Algonquin Power & Utilities Corp (AQNU) 2010 Q3 法說會逐字稿

Good morning ladies and gentlemen and thank you for standing by. Welcome to the call Algonquin Power and Utilities Corp. Q3 analyst conference call.

(Operator Instructions)

I would like to remind everyone that this conference call is being recorded today, Friday, November 12, 2010, at 10.00 a.m. Eastern time. I will now turn the conference over to Ian Robertson, Chief Executive Officer. Please go ahead, sir.

Thank you and good morning, everyone. As mentioned, my name is Ian Robertson. I'm the Chief Executive Officer of Algonquin Power and Utilities Corp and I would like to welcome you this morning to our 2010 third quarter results conference call. With me on the call today are Chris Jarratt, our Vice Chair; David Bronicheski, our Chief Financial Officer, and Kelly Castledine, our Manager of Investor Relations. For your reference, the Q3 financial statements and management's discussion and analysis are available for download on our website at www.algonquinpowerandutilities.com.

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

As an agenda for today's call, we would like to start with a couple of operational highlights of the quarter. Following that, our CFO, David Bronicheski, will review the financial results. I would then like to provide some updates on our growth strategies and opportunities and at the end of the call, Chris Jarratt, our Vice Chair will host a question-and-answer period.

Within Algonquin Power Co this quarter, the hot, dry and sunny weather that made this summer, at least on the eastern seaboard, one of the nicest in 60 years caused our hydroelectric facilities to face challenging hydrologic conditions, contributing to financial results for the third quarter which were slightly below management's expectations. More specifically, while wind and hydrologic conditions in the western region were above long-term averages and not withstanding exceptional plant availabilities, Quebec, Ontario and New England demonstrated hydrology which was significantly below long-term averages.

Some good news, however, is that to date this fall appears to indicate a return to closer to normal conditions across our regions with the [maritimes] particularly benefiting from a number of major rainfall events in the past month. We are pleased that our thermal energy division saw the return to service of the Energy-From-Waste facility early in the quarter with a successfully completed overhaul. The performance of the plan is exceeding historic metrics and we believe that 2010 operating income from this facility will not be materially impacted in comparison to last year's performance.

Within the Liberty Utilities Group, operations were in accordance with expectations with continued year-over-year growth of approximately 2% in customer count. I would mention that we were pleased that our customer satisfaction survey completed annually in August by an independent agency showed statistically significant improvements over all metrics of customer satisfaction, with overall customer satisfaction rating increasing from 83% to 88%. This is particularly notable in light of the fact that we were in the midst of significant rate cases within a number of our utilities during the fielding of the survey. We believe that these results are consistent with our mantra that satisfied customers make a satisfied regulator make a satisfied utility owner.

I now would like to take a couple of minutes to provide a quick update on programs on the three major growth initiatives comprising our 2010 volume consolidation promise. First, our Liberty Water rate cases. As discussed in our MD&A, during Q3 Liberty Water continued to pursue several rate cases in Arizona. In this regard, we are pleased to have implemented new rates on September 1 at our Black Mountain facility providing US $0.7 million in additional revenue.

Additionally, we received an initial recommended order for Liberty Water's Litchfield Park facility in Arizona. Under this recommended order, the proposed revenue increase of USA $0.1 million represents approximately 70% of the revenue increase requested in our adjusted rate filing. This revenue increase when combined with the previously settled rate cases is expected to provide over US $10.3 million in additional revenue to Liberty Water in 2011.

We do have two additional rate cases in Arizona still awaiting recommended orders in which we had originally requested $3.5 million in additional revenue. Based on discussions with the Arizona regulatory staff, we are hopeful that the recommended orders for these remaining rate cases will be available in late 2010 or early 2011.

Secondly, our electric utility opposition in partnership with Emera. The California Electric Utility acquisition by Liberty Energy is proceeding through the regulatory approval process before the California and Nevada public utilities commissions. On September 14, the California utility received a favorable proposed decision from the administrative law judge of the CPUC. On October 15, 2010, the CPUC issued its final decision, approving the transaction without imposition of material conditions. The transaction is now subject to the pending approval of Public Utilities Commission of Nevada which is expected in December of this year. A number of key individuals from Liberty Energy's utility management groups from Arizona and Toronto have been relocated to the Tahoe region to ensure a seamless transition of operations upon closing of the transaction.

And, lastly, the continued construction of our Red Lily Phase One Wind Farm. The Red Lily phase one red farm solid completion of road and foundation construction work during the quarter with approximately half the turbine generators installed so far. Commissioning is on track to be completed at the end of February 2011. I'd like now to hand it over to David Bronicheski to give you some insight into the financial results.

Thanks, Ian. Now, a review of the Q3 2010 results. Just to note that we use adjusted net earnings to assess the net earnings without the effects of gains or losses on foreign exchange, foreign exchange, forward contracts and interest rate swaps as these are not reflective of the performance of the underlying business. Revenue in Q3 2010 was $45.4 million. This compares to $45.1 million about a year ago, almost unchanged. Adjusted EBITDA was $17.8 million in Q3 this year compared to $20.3 million last year. And our net earnings in 2010 this year in the quarter was $1.5 million compared to $13.1 million a year ago.

Now, some third quarter highlights from our operating subsidiaries, beginning with the Algonquin Power Company, or APCo. In APCo's renewable energy division, during the third quarter of 2010, net energy sales totaled $14.4 million and the division generated electricity equal to approximately 87% of long-term projected average wind and hydrology. The decrease in net energy sales compared to the same period last year is mainly a result of below long-term average hydrology in the New York, New England, Ontario and Quebec regions. For the third quarter of 2010, operating profit totaled $9 million as compared to $10.5 million during the same period a year ago. Overall, the renewable energy division did not meet our expectations due to lower than expected hydrology.

In our thermal energy division, net revenue for the third quarter of 2010 was $13.3 million as compared to $14.2 million during the same period a year ago. The decrease is mainly due to the expected impact of the shift to the new operating model at the Windsor Locks facility, the closure of the landfill gas facilities and the impact of a stronger Canadian dollar. For the third quarter of 2010, operating profit totals $7.3 million as compared to $7 million during the same period in 2009. And, overall, the thermal energy division did meet our expectations.

Looking ahead to the next quarter, APCo's renewable energy division is expected to perform at or below long-term averages in the fourth quarter of 2010 based on wind and hydrology conditions. The EFW facility returned to full production in mid July and is expected to operate for the remainder of the year above expectations processing 500 tons of waste each day. We expect the [Sanger] facility to operate at or above expectations during the fourth quarter of 2010 in line with performance from the same time last year. However, hydromulch sales are expected to remain below expectations for the quarter due to low demand.

The Windsor Locks facility did not commit any portion of the remaining available capacity to the winter 2010-2011 forward reserve market for the period October 1 through April 30. Instead, Windsor Locks will continue to sell a portion of its electricity capacity and all of its steam capacity to the industrial host and the balance of the electrical capacity up to a maximum of 40 megawatts into the ISO New England day ahead market. And, finally, plans are underway to expand the energy services business to include the marketing of output from the New York and New England hydroplants.

Moving on to Liberty Water, revenue for the third quarter of 2010 totaled $9.8 million as compared to US $9 million during the same period in 2009. Water distribution of waste water treatment revenue both increased primarily due to increased interim rates at the facilities in Texas. The waste water treatment customer base grew by 2.1% and the water distribution customer base grew by 1.7% over the number of customers at the same time a year ago. The increase is due to some organic growth and the inclusion of customers from the acquisition of the utility asset in Galveston, Texas, at the beginning of the year.

For the third quarter of 2010, operating profit totaled US $4.2 million compared to US $4.8 million in the same period in 2009. Overall, Liberty Water's operating profit did meet our expectations for the quarter.

Looking ahead to the next quarter, we are expecting continued modest customer growth for the remainder of 2010. Revenue increases from rate cases completed in Arizona and Texas have contributed an additional annualized $2.2 million. And we're pleased to note that we have received a recommended order and opinion that provides an additional $8.1 million of revenue for our Litchfield Park utility. The order is subject to final approval which we anticipate will be received later this month. Additional rate cases with revenue increase requests of $3.5 million in annualized revenue are expected to be resolved late in 2010 or in the first quarter of 2011. Further details on the rate cases are detailed on page 26 of our MD&A.

Finally, just a brief word on our financial reporting framework. As most of you are aware, in 2011, Public Enterprises in Canada will be required to change to the accounting framework under which financial statements are prepared to be international financial reporting standards, or IFRS. The adoption of IFRS is one of the alternatives that is available to Algonquin Power as an entity with rate regulated activities. Algonquin can also avail itself of the one-year deferral approved by the accounting standards board in Canada. And alternatively, we are an SEC registrant so Algonquin can also choose to report its financial statements under US GAAP.

Considering the short-term nature of the Canadian solution and the uncertainty around the eventual adoption of rate regulated accounting under IFRS, US GAAP financial statements represents the least disruptive and most meaningful accounting framework for readers of Algonquin Power's financial statements. This option will result in minimal changes having to be made to our financial statements as there are few differences between US GAAP and Canadian GAAP.

US GAAP also includes accounting standards for rate regulated activities within the financial statements and, of course, this is a growing part of Algonquin's operations. Therefore, we've decided to adopt US GAAP for our accounting framework effective January 1, 2011, for purposes of Canadian and US reporting requirements. I'll now hand it back to Ian.

Thanks, David. Just before we start our question and answer period, I would like to spend a couple of moments on our growth strategy and some of our prospects. Starting with Algonquin Power Co, or APCo, we are continuing development work on three sites in Saskatchewan representing approximately 500 megawatts of wind power potential including a phase two for our Red Lily Wind Farm. All three of these projects were qualified to participate in [Sas power's] upcoming request for proposal process in the first quarter of 2011 where [Sas power] has reported that they will be procuring up to 175 megawatts of additional wind power.

As previously mentioned, APCo also participated in the Hydro-Quebec community-base call for offers with two 25 megawatts community base wind power submissions and we're now awaiting the results of this RFP which we expect by the end of 2010. In Ontario, our 42 megawatt Prince Edward County wind project is awaiting the results of the economic connection test pursuant to the Ontario fit program and based on advice on the Ontario power authority, we expect the results of this economic connection test in the fourth quarter of 2010.

Our 80 megawatt Amherst Island wind project which is not subject to the economic connection test process is located in the area where we are confident that connection availability exists and we are awaiting an Ontario power authority's fit contract response. At the Windsor Locks facility we are continuing to refine our repowering plans regarding the planned installation of a 14 megawatt turbine, one more appropriately sized to serve the mill requirements.

In addition, and perhaps equally significant, based on the outcome of the recent integrated resource planning hearings held by the Connecticut DPUC in which they urged utilities to recontract facilities such as Windsor Locks, we are now in negotiations with a number of Connecticut utilities for new power purchase agreements. As an alternative to our continued participation in the merchant New England ISO market place.

And now, over to Liberty Utilities. The business development objective for this group is to grow earnings to match or exceed those of APCo. As we have previously pointed out, with the completion of the Calpeco transaction and our Liberty Water rate cases, we expect the percentage of our 2011 consolidated EBITDA, generated from regulated utilities, to exceed one-third of total EBITDA.

To that end, liberty water was pleased to note that in addition to the rate case revenue growth, customer growth is continuing within its service territories. For Liberty Energy, in addition to adding the EBITDA growth in the Calpeco transaction next year, we are focused on completing follow on electric distribution, utility and transmission related investment opportunities.

Our strategy, which appears to be having -- to be gaining traction, has been to approach large utilities to acquire the portions of their utilities which are located in noncore state jurisdictions. This is exactly the circumstance which led to the Calpeco transaction.

While these target acquisition opportunities are small from their utility parent's perspective, the $100 million to $200 million transaction side is exactly in our sweet spot. Acquiring these utilities will allow us to continue to execute on our strategy of sharing common administrative and customer service infrastructure between utilities to generate economies of scale, which support best-in-class customer care for all of our utility rate payors.

In conclusion, as we look back on the first nine months of 2010, we note the focus that has been placed on completing the growth initiative comprising our 2010 value consolidated -- consolidation promise, the full impact of which will be felt in 2011. We have successfully moved Calpeco through the California regulatory process. We've made significant progress on the Liberty Water rate cases and achieved steady construction milestones toward the February commissioning of the Red Lily Wind Farm.

We are confident that our organization is well-positioned to deliver on the proposition of total shareholder return from a combination of our healthy dividend coupled with capital appreciation arising from sustainable dividend growth through businesses premised on economic longevity, environmental respect and community engagement. With that, I'd like to turn things back over to Chris Jarratt to chair our question-and-answer session.

Great. Thanks, Ian. If anybody has any questions, we would be happy to answer them.

(Operator Instructions)

And your first question today comes from James Morrison with Cormark Securities. Please go ahead, sir.

Hi, guys. Just on the debt negotiations. I know you're looking at the refinancing of your operating line, but what are you doing in terms of the senior debt that expires later in 2011, I think it is the $70 million for Air Source?

As we noted in the MD&A, we are in receipt of offers to begin terming out the bank credit facility. And we've also -- are well down the path of discussions with the bank on the form and tenor of the renewal of the bank credit facility in 2011. Also, as part of this be looking at perhaps taking out additional debt in order to repay the same (inaudible) facility perhaps a year earlier. As you know, it's not due until fall of next year, but since we are active in the debt markets at the present time, it seems logical for us that we would take a look at perhaps dealing with that to date.

Right. What kind of terms do you think you will be able to get in terms of maturity?

We have a number of options available to us. Right now, given the economic life of our assets, certainly on the power side, we would like to see tenors in the seven to ten year range. Regulated utilities have an indefinite life and so we prefer to see tenors well in excess of five or ten years. So certainly we're looking to have as long a tenor as we can.

Okay. And so just looking at your overall debt level, where do you kind of see your debt by, say, the end of 2011? Do you have a target capital ratio or something?

We manage the capital structure to investment grade credit metrics which, for us, given the mix of assets that we have is approximately 50/50. We can oscillate slightly above or below that number but approximately 50/50 is what we expect to see in the long run.

Okay. And then just quickly, on the -- my next question is the hydroassets in Quebec that you've got I think $17 million in CapEx coming up. Is that fairly evenly spread across all of them or are you looking at kind of divesting of a couple of the ones that are more capital intensive? I'm just looking, there's some pretty short maturities on some of those PPAs.

Sure. It's Ian Robertson speaking. The obligations under bill C-93 are actually focused on a couple or three facilities. You mention the maturities of the PPAs. We obviously look at the economic useful life of a hydroelectric facility being substantiated to the 20 or 25-year PPA that was -- might have been entered into in the context of the construction. And Donnacona, which is probably not quite half but it's a significant contributor to the $17 million of capital requirements, is a perfect example. The facility is in great shape.

It is barely a youth, if you will, in terms of its service life. And so, consequently, we actually look at the economics of these facilities over a much longer horizon than just the remaining PPA. I would mention that in Quebec we have been successful at recontracting facilities including our Cote Ste-Catherine phase 1 and [Moloryae] facilities with Hydro-Quebec for extended periods of time, which I think reinforces our belief that we shouldn't be looking at these over a short-term horizon.

So, in short, no. We aren't planning on disposing any of the facilities. We're happy with the quality of the facilities and while the volatility and hydrology has obviously been upsetting in the short term, in the long-term we think they continue the strong value contributors.

Okay. That's all for me. Thanks, guys.

Thanks, James.

Your next question comes from John [Plethas] with Canaccord. Please go ahead.

Thank you. Congratulations for the good performance on the energy-from-waste facility. When I was at the plant during its outage during the year, there were a lot of things you were doing to improve the efficiencies of the plant, but it seems that the efficiencies at that plant are now exceeding your early expectations. Just last quarter I believe you were expecting only $0.2 million dollar improvement for the second half and now it looks like you're expecting about $1.9 million. So, would you say that an improvement of around $1 million a quarter is a good run rate for this facility?

John, it's Chris Jarratt speaking. I would say that's probably a little bit optimistic and the reason being is because that facility is, as you know, has five individual boilers which is on a cycle for cleaning them out. So, when the facility was started up in July, they were obviously all clean. So, what you avoided was basically one of those cycles in the ten-week period. But having said that, the facility is operating much better than it was. And in terms of a run rate, I don't think we quantified that yet but it's probably not the $1 million a year but is certainly well above what we had been running.

Okay. Thanks. So then having all five units up was probably the main reason why this has significantly exceeded your expectations or is there something else?

No, I wouldn't say it was the main reason. It was just one of the reasons that it exceeded what we had done in previous years. As I said, the facility had a number of improvements made to it. And all of those improvements are working extremely well. So, long-term we expect that facility to be much improved from what it had been.

Okay. Thanks. And moving to Windsor Locks, I believe you were previously expecting about $5.3 million US of operating profits for the year. Is this still the expectation?

It's Ian Robertson speaking, John. Over the course of 2010, when we converted our -- from the PPA operating model to the merchant operating model we had expected about $4 million to $4.5 million of operating profit. Through the course of the summer, the -- our participation in the merchant market resulted in increasing that to, as you said, $5.2 million or $5.3 million.

In the fall with the change in the dynamics at the foreign reserves market place and the decision not to take the lower market clearing price in that forward reserves market, we're now participating fully in the merchant market place. I think over the course of -- over the course of Q4, the estimate of $5.3 million might be a little optimistic. I think we obviously enjoyed the benefit of the much higher revenues from that facility given the weather conditions. I think the bigger question that stares in front of us and perhaps it's unasked, I'll give you the answer anyway, John because it is obviously important.

What are the implications over 2011 for the change in operating regime? When we looked at the market clearing price, we came to the conclusion that albeit subject to heat rates and other factors of the merchant market place, we were actually better off to not take participation in the forward reserve market place. And so, in 2011, looking forward we see that Windsor Lock is still expected to generate a run rate revenues in the $3 million to $4 million range. Maybe that's down a little from our previous estimate of $4 million to $4.5 million but part of the difficulty, of course, is predicting heat rates and degree days during the summer of 2011 which obviously hasn't taken place. And so we're trying to be somewhat conservative. I don't know if that answers your question, John.

Yes, thank you for that. Now, staying with Windsor Locks, you mentioned the DUPC in Connecticut issued the order to Connecticut Light and Power to recontract some plants. Can you give us any more color on this, incentive maybe timing or the length of the potential contracts you're discussing, that kind of stuff?

Sure. Easy question first. Timing. It is kind of right here, right now. As part of the integrated resource planning hearings in which utilities are in there talking about their planning needs. It became apparent and partially because we advanced it, that there are a number of facilities, not dissimilar to Windsor Locks that have available capacity that could quite easily be recontracted in a manner that could avoid the necessity for construction of new plants. So, the utilities, as you mentioned, were urged to enter into those negotiations. We took the DPUC up on their suggestion and are now in negotiations with a number of utilities including, as you mentioned, CLMP.

As to the tenor of those contracts, still having the conversation with the utilities, obviously the facilities exist. So, the necessity for 20-year contract may not be on the table with the CLMP because there isn't a need to support a construction of it since the facility already exists. But we were pleased with the response and obviously the negotiations are on-going and when the results of it become apparent, we'll certainly roll them out to the market place. I think we are very pleased that as an alternative to participating in the ongoing merchant market place, this is an alternative to potentially earn the same returns but with lower risks since we would be passing that on to the utility.

Okay. Thank you very much.

Thank you, John.

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

Good morning. Can you, Ian, outline for me whether you have preferences in terms of pursuing growth in the power segment or liberty or electric or energy or whatever you call it?

I think it really comes down to an evaluation of the risk adjusted returns that are available in the various areas. Let's talk a little bit about our power division. We obviously have a long and I would like to think somewhat rich history as independent power developers. As you know, Chris and I started Algonquin back in the late 1980s as an IPP developer. It obviously has a soft spot in our heart and things like Red Lily is a perfect example of that.

I would say though as we've looked at some of the transactions that are taking place in the market place for contracted assets, I don't think from a risk adjusted return perspective they equal the returns that can be obtained from, for instance, our Calpeco transaction. So, I think it's a little bit of a pendulum, Tony. That right now, I think our belief is we're continuing to explore a number of growth opportunities in APCo but we're certainly seeing some very attractive, material-sized utility acquisitions that can contribute substantially to the earnings of the organization.

I think we've always said that as we urge the capital markets when they think of this organization from a peer perspective, perhaps it is not just the (inaudible) and the northlands and the interjectures they should be including in the peer group. It is the [Ameris], the [fortis], the AESs, it's the organizations that have a substantial portion of their revenues from regulated sources. We happen to believe that -- and if you look at the earnings from Liberty Water, I think they support that proposition is that on a risk-adjusted basis, I think that's a very attractive place for us to pursue growth. We're certainly not ruling it out. I think our target, and we've kind of set it out there, is that we would very much be happy to see our EBITDA split much more equally between regulated utilities and the IPP space, and so as that trended much closer to 50/50, that would be totally okay.

I mentioned in my earlier opening remarks that we are actively pursuing opportunities there. So, while there's no hard and fast rules, it really is about finding the benefit, risk adjusted returns. I think today as we look at it, utilities seem to offer a compelling proposition. I don't know if that answers your question, Tony.

Well, it does. I wonder in terms of approach would you consider doing it alone or seeking partnerships as you have with Emera, say particularly electric utility?

Well, we -- we're not adverse to having partners. Obviously, we are thrilled with the relationship with Emera. In terms of gaining access not just to get support from a financial perspective but in terms of the transition of Calpeco, we've had active involvements of the Emera group in that process. I think we are pleased, however, that this organization has now, evolving into its corporate DNA, the ability to deliver utility management services and so I think it is a little bit dependent on size, Tony.

If a utility that came along that was perhaps about $2.5 billion, perhaps a bit of a threshold, I think a partner might make sense. I think if we were below that threshold in using Emera as an example, it might make sense for Emera to participate in it economically directly through an investment in Algonquin. So, it could be a mix but largely probably dependent on transaction size.

All right. Appreciate it. Thank you.

Thank you, Tony.

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

Thanks very much. Hello, guys, on the Calpeco, could you update us now that you're getting close to final regulatory approval on how you now expect the asset to perform relative to your initial expectations?

Sure, Matthew. Well, I guess the good news is from the assets perspective is that a growth has continued in Tahoe. That debt is well below national utility averages. Now, we had always expected that because they had never had those problems. The energy usage is strong. I think -- so, there has been nothing happened from the utilities perspective that would cause us to have any concerns with the transition. I think the biggest issue that -- I don't say we face but I guess as we go through, the utility is poised to do its first rate case in -- submitted in early -- mid to late 2011 for rates to be effective in 2012. That's an important rate case for us because it will be the first time where our actual operating costs will be incorporated in rates.

And while we don't expect any material differences, in the rates -- in the operating costs, Nevada Energy has incurred in the utility, it is important that ultimately we get cost reimbursement on our costs. So, Matthew, in short, nothing has come up during the transition process that causes us heartburn from the utilities point of view as we've got a little bit closer to moving from the right seat in to the left seat of that bus and so don't know what else to add. I hope that answers your question.

Yes, that's good. Separately, on Lipsco, I know there's still I guess a bit of uncertainty about the phase-in. You guys have been waiting an awful long time to get the rates in. I'm sure you would like to get that implemented ASAP, but what's your best guess I guess now as to the time line for fully phasing in the rate increase?

Well, I think there's two issues that you touched on in your question. I'll hope this answers them. The first is just the implementation of the recommended order. It was on the open meeting that got held -- the agenda for the open meeting that got held in October. And a couple of questions came from the [dias] with respect to the rate design issues in respect with the proposed amendment that came from the city of Litchfield with respect to rate design and as a result of answering those questions. The matter got held over until the November meeting scheduled for November 22, 23 of this month, so I guess in a week or so time, so we fully expect the rate order to be resolved at that time.

The second part of your question was a phase-in that's been proposed. You are right in that the phase-in of rates over three years was proposed. I would mention, of course, though that under Arizona law any phase-in of rates actually has to be accompanied with a full reimbursement of the shortfall. And so we actually -- probably from accounting point of view, because of the certainty of that, will be not recognizing that phase-in because we are given reimbursement for all of those revenues. And so I think the phase-in of rates really is more of a rate payer issue rather than a utility issue just given the way we're compensated for those phase-ins. Those aren't on our ticket, if you will.

Okay. Great. Thanks. Those are my questions, guys.

Thanks, Matthew.

Your next question comes from Matt Gowing with [Maki] Research. Please go ahead.

Thanks very much, guys. Just a follow-up to the previous question about the phasing in and the impact on your accounting. You'll be recognizing the rates even though there won't be the phase-in -- there will be this face-in impact. But what's the impact on cash flow of that reimbursement? Will that phase in affect the -- how will that affect the cash flow?

Steve, I think in short, obviously from a cash perspective, that, that cash will follow the actual revenues. The phase-in is not all that material in terms of the impact. I can certainly get you the specifics of it, but I think we obviously won't be recognizing cash we don't receive. So, maybe from an accounting perspective, the appropriate treatment would be to not recognize it, from a cash point of view, we will.

I would mention that believe it or not, cash isn't probably the biggest challenge that Liberty Water faces in that until growth kind of catches fire again down in the Arizona and Texas market places, the reinvestment opportunities and reinvestment obligations we might look at it that way have been somewhat muted. So, yes, obviously cash is important and, yes, we need to get it back with a return on it but it's not like that phase-in is going to create a strain, if you will, on the cash flows of the utility.

Thanks. And an unrelated question actually on your Amherst Island development project. Wondering if you could provide us with a little bit more color on the capacity that's available in that part of the grid? I understand any power will be ultimately fed into the Lenox generating station adjacent to that. What's the available capacity there?

It's Chris Jarratt speaking. I don't think we know exactly what it is, but we know that it is a very robust system. It's our understanding that there is more than enough capacity to handle the 80 megawatts that we have.

Okay. Thanks. That's it for me.

Thank you.

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

Good morning. Just a follow-up question on Amherst Island. You were pretty bullish about that development or an announcement with respect to that project back on your Q2 call. Is there anything in particular that's delaying the OPA from making a decision?

Not that we know of, no. We always expected it to be in Q2 -- in Q3, Q4 time frame towards the end of this year. So, we have heard -- we haven't heard anything else to make us think differently.

Okay. And you also -- I notice in the MD&A you were talking about the potential development of 12 megawatt combined cycle plant in Ontario. Can you provide maybe a little bit of information on that? Where it's located and what the next steps are to get that developed?

Yes. That is an opportunity that exists at the energy-from-waste facility. It's kind of tied into some existing equipment that we already have there as well as an existing customer for the steam. So, it's kind of like one of the projects that has all of the technical aspects are at hand and what we really just need is to work out power purchase agreements and that's obviously a significant challenge for any development project. From a technical point of view, the land, the off-take host, all of that is almost right there all set to go.

So, that's really the same development you've been talking about?

Yes. That's correct. And the other important feature which helps you with the power purchase agreement is the fact that it's in an area which is a congested area. It is right beside, and I mean literally right beside, a 500KV substation. It's just kind of got all of the attributes of a good project.

Okay. And last question, seems you're moving into fourth quarter with a bit of an open position in your energy services business. Just wondering given where prices are, does that present an opportunity or a headwind for your renewable energy segment?

Well, two parts to the question or two parts to the answer. One is when you say an open position, we tend not to be long energy. In our energy services business, it is all about the underlying hedge being our existing generation and any purchases that we make to potentially offset those contingent, the unit contingent nature of generation from the Tinker Facility are in the form of options or derivatives that allow us to make sure that we're not long exposed positions from an energy point of view. So I'll start with that. We are very careful not to find ourselves, this is not about speculating on energy prices.

Having said that, I would note that we've been very pleased to see quite strong energy prices in the New England ISO, quite a rebound, if you will, and so the positions that -- I wouldn't even say the positions that we have, but the underlying value of our assets and our business we think is very strength. Obviously, Tinker is about managing two and three year contracts going forward. And it's always nice to renew the contracts in an environment of strong energy pricing. And so there are two answers to the question. I hope I hit what you were looking for.

Well, isn't it that Tinker will supply about 75% of your outstanding obligation and you have to acquire the remaining 25%?

That's correct. And in respect of that 25%, we tend to have a book that includes, if you will, calls on energy that if we need it, great. If not, we can allow it to expire.

So, you've already locked in your purchase price for that energy?

Absolutely. When we entered into the contract with the customer for that energy over the course of the year, we certainly didn't want to be exposed to potential shortfalls in the book and so, consequently, had optional long positions in the market place to cover up the unit contingent nature at fixed prices. Now, as I said, the cost of those contracts has already built into margin and so, to the extent that the contracts expire, fair enough, so be it, but to the extent that we need them to make up hydrology or unit outage shortfall, it's available at a fixed price.

Okay. Great. Thank you.

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

Good morning, everyone. You've already answered part of my first question with your discussion on utility acquisitions and your focus on risk adjusted returns. I wanted to focus on the disclosure which seems to suggest you broaden the scope of your business to contemplate acquisitions in natural gas utilities. I was wondering if you could give more color on that opportunity, how it might look different from the other utilities you're investing in. Do you see much for sale, your price and return expectations?

Thanks, Rupert. It's Ian speaking. Let me start by saying from a disclosure point of view, and I presume you're speaking to the kind of shift from Liberty Electric to Liberty Energy and the discussion that natural gas distribution systems may or may not form part of the utility universe that Liberty Energy is looking at. You're correct with the observation.

I think I would point out that the decision to broaden that focus beyond Calpeco's distribution and transmission utility is something that's going to be debated at the Board and before any decision gets made. I would offer that comment up though against the backdrop that a number of utilities, that we're actively participating in discussions with, hold a portfolio of both electric and natural gas distribution utilities. So pipes and wires tend to form the majority, if you will, of distribution utilities in the US and so, as we look at some of those utilities to make sure we don't find ourselves at least not even able to have conversations with them because we may have limited our scope. We did want to make sure that, that opportunity or potential existed.

I would say that from a core competency perspective, as you look at management of an electrical distribution system and a natural gas distribution system, obviously there are a number of factors associated with the storage of natural gas which obviously can't -- doesn't take place in electric utility. We're pretty confident that from a utility management perspective that between ourselves and Emera, that's definitely within the competencies of this organization. And so it really -- I don't think it's a statement that we are -- we've gone there yet but I think we just didn't want to preclude those conversations at this stage.

Okay. Thanks for the color. One other question. Housekeeping question, really. A slight uptick in your admin expenses in the quarter. Can you break out for us how much of that was one-time and what we can expect on a go-forward basis?

In the quarter, we're experiencing, as you know, the conversion to a different accounting framework. In the quarter, we did make a decision that we were going to switch to US GAAP, but up to that point, we were still incurring expenses on the IFRS side. In addition, we, as an SEC registrant now in our second year, are required to be SOX compliant. And so there is an initial -- I'll call it start-up cost associated with moving forward with the SOX initiatives. Those were, I think, two of the more significant factors in the quarter. And there's also some capital tax that we're incurring this year that we didn't have in the previous year.

Okay. You know how much of the expense would be a one-time for Q3 only?

Off the top of my head, I wouldn't want to just venture a number but I can certainly get back to you with that.

Okay. Great. That's all. Thank you.

Thanks, Rupert.

(Operator Instructions)

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

Great. I'd like to thank everyone for joining us this morning. And just before we start the obligatory but important disclaimer from Kelly, I would note that November 23 is our investor morning and we welcome you all to participate. We obviously look forward to giving you some deeper insight into some of the strategies and opportunities that we've touched on but due to time limitations weren't able to get into in-depth. And thanks, everyone, and have a great day.

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 and Utilities Corp with respect to future events based on assumptions relating to, among others, the performance of the Company's assets in 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 a company, its future plans and its dividends to shareholders.

Since forward-looking statements relate to future events and conditions, by their very nature they require us to make assumptions and involve inherent risks and uncertainties. We caution that although we believe our assumptions are reasonable in these 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 2009 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 conference call for today. Thank you for participating. Please disconnect your lines.