, if you will, stagger those things going forward. And so we continue to be on the hunt. Don't expect to announce anything next week, but we will continue to try to keep the pipeline filled, if you will, so that that group of individuals who are focused on that transition work have their next group of assets to work on.

On the power side of the business, as you know, our growth is a combination of acquisition, a la Gamesa, but also our own development projects. In Quebec, our St. Damase project is proceeding on schedule, our Cornwall solar project is proceeding with COD expected next year. And so I think the organization will continue on on the growth trajectory. And so I think that is part of the proposition. And I think we're confident and comfortable to say that life will continue on along those lines.

Okay. Great. Thanks. Those are my questions.

All right. Thanks, Bill.

Matt Gowing, Mackie Research.

There's a difference in the wording with respect to the Georgia and the Arkansas utility acquisitions in the fact sheet. For Georgia you say there's opportunities for continued growth in capital investment. And then on Arkansas, it says opportunities for just follow-on capital investment.

Wondering if you could provide any color on why the difference in wording there. And on the Georgia side, what are you thinking is the growth opportunity there beyond just capital investment and rate increases going forward?

Well, let me start, Matt, by saying you have a way more critical eye for wording than I would have thought. But, let's spend a little bit of time on the growth opportunities.

Arkansas is -- it's not a high-growth town. There are some new homes being built. I think the investment opportunity that exists primarily within the Pine Bluff Utility is capital replacement. United Water, who sold that utility to fund capital needs to our knowledge anyway, elsewhere in their portfolio of assets, I think there are opportunities to replace capital that needs to get done. So I think the primary reinvestment opportunity in Arkansas relates to the existing system and replacing old with new.

In Georgia, actually not so much. I think there is two opportunities. One is down in the Columbus, Georgia area, there is significant growth going on. You may have read 20,000 troops and their families are being moved from the Fort Knox area down to the Fort Benning area. And so those families and all of the ancillary spinoff businesses that are associated with that are coming into the area. And so new home construction, we toured the service territory, there are subdivisions going up.

So in addition to the robust-type replacement program in Georgia, which is really about reinforcing replacement of the existing infrastructure, there is growth going on. So I think both of the utilities -- and we were talking a little bit earlier from a forecast perspective, should, I think, reasonably from a modeling perspective, should show continued modest growth in rate base going forward. And I don't think anyone would be disappointed if the rate base assumption showed at least inflationary and perhaps even inflationary across a couple of hundred basis points would probably not be unreasonable certainly over the next while given what we see as investment opportunities within both of those utilities.

Great. Certainly something to be excited, be involved there in Georgia.

While we're on the topic of modeling, in terms of EBITDA margins as a percentage of sales, would we be safe to use the similar levels that we're using for, using for, say, Granite State and Energy North? I think Northern Grid had provided some financials on those items, so I'm wondering if the margin profile as a percentage of sales would be similar for the new acquisitions as previous ones?

Well, we tried to give a little bit of guidance in both of those fact sheets and even in my prepared remarks, for both of those acquisitions, that in near term, and I mean immediately following closing, CAD19 million of EBITDA from both of those acquisitions on an aggregate basis is probably not unreasonable and that's consistent with current operations. And so I don't know if that's where your question is going, but I think that's probably not an unreasonable modeling starting point.

I think as Matthew Akman asked, the Georgia construct, this whole GRAM filing and the nature of the regulatory environment, provides the opportunity for a relatively regulatory lag lift ability to actually have revenues and therefore EBITDA reflect full earning. And so from a modeling perspective, it's probably not unreasonable to take that CAD19 million and move forward to a full earning basis certainly as the portion relates to Georgia.

In a relatively short order, we talked about 2014, 2015 as a number. I don't know if that's where your question was headed.

I'm just trying to get a better sense of the pass-through revenues? And if you have an idea of, rather than say the absolute number of EBITDA, just roughly if those 12% and 18% EBITDA margins as a percentage of sales would be decent numbers to go with.

Yes. They probably are. We tried to give a little bit more guidance. I think we had indicated on our fact sheet in Georgia that it's 9.1 million decatherms of natural gas gets sold. You can actually back your way into -- the only difference if you want to think of it that way, at least on the revenue side, is the cost of gas and the cost of operations.

The cost of operations, I think you're totally fair from a modeling point of view to be consistent with some of the other operations. There's nothing in terms in the operating in the State of Georgia which would make it materially less or more expensive. And from a gas perspective if you actually want to model right up to the top line, take 9.1 million decatherms of gas and factor in market price for that gas at CAD3 and you can back your way into the top line revenue as well, Matt.

Great. And one last modeling one for me. I guess the cash taxes have been fairly minimal for Algonquin Power on a consolidated basis for the past several quarters. How should we think about cash taxes going forward in light of a lot of these acquisitions and capital investments that you're making? At what point should we see a normalized cash tax rate?

Matt, David Bronicheski here. As far as the cash taxes in our regular investor presentation, we do have a slide that provides some color on that.

And I think the big picture, I think the way to think of it is for the power side of the business, basically not going to be in a cash tax position for arguably the next 10 years. When we did the transaction to convert to a corporation, we did it by way of a reverse takeover of a corporation that had significant tax attributes contained within it. And so we are able to take advantage of that.

On the utilities side of the business, the taxability horizon is shorter. Currently we're expecting to be tax-free to the end of 2015. And clearly, we look at that on an annual basis. And sometimes even more frequently to see if there are opportunities to push out that taxability horizon a little bit further.

But if you're asking a question specific to if I was modeling it out, so to speak, I would say as you look at the utilities side of our business, slotting in some cash taxes to be paid beginning in 2016, and on the power side of the business, beginning in 2022, 2023.

Thanks, David. Very helpful. Thank you.

Ian Tharp, CIBC World Markets.

Many questions asked and answered already. Just a brief observation on Liberty South, a question on the wastewater connections. I noticed they dropped quarter on quarter. You had an increase in vacancy there. So just wondering if you expect that trend to continue or will it normalize to a standard growth rate as you see in your other utilities?

Let's put it this way.

I think the more relevant comparison, rather than look Q1 to Q2, because there is some seasonality within the Liberty Utilities South due to the snowbird factor. And so we'd say that the more relevant factor is to look at the year-over-year and look at the Q2 customers this year compared to the Q2 customers last year. And if you look at that on the water side, the water customers a year ago, we ended the quarter with 37,930, and we ended this quarter with 39,700. So that was a 4.7% increase in the water customers there.

And the wastewater customers, that base grew by about 1.5% year-over-year. So I would say the right comparison is year-over-year, just given the seasonality that exists in that region.

And, it's Ian speaking, just to paint a macro picture over top of that, we are seeing continuing -- believe it or not -- housing starts and growth in homes. And so I think that's the basis of our suggestion and assertion in the MD&A that going forward modest growth appears to be the order of the day.

Great. We're definitely seeing that in other spots as well. Helpful, David. Thank you.

And then going back, Chris, to your comments around the EFW facility, I noticed you also had supplemental waste used in the quarter as you did in Q1. So first, if you can talk about that proportion of supplemental that you used in Q2. And then if you're able to give us some kind of order of magnitude in terms of the price decline you're seeing on tipping fees for these new contracts your signing post the Peel contract expiring.

Yes. Just on the price declines, I don't really want to give a whole lot of guidance on that right now only because we are finalizing a lot of contracts right now. So as I said, we do expect a decrease, initially. But in relatively short order we expect that to move up.

Okay. And following on that, you talked about these high-value waste streams. Is there any permitting or otherwise that you have to get for your facility in order to process these types of waste?

It's not so much the types of waste as it is the location from where it comes. And we are engaged in an approval process right now which we also expect to coincide with the end of the existing contracts.

Okay. Great. And just finally, we talked a little bit about a merchant risk around Pocahontas. It sounds like that's putting that transaction in jeopardy, but you've got call it, a quarter of your remaining assets there, of American wind still exposed to market rates.

So I wonder is there a thought in -- over the longer-term to attempt to contract those out, even for shorter periods, two years, five years? Or are you looking more at the option value of selling into the merchant market through your services business as the upside there?

I think our general approach to risk, Ian, is probably the former rather than the latter. The latter kind of feels like we're smart enough to bet where electricity prices are going. And that's a difficult one I think in any market and particularly given the volatility that appears to be present in electricity markets.

So I think we would be -- our general approach and you've seen what we've done with Dickson Dam -- that contract expired and we re-contracted it for five years. I think that would be the order of the day going forward.

The question had been posed I think it was last quarter, and I'll just reiterate the answer. As we think about some of the assets, particularly the assets in the New England and perhaps New York area which are the primary part of that merchant risk, some of them are smaller hydroelectric assets, which rather than contracting, may be sold. And as we think about culling and managing our portfolio to be reflective and appropriate for its new size, it may not just be contacting the assets, so those are both options that are in front of us. But we really don't think of holding assets based on the option value; that's kind of inconsistent with the conservative approach that we take to our business units.

Good to know. And then Sanger, we've talked about the outage in Q2. Wonder if you could talk about some of the re-contracting efforts you're making around the incremental power there.

Yes. We are actually in discussions with PG&E on amendments to our contract to both address the incremental power that we have, which is now, if you will then let out of jail if you think of it that way. That work that you allude to that was completed in May included the installation of a larger main power transformer and interconnection to 115 KV grid rather than a 69 KV grid. And so we have an additional 14 megawatts of capacity which has now been unstranded. And we are in discussions right now with PG&E to deal with that.

Those are my questions. Thanks very much.

Thanks, Ian.

Sean Steuart, TD Securities.

You've answered just about everything. One technical question. Calpeco closing timeframe. It sounds like you have all of the approvals and I guess the first tranche with Emera is August 31.

Yes.

Is that the timeframe we should think about the closing of the 49% plus?

Yes. I think August 31 would be the right timeframe if you think from a modeling point of view for us to now assume 100% of the net income. As you and I have spoken, it's going to be a relatively anticlimactic closing in that we are fully consolidating that utility in any event right now.

Understood. And then maybe if you could speak to -- I guess the deal flow you're seeing on the utility opportunity side in the states. Can you talk to -- I guess in terms of the volume of opportunities that are being presented to you, how that might have changed over the last six months, year? How does the deal market look like in general right now?

Well, you know we're targeting I don't want to say a relatively unique slice of that market. Under our approach, we are looking for things that are in the sweet spot of like CAD250 million of which, in human terms is obviously an unfathomable amount of money. In utilities speak, they're relatively small acquisitions.

We're looking at targeting larger utilities that are looking to potentially shed some of their non-core states. And so I would say that most of the market for us is actually being created. These are outbound phone calls that we're making in general. So we continue to make the same volume of calls.

It is a bit of a push market. We are obviously trying to move large utilities off top dead center to deal with an asset which is almost by definition small. And so that obviously makes getting their attention difficult.

But I think there is a sufficient deal flow that you will continue to see that roll up strategy continue on for the foreseeable future as we think about what our capacity to process transactions is. It's kind of a couple per year of in the CAD100 million to CAD200 million or CAD300 million range. I think there's sufficient market for us to be able to do that, Sean. Obviously it's impossible to predict particularly when it's an acquisition strategy since the timing is sort of totally out of your control.

But I will say that we have a map in our office here with a bunch of pins in it that we're continuing to pursue. And sometimes things pop up, but obviously the Georgia transaction with Atmos I would say wasn't on our radar. It came as a result of some conversations between our respective teams. And it kind of got life and lights of its own in relatively short order.

So these things can come quickly. But we are making outbound phone calls. I appreciate that's probably not a very insightful answer, but we do see the market continue to be robust and that's a park to support our growth objectives.

Great. That's good context. Thanks, Ian.

Thanks, Sean.

Jeremy Rosenfield, Desjardins Capital Markets.

Most of the questions we've gone over so far. Just on the Georgia and the Arkansas acquisitions, curious to know if you've had any preliminary conversations with the regulators and if you have, if they've indicated support so far for the proposed transactions?

No, we haven't yet. But it is high on our to-do list, Jeremy, to get in front of them.

We have our first meeting with the Arkansas regulator on August 22. The application for Arkansas is being filed, if not today, then on Monday. So that will be in front of them.

I will point out that both United Waterworks and Atmos, as a matter of their relationship with the regulators in Arkansas and Georgia, went and gave some insight into this transaction already. Well, they don't give immediate reaction, there was nothing that came untoward out of that meeting that would lead us to believe that the reaction would be any different than it has been for the proposition that we are advancing in the other six states in which we've made applications or five states we've made applications in the past couple of years. And so I think we are cautiously optimistic if your question is speaking about handicapping the risk that we might face, I think we remain confident.

I think the proposition that we are advancing should be attractive to those regulators in the same way it has been elsewhere. We have a strong and enviable history of safe, reliable customer-centric operations. There's nothing for us to believe, Jeremy, that leads us to have concerns. Having said that, we acknowledge the jurisdiction of both of those regulators and the authority and it will take as long as it takes.

Okay. Great. That's excellent. Then more from a strategic point of view as you enter new jurisdictions and new markets, going forward, what do you feel is your level of comfort in moving into additional new markets versus going after utilities within existing states where you already have relationships with the regulator?

Sure. I think first prize is obviously to continue to build in those states in which you already have the relationship. Having said that, I think both Arkansas and the Georgia assets would meet the size threshold that they could substantiate or support the necessary resources to build those regulatory relationships. You may be aware that our approach is one of local, and so the regulatory resources and those regulatory relationships are built locally. And both Arkansas and Georgia are sufficient size to support those relationships.

We certainly wouldn't be going into a new jurisdiction for 1000 customers that just wouldn't have the size and scale to be able to do it. But I think we're confident that at close to CAD30 million plus, that Arkansas has that, and Lord knows, Georgia certainly does too.

Okay. Great. Excellent. And maybe one final question.

Moving back to be Gamesa transaction and the restructuring there, you had made some comments earlier about trying to lower the risk profile obviously by not getting involved in the merchant side of Pocahontas. Obviously when you lowered the risk profile, typically you would see a lower return in general on investment. So I'm just kind of curious as to whether you see there being sort of a move in the needle on what your expected return on the overall investment might be given that you would have a lower risk profile without taking that merchant capacity. Are we talking maybe a matter of basis points here or something else?

Well, let me start by saying that in the discussions with Gamesa, there was very little talk about differential profiles and relative pricing if you will when the original prices were crafted. I won't say they were crafted in Excel world where you can imagine where risk doesn't exist. And so I think we were pleased that the discussions with Gamesa really revolved around the existing asset segregation of the total investment price without reference to whether it was a contracted or uncontracted asset.

And so I think I'll answer your question by saying, I think it's a net pickup, if you will, with very little change in pricing to reflect the fact that Senate, Minonk, and Sandy Ridge have a different contracted status than Poca. So I think we're pleased in that regard. I think I would agree with your comment that uncontracted assets have a fundamentally different profile, particularly in the face of the current electricity market. But I think that doesn't really apply in the case of our renegotiation with Gamesa.

Excellent. And then I don't know if you can provide any updates but maybe Gamesa, have you taken a look at any of their other assets? And has there any indications as to the potential pipeline -- we're getting towards the end of 2012 and obviously PTCs are expected to be expiring at the end of the year. So does that give you visibility on some other assets that they might be looking to offload?

Yes. I don't think -- without giving away secrets from Gamesa's point of view, I don't think there are other assets that are at a stage that there would be an expectation that they would capitalize on the current expiration of the PTCs. Having said that, as we announced back in March when we made this disclosure of the relationship with Gamesa, we like to think it is broader than just these current assets. And our development teams have been in contact and continue to be so with Gamesa's development forces to look at some of their future assets, but nothing from our perspective would hit the current 2012 timeframe.

I think the industry as a whole is obviously hopeful that in some way the US government will find it appropriate to extend the PTCs. And that's probably a requirement for most of their projects to proceed as they would be for most other developers but they're all post-2012.

Great. Thanks. That's it for me.

All right. Thanks, Jeremy.

Nelson Ng, RBC Capital Markets.

Just a few quick questions on Quebec. I was just having a look at the dam safety CapEx and it looks like some items have been deferred to 2014 and 2015. Is there a deadline to have some of that work done? And also are there any opportunities to get something in return from Hydro-Quebec in terms of a higher PPA price or a slight extension to the PPA term?

Well, let me start by saying we have the dam safety rehabilitation program is actually mandated by the MRM, Ministere des Ressources Naturelles, and not Hydro-Quebec. And so consequently, I think it would be difficult to, from Hydro-Quebec's point of view with respect (technical difficulty) by the (technical difficulty), notwithstanding the close relationship between (technical difficulty) and the Quebec government. To touch on your point about delayed (technical difficulty), we're obviously managing our investment in a prudent way. We're spending time right now on engineering design at our Donnacona facility.

The majority of the work as you accurately point out, is now scheduled to occur next summer and perhaps the summer after, rather than we did expect it to do more this year. I won't say there's no firm deadline; there is a requirement that you advance a plan to the government and that plan is always under review and discussion with the government. They're not asking to do anything crazy or imprudent. And so I think we are confident that we are in compliance with our obligations and that our plan is prudent and will continue to be amended as appropriate going forward. I don't think you should read anything into that delay other than it was just the right thing to do from an engineering construction perspective.

Thanks. And then in terms of the Quebec wind RFP, do you expect to participate and do you have any developers or partners lined up?

Yes, we do. And yes, we have some of our own projects that we would be expecting to participate with. And, yes, we are in discussions with perhaps some of the smaller developers to identify opportunities to team up as we have done -- certainly did in some of the previous RFPs. So yes, yes, and yes, Nelson.

Thanks, that's all my questions.

Okay, thanks.

Gentlemen, there are no further questions at this time. Please continue.

Well, thanks for taking the time this morning for our conference call. And please remain on the line for the absolutely riveting disclaimer from Kelly.

Thanks, Ian. Certain written and oral statements contained in this call are forward-looking within the meaning of certain securities laws and reflect the views of Algonquin Power & Utilities Corp. with respect to future events based on assumptions relating to, among others, the performance of the Company's assets and the business, financial, and regulatory climates in which it operates. These forward-looking statements include among others, statements with respect to the expected performance of the Company, its future plans, and its dividends to shareholders. Since forward-looking statements relate to future events and conditions, by their very nature they require us to make assumptions that 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's discussion and analysis. Given these risks, undue reliance should not be placed on forward-looking statements which apply only as of their date. Except as required by law, the Company does not intend to update or revise any forward-looking statements whether as a result of new information, future developments or otherwise.

Ladies and gentlemen, this concludes the Algonquin Power & Utilities Corp. Q2 analyst investor call for today. Thank you for your participation. You may now disconnect your lines.