Filed by: Algonquin Power Income Fund

Pursuant to Rule 425 under the Securities Act of 1933

Subject Company: Algonquin Power Income Fund

SEC Correspondence File Number: 333-141569

THE FOLLOWING IS A TRANSCRIPT FROM THE ALGONQUIN POWER

INCOME FUND Q2 CONFERENCE CALL ON AUGUST 14, 2009.

OPERATOR: Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Algonquin Power second quarter analyst conference call. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. Instructions will be provided at that time for you to queue up for questions. If anyone has any difficulties hearing the conference, please press * followed by 0 for operator assistance at any time.

I would like to remind everyone that this conference call is being recorded on Friday, August 14th, 2009 at 10:00 a.m. Eastern Time.

I will now turn the conference over to Chris Jarratt, Executive Director. Please go ahead, sir.

CHRIS JARRATT (Executive Director, Algonquin Power Income Fund): Thank you, Joanne. Good morning. My name is Chris Jarratt and I am an Executive Director of Algonquin Power. I’d like to welcome you to Algonquin Power’s 2009 second quarter results conference call.

With me on this call are David Bronicheski, Chief Financial Officer; Louisa Reid, controller; and Kelly Castledine, Manager of Investor Relations.

To start off today, I’m pleased to report that for the second quarter, Algonquin showed positive results in light of the current business environment. While production was approximately in line with expectations, revenue and EBITDA fell below expectations, primarily as a result of lower than average energy rates due to the economic slowdown in the U.S. where we saw merchant power and the lower than expected natural gas prices.

Algonquin’s diversified asset base and long-term contracts have helped to stabilize cash flow, which allows Algonquin to successfully execute its growth plans even in these tough economic times.

For your reference, the financial statements and management’s discussion and analysis are available on Algonquin Power’s website.

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

I would like to start with a few highlights and a general update of the business of Algonquin Power. Following that, our CFO, David Bronicheski, will talk about the financial results and then I will review some of the growth opportunities and development projects that we are working on. At the end of the call, we will have a question-and-answer period.

Highlighting a recent announcement made during the second quarter on April 23 ^rd, Algonquin was pleased to announce a strategic partnership with Emera Inc. through a private placement of approximately 8.5 million units at a price of $3.25 per unit which is expected to represent 9.9 per cent of the outstanding units following the subscription. Proceeds from this transaction will be used by Algonquin to acquire an electric utility in partnership with Emera. Algonquin Power and Emera will each own 50 per cent of the newly-formed California Pacific Electric Company which intends to acquired the California-based electricity distribution and related generation assets of NV Energy. This is a very positive step in strengthening our utilities business and leveraging Algonquin’s proven utility management and independent power generation expertise.

In addition, Emera brings a wealth of expertise and experience, owning and operating local electrical distribution utilities to this transaction. The transaction will enhance Algonquin’s cash flow quality and stability and will contribute to the long-term success of Algonquin. The transaction is subject to state and federal regulatory approval, which is expected to occur in mid 2010.

Additionally, on June 12^th, 2009, the trustees of Algonquin announced that they had entered into a unit-share exchange support agreement to support an offer which will provide Algonquin’s unitholders the opportunity to exchange their trust units of Algonquin for common shares in a corporate entity. If the offer is accepted by Algonquin unitholders, they will receive common shares of the corporation in exchange for their trust units of Algonquin on a one-for-one basis. The shares of the corporation will continue to receive monthly dividends equal to current distributions of $0.24 per unit annually and will also be lifted for trading on the Toronto Stock Exchange.

In addition to the exchange of Algonquin trust units for shares, a proposal has been made to unitholders of convertible debentures to exchange them for newly issued CDs or shares of the corporation. Additional details of the offers are available on Algonquin’s website.

The board of trustees and the manager believe that having Algonquin’s business conducted under a new corporate structure will benefit Algonquin Power within the capital market and will increase Algonquin Power’s competitive effectiveness in the power and utility sectors. In addition, the ability to reinvest future cash flows retained as a result of increased tax attributes available to Algonquin as a result of this transaction will further support our growth objectives.

Subsequent to the end of the quarter, on July 27^th, 2009, at the annual special meeting of unitholders, Mr. Chris Huskilson was appointed to the board of trustees of Algonquin Power. Mr. Huskilson is currently the

President and Chief Executive Officer of Emera Inc. having held this position since November 2004. In addition, Mr. Huskilson is the Director of Emera Inc. and Nova Scotia Power Inc. and is the Chairman of Bangor Hydro-Electric Company.

The addition of Mr. Huskilson to the board of trustees is very positive for Algonquin Power, both form a corporate governance perspective and for future partnership and acquisition opportunities with Emera which will contribute to the strengthening of Algonquin Power and the highly predictable long-term regulator returns from our assets.

As an update to the focus on creating value through growth, our strategy is to continue focusing on high-quality, renewable and high- efficiency thermal generation projects that benefit from low operating costs using proven technology.

In addition, we continue to look at high quality, regulated utility assets that provide steady and stable long-term cash flows. Our development division continues to progress with greenfield development projects and we have seen acquisition opportunities open up within the power and utilities businesses which we continue to evaluate on a risk-adjusted basis.

Although times are challenging with respect to accessing capital, I would like to point out that we continue to pursue innovative ways of financing our growth activities as evident by our recent partnership with Emera and co-acquisition of the California utility.

As discussed last quarter, we continue to see softening of power prices in the New York and New England power markets where Algonquin has some merchant power exposure. While we have benefited in the past few years from relatively high power prices, as David will outline in a few minutes, the lower power pricing has impacted our results in our renewable energy division.

Algonquin’s exposure to commodity prices is primarily limited to exposure to natural gas price risk at our co-generation facilities. Power purchase agreements for these facilities include provisions which reduce exposure to natural gas price risk by having each facility’s energy price linked to the price of natural gas. As a result, fluctuations in natural gas prices are largely a pass-through to energy prices.

With that, I’m going to hand it over to David who’s going to talk about our financial results.

DAVID BRONICHESKI (Chief Financial Officer): Thanks, Chris.

Now for a review of the Q2-2009 results: In the second quarter, our revenue was $46.5 million as compared to $54.2 million the year before. Our EBITDA though came in at 20 million as compared to 22.9 million in the previous year’s quarter. Net earnings were 15.3 million compared to 8 million last year. On an adjusted net earnings basis, our net earnings were 3.8 million compared to 4.3 million.

Just as a note, Algonquin uses 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 of Algonquin.

Now, some second quarter highlights from our business units beginning with the power generation and development business unit. In the renewable energy division, during the second quarter of 2009, revenue from energy sales totalled 17.5 million and the division generated electricity equal to approximately 101 per cent of long-term projected average wind and hydrology. The small decrease in revenue is mainly a result of lower weighted average energy raised in the New England region which was partially offset by increased average hydrology compared to the same period last year in Quebec, New York and New England regions.

For the second quarter of 2009, operating profit totalled 12.4 million as compared to 14.5 million during the same period in 2008. Overall the renewable energy division did not meet management’s expectations due to the lower weighted average energy rates in the United States.

In the thermal energy division, revenues for the second quarter of 2009 totalled 13.2 million as compared to 14.4 million during the same period in the previous year. The decrease is mainly due to decreased energy rates due in part to lower natural gas prices which are largely a pass-through in the rates.

During the quarter, production increased by 5,000 megawatt/hours at the Sanger facility and 8,000 megawatt/hours at the Windsor Locks facility. The landfill gas facilities increased energy production by 3,000 megawatt/hours during the quarter and the EFW facility experienced decreased throughput over the same period in 2008 processing just over 35,000 tonnes. For the second quarter of 2009, operating profit totalled 6.3 million as compared to 7.2 million during the same period the previous year.

Overall, the thermal energy division did not meet management’s expectations primarily due to weaker gas prices and lower demand for steam from the division’s cogeneration assets as a result of the current economic slowdown in the U.S.

Moving on to the utility services business unit, revenue for the second quarter of 2009 totalled 9.9 million as compared to 8.7 million during the same period the year before. Increased revenue resulted primarily from a weaker Canadian dollar compared to the second quarter of the previous year.

The wastewater treatment and water distribution customer base grew marginally by 0.7 per cent over the total customers at the same time in 2008. For the second quarter, operating profit totalled 4 million as compared to 3.6 million during the same period last year. Overall, utility services business unit achieved Algonquin’s expectations. During the quarter, operations provided approximately 1.55 billion U.S. gallons of water to its customers, treated approximately 475 million gallons of wastewater and sold approximately 105 million gallons of treated effluent.

As an update to Algonquin’s liquidity position, as noted on page 30 in our MD&A, we ended the quarter with $26.7 million in cash reserves and committed bank facilities, an improvement over Q2-2008 where total liquidity was 17.7 million. I also wanted to underline that Algonquin remains in full compliance with all its covenants under its loans and credit facilities. We continue to have the full support of a strong syndicate of four Canadian banks who are fully supportive of Algonquin’s growth plans and prospects.

Looking ahead to the next quarter, the renewable division is expected to perform at or above long-term averages in third quarter of 2009 based on wind and hydrology conditions with the exception rather of the western region where we expect at or below long-term averages.

In addition, the Ontario region is anticipating lower average energy rates during the remainder of 2009 at the Long Sault facility, resulting from rate adjustments in the PPA. And the hydro facilities in the New England and New York regions are expected to experience reduced market rates as compared to the rates experienced in 2008 as a result of a decrease in the demand for electricity from the current economic climate in those markets.

The EFW facility is expected to operate in line with management’s expectation during the third quarter while the Windsor Locks and Sanger facilities are expected to operate below expectations due to lower natural gas costs and reduced demand for steam resulting from the U.S. economic slowdown.

For the remainder of 2009, utility services is not expecting any material change in water or wastewater customers.

With our major capital program complete, we are in the process of filing a number of rate cases including cases at five Arizona utilities and six utilities in Texas. It is anticipated that regulatory review of the rates and tariffs for our Arizona utilities would be completed in the latter half of 2009 and early 2010 with the new rates going into effect throughout 2010. While a firm forecast of rate increases at these facilities is not possible as the rate cases are in the early stages, the expectation is a potential increase in EBITDA of approximately $10 million starting in 2010. Further details on the rate cases are detailed on page 22 of our MD&A.

I will now turn the call back to Chris Jarratt who will share with you some of Algonquin’s growth and development projects. Chris?

CHRIS JARRATT: Great, thanks David. I’ll start today with an update on the 25 megawatt Red Lily wind project which is located in South-eastern Saskatchewan. In addition to the milestones achieved to dates, we continue to assess the viability of this project with respect to financing and capital costs. In addition, we are also assessing the viability of an expanded project and have secured additional land in the area to support phase two of the project.

During the quarter, Algonquin and Natural Resources Canada executed a contribution agreement under the eco energy for a renewable power program for phase one of the Red Lily project which secures funding for the project. The environmental impact assessment documentations have been submitted for review by Natural Resources Canada, and during the quarter the Saskatchewan Environmental Assessment Branch confirmed that requirements under the Provincial Environmental Assessment Act had been satisfied for phase one of the project.

Building on the success of the St. Leon wind energy project, Algonquin Power continues to move forward with obtaining the necessary federal and provincial approvals for a future expansion of the existing facility and a future adjacent project. These opportunities have a potential generation capacity of over 85 megawatts and are estimated to require an investment of approximately $250 million.

As a follow up to the successful repowering of the Sanger cogeneration project, there are 14 megawatts of additional power available in excess of what is currently being sold under the existing power purchase agreement. Of this additional capacity, six megawatts can be sold with no further investment in the facility. A supplemental supply contract is being negotiated with PG&E to sell the six megawatts of power at a slight discount to hourly market rates. The facility would utilize this additional contract capacity when gas and electricity markets provide a positive spark spread.

For the remaining eight megawatts, it is forecast that an upcoming interconnection voltage change by the utility will eliminate the current 48-megawatt connection capacity limitation. And our development team has begun the process of applying for interconnection capacity for this additional eight megawatts.

At the Windsor Locks facility, we are reviewing two options as the power purchase agreement reaches maturity in 2010. The first option involves maximizing net revenue from the existing equipment by operating the turbine at a reduced output to service the steam and power requirements of Ahlstrom and selling up to 40 megawatts of electrical capacity as backup energy to the independent system operator.

The second option under analysis involves repowering the facility with new equipment to match the current steam and electrical demand of the Ahlstrom mill in addition to maintaining the existing turbine equipment as backup capacity to the independent system operator or peaking revenue which is supported by a positive spark spread. We will continue to provide updates on both these options as we continue our review.

With the energy from waste facility, the development division continues to negotiate with the Region of Peel to expand the power generation and waste processing capacity between 40,000 and 100,000 tonnes per year. If the expansion is pursued, depending on the proposal selected, an investment of between $600 million and $250 million would likely be required. They’re currently evaluating the feasibility of an expansion including the associated capital costs and operating costs and financing terms. We will continue to keep you informed on the progress of these projects as we move forward.

In summary, in accordance with our strategy, Algonquin Power has had a very active second quarter, having made three significant announcements that will contribute to realizing our long-term goals. These activities demonstrate Algonquin’s commitment to invest in the business, identify appropriate growth opportunities and remain focused on the long- term goal of increasing value.

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

OPERATOR: Thank you. Ladies and gentlemen, we will now conduct the question-and-answer session. If you have a question, please press the * followed by the 1 on your touchtone phone. You will hear a tone acknowledging your request. Your questions will be polled in the

order they are received. Please ensure you lift the handset if you are using a speakerphone before pressing any keys. One moment, please, for our first question.

Our first question comes from Tony Courtright, of Scotia Capital. Please go ahead.

TONY COURTRIGHT: Thanks very much. You have a very detailed table of liquidity on page 30. I appreciate that. I did notice at the top line, the committed bank credit facilities have declined by about 3.7 million quarter over quarter. Could you elaborate on what accounts for that?

DAVID BRONICHESKI: Yes, certainly. It’s really as a result of the slight dip in our EBITDA, the upper limit of that facility is now 189 million.

TONY COURTRIGHT: And is that a permanent reduction or could it float back up if EBITDA improved?

DAVID BRONICHESKI: No, it can float back up as EBITDA improves.

TONY COURTRIGHT: And what’s the upper limit?

DAVID BRONICHESKI: Right now, we have committed facilities of 192 million 750.

TONY COURTRIGHT: So it could go back up to that limit. In the constraining, what was the specific metrics on the constraining EBITDA ratio?

DAVID BRONICHESKI: The governing covenant is the debt to EBITDA.

TONY COURTRIGHT: So a debt to EBITDA. And what is the numeric… what is the ratio, absolute ratio limit that constrained it?

DAVID BRONICHESKI: Right now, what we do is we calculate what the effect of the covenant is because the calculation actually is rather complicated; so we thought rather than give a number and then you potentially have people calculating different numbers, we just thought to provide the actual calculation.

TONY COURTRIGHT: Alright. In terms of Windsor Locks, you have outlined two approaches to dealing with your energy sales agreement. Ahlstrom beyond the term of the existing PPA was Connecticut Light & Power. What would transpire if you didn’t choose to honour the energy sales agreement to Ahlstrom? Like is there a commercial penalty that you might be exposed to? What’s the walk-away cost from not honouring the energy sales agreement with Ahlstrom after the Connecticut Light & Power PPA expires?

CHRIS JARRATT: It’s Chris speaking, Tony. I don’t believe there is one, but we are very confident that we would be able to honour it. You know, one of the activities that was undertaken last quarter was we basically ran a test of the turbine at that reduced output. It was done to confirm the desktop exercise that said that was possible. And it was very successful and we were able to operate the turbine at a reduced output and service the Ahlstrom steam and electricity needs.

TONY COURTRIGHT: Presumably at a penalty in terms of your heat rate efficiency?

CHRIS JARRATT: Yes, there is a slight penalty that way, but we believe that’s more than made up for by the second part to that option, which is to basically get paid to be what’s called spinning reserves which is you’re basically there if, as and when required and you’re paid by the ISO operator there to fill that role.

TONY COURTRIGHT: And in terms of emission allowances or greenhouse gas offsets, are they a pass-through to the power purchaser, the energy sales purchaser, or do you absorb them yourself?

CHRIS JARRATT: Are you talking on Windsor Locks?

TONY COURTRIGHT: Specifically, yes.

CHRIS JARRATT: No, we absorb them ourselves.

TONY COURTRIGHT: Right. So would an investment in new appropriately-sized turbines steam generation for the Ahlstrom contract only be undertaken if you had sufficient ancillary service contracts, because the actual term of the energy sales agreement is relatively finite in length?

CHRIS JARRATT: Yes, of course it would. We would have to. You know, we’re in the midst of conversations with Ahlstrom about getting that extended, as well as exploring opportunities to take on other customers.

TONY COURTRIGHT: Okay. So, I mean you’d only commit new capital if you had sufficient contractual horizon to ensure recovery of it.

CHRIS JARRATT: Yes, absolutely.

TONY COURTRIGHT: Okay. Those are my questions. Thank you.

CHRIS JARRATT: Thanks, Tony.

OPERATOR: Our next question comes from Bob Hastings, of Canaccord Adams. Please go ahead.

CHRIS JARRATT: Hi, Bob.

BOB HASTINGS: Hi. Just to finish up on what Tony had raised there at Windsor Locks, once Connecticut Light & Power is gone, there’s obviously a step down in the operating profitability; but did I hear you say that you thought that the spinning reserves potential would offset that or just offset the heat rate?

CHRIS JARRATT: No, it would offset that to some degree. It might not be a complete offset, but certainly you’d get paid quite well to have capacity there if it’s needed.

BOB HASTINGS: So, right now, that Windsor Locks throws off normally something around, what, $10 million of operating income?

CHRIS JARRATT: Yes, maybe not quite that much but depending on the gas price, yes.

BOB HASTINGS: So if we were looking at, once Connecticut Light & Power is gone, does that get cut in half or is it more or can you give us some kind of guidance say without the spending reserves?

CHRIS JARRATT: Yes. I don’t think we’re prepared to do that right now just because we’re in the midst of finalizing some of these details.

BOB HASTINGS: Okay, but… Okay, fair enough. And the St. Leon warranties and payments that will be starting up in maintenance payments, is that kicking in just in the second half here? Or can you give us an idea of how significant that might be?

CHRIS JARRATT: Yes, it kicks in starting September and, you know, in terms of the quantum it’s probably about $1 million in 2009; maybe a bit less than that.

BOB HASTINGS: So we should prorate that for next year and say it’s a few million dollars?

CHRIS JARRATT: Yes, you’re probably not far off. Yes.

BOB HASTINGS: Okay. And you’ve deferred some capex spending this year: 3 million in one instance for Windsor Locks and 3 million on the dam. Can you sort of give us some details around that?

CHRIS JARRATT: Yes, sure. The $3 million that Windsor Locks was a number we were carrying in our budget. It was contemplated that we would likely be doing a repowering of that facility. And, as I’ve mentioned, we just talked about it a couple of minutes ago, it looks like there’s a very good opportunity to basically just set the option one at Windsor Locks which is to have it in spinning reserves and satisfy the needs of Ahlstrom with existing equipment. That option looks very promising, so before we spend money on a new turbine we just want to run that to ground to see if that’s possible. So, that accounts for the one amount you referenced, the 3 million.

The other is related to the dam repairs at Donnacona and those costs have been deferred for a year. And, once again, we are just exploring some other alternatives with respect to the technical alternatives that are available, as well as the construction timing of that project. So that was just a deferral of $3 million.

BOB HASTINGS: Right. And I was kind of interested in that one because there had been talks before that maybe some of that might be able to be offset, or other contributions from other sources and I just didn’t know if this gave us a little bit of hope that maybe the spending might be, you know, the net impact might be lower or at least delayed.

CHRIS JARRATT: Yes, and that’s the type of things we’re exploring. And of course we’re very hopeful that we’ll be able to do something there.

BOB HASTINGS: Great. Okay. Thank you very much.

CHRIS JARRATT: Thanks, Bob.

OPERATOR: Our next question comes from Carolina Vargas, of Clarus Securities. Please go ahead.

CAROLINA VARGAS: Good morning, everyone. A few questions: The first one is that you had a rather large gain from derivative instruments and if you can elaborate on that and what is your expectation for the next quarters?

DAVID BRONICHESKI: Certainly, yes. In the financial statements I think people have noticed there’s an unrealized gain of 11.7 million. Overall, it nets, when you take the realized losses into account. I mean, that really is a result of the mark-to-market adjustments that are made each quarter to the hedging position that we have on our books for FX and also on the interest rate swaps that we have in place.

And really it’s almost by definition, one can’t really give guidance on what that’s going to be going forward because it really is just dependant upon where the FX rates go, if we have an appreciation in the U.S dollar

relative to the Canadian dollar. You know, that would have been one thing. If the currency goes the other way, then that would mean something else. Same thing with interest rates. As interest rates move, so will the unrealized mark-to-market gain or losses on the swaps.

And what we do in the MD&A, I don’t have the exact page reference off the tip of my tongue, but what we do there is we quantify what the effect of a certain swing one way or another in those are. And so individual analysts are then able to kind of do their own sensitivity on that and mesh that with their own individual expectations of where interest rates and currencies may go.

CAROLINA VARGAS: Okay, thank you. And the next question is you mentioned that you’re assessing different funding opportunities for the different projects, and I just wanted to get your view on what is happening with the markets in terms of financing of these projects, in terms of rates and funds available for development.

DAVID BRONICHESKI: Well, I mean, it really does depend on the project. You know, as an example, with Red Lily there definitely is a very strong demand for debt instruments associated with a project that would be of the quality that Red Lily is. You know, also mesh that up with the possibility that we could be doing a … financing with that where you could have a flow-through of the CCA associated with that.

That particular arrangement is also very, very attractive. So when it comes to projects like that there definitely is a strong appetite for financing there. And we’re also seeing just in general, there’s a little bit of loosening up in the credit markets and spreads are coming down. So, you know, as we move a number of these projects forward, we’re fully confident that we’ll be able to have the financing in place.

CAROLINA VARGAS: Okay. Thank you.

OPERATOR: The next question comes from Matthew Akman, of Macquarie Research. Please go ahead.

MATTHEW AKMAN: Thanks very much. Were hydro levels in New England on your facilities above or below normal in the quarter?

CHRIS JARRATT: They were slightly above average, long-term average. They were down from last year, which was a very good year, but they were slightly above long-term averages.

MATTHEW AKMAN: Thanks. What is your hedging policy on the merchant capacity, if any, and have you considered putting hedges in place for that?

CHRIS JARRATT: Right now, we don’t. We sell into the spot market but obviously with this… and I might add we’ve done quite well over that for the past several years; but obviously we are exploring what can be done to hedge the energy that comes off those facilities.

MATTHEW AKMAN: Is there anything you could do with Emera there because they obviously have a business that does that in that region?

CHRIS JARRATT: Yes, and we’re exploring all options.

MATTHEW AKMAN: Okay, thanks. Moving forward to the thermal energy division and your development activities, can you please explain, first of all, the revenue model that you’re pursuing on the expansion of the energy from waste facility? And second, what kinds of returns on capital you’d be looking for on the 60 to 250 million you’d be investing there?

CHRIS JARRATT: Can you just…? I’m a little unclear as to what you’re looking for in the first part of that question, the first question.

MATTHEW AKMAN: Who’s your customer?

CHRIS JARRATT: Oh, the customer is the Region of Peel.

MATTHEW AKMAN: But there are steam customers as well, is that correct?

CHRIS JARRATT: That is correct. I mean, we have an existing arrangement that we wouldn’t be changing and it runs for probably 19 more years. It’s a mill down the road. So, the other customer I suppose is OEFC with regard to the electricity that we sell into the grid.

MATTHEW AKMAN: But the main customer then would continue to be the Region of Peel for revenue on that investment?

CHRIS JARRATT: Yes. I mean that would be our first choice. I mean, it’s a waste-burning facility that’s located right in Peel. If Peel, for whatever reason, where something didn’t happen, I mean there are other customers, but clearly Peel is the preferred choice. With regard to our investment criteria, we kind of have a bit of a target of a return of about 10 per cent on an unlevered basis. That’s just kind of a guideline as to where we’re trying to head to.

MATTHEW AKMAN: How do you measure that? Is that an IRR calculation?

CHRIS JARRATT: Yes. And of course we are very cognizant of the early years as well. Again having a back-end loaded IRR calculation for 20 years probably wouldn’t do us much good.

MATTHEW AKMAN: Okay. Thanks. Those are my questions.

CHRIS JARRATT: Great. Thank you.

OPERATOR: Ladies and gentlemen, if there are any additional questions at this time, please press the * followed by the 1. As a reminder, if you are using a speakerphone, please lift the handset before pressing the keys.

And our next question comes from Matt Gowing, of Research Capital. Please go ahead.

MATT GOWING: Hello, everyone. Just a few questions here. I’ll start off with your power places in the New England and New York merchant region where you have some hydro facilities there. I’m wondering if you can give us any colour on what your total average price per megawatt/hour was this quarter and how that compared to the same quarter in last year.

CHRIS JARRATT: Yes, it’s about between $0.03 and $0.04 this year, and last year it was basically twice that; so it’s between $0.06 and $0.08.

MATT GOWING: Great. And then how does that compare with the remainder of your power portfolio in terms of the portion of the portfolio that’s contracted? What was the average contracted rate for the contracted portion of your portfolio?

CHRIS JARRATT: I don’t have that number. I’d be guessing, but every site is different. But if I had to guess, I’d say the average is probably in the $0.06 range.

MATT GOWING: Great, thanks. I have some questions around your steam sales. You talked about lower steam sales at Windsor Locks and Sanger being a head wind on the quarter. Can you quantify at all what your steam sales were in terms of dollars, in terms of revenues at Windsor Locks and Sanger and then how that compared versus last year and perhaps what your outlook is going into Q3?

CHRIS JARRATT: Sure, I don’t know if can quantify exactly because we don’t really track that, I don’t have it right in front of us. But at Windsor Locks the way it works is we get paid a capacity factor, which is really meant to pay you for your capital that’s in the ground and then you get paid as you sell the steam, and it was originally intended to basically be a pass-through of your costs. The way it has evolved is it’s more or less a pass-through of your costs, but we do make a little bit of money when we do sell steam at Windsor Locks.

So we are receiving the capacity payment and Ahlstrom is not taking as much steam as they were. So, that’s why the revenues associated with steam sales are down a little bit. And the same goes for Sanger. It’s essentially the same arrangement.

MATT GOWING: Okay. So there’s a capacity payment portion and then some other payment variable tied to variable volume amounts. The Ahlstrom facility, you talk about that facility having an unplanned two-week plant shutdown. Is that going to be a material impact on Q3 results considering that there is a capacity payment side to the revenues from that facility?

CHRIS JARRATT: It shouldn’t be a significant one because, as I say, the capacity payment, we still receive that.

MATT GOWING: Great. I’m impressed with the performance from the utilities service business; Year over year growth of 14 per cent in both revenue and EBITDA. You talk about the challenged housing market down in the South, in the Southwest U.S. So, what drives the pretty solid results there?

DAVID BRONICHESKI: The increase has largely been driven by the change in exchange rates year over year. You might recall last year, the Canadian dollar was sitting at near parity with the U.S. dollar, whereas this year the Canadian dollar has slipped. So therefore, those U.S. revenues are stronger.

MATT GOWING: Okay, great. And just on the Windsor Locks, the repowering options that you’re exploring, do you have any sort of timeline when you think you’ll have a decision made on that and when you’ll make that decision public?

CHRIS JARRATT: No, I don’t have an exact timeline, but I can say we are getting close. So I would I expect in the next couple of quarters, if not next quarter, probably the quarter after we’ll have something.

MATT GOWING: Okay, great. That’s it for me, guys. Thanks.

CHRIS JARRATT: Thank you very much.

OPERATOR: Next question comes from Tony Courtright, of Scotia Capital. Please go ahead.

TONY COURTRIGHT: Thanks very much. Just a clarification in terms of timing: You’re anticipating circulating a management information circular for the proposed reorganization, are you not?

DAVID BRONICHESKI: I’m pleased to speak to the unit share exchange transaction that we recently announced and we are expecting to shortly have a takeover bid circular going out. One thing that I would like to note is we have over 25 per cent of our unitholders are in the United States; and so, because of that, the transaction has required an SEC filing, and so we’re in the process now of working through, it’s called a form F4 SEC filing. And so we’re in the comment period right now with the SEC and we expect to work through that over the next two to three weeks. And as soon as we have the SEC clearance, then we’ll be looking to put out the takeover bid circular.

TONY COURTRIGHT: So, general timing, are you permitted to… like when would you, on your best wish, see this sort of consummated?

DAVID BRONICHESKI: Well, obviously, we want to close it as soon as we can, but our current expectation rate is now is it will close sometime in October.

TONY COURTRIGHT: Great. So that would be post a meeting? So the meeting then would likely transpire sometime in October and you would resolve…?

DAVID BRONICHESKI: Actually, just to be clear, there actually won’t be a need for a meeting. It’s a takeover bid circular and our unitholders will simply tender to the offer.

TONY COURTRIGHT: I see. I appreciate that clarification. Thank you.

CHRIS JARRATT: Thanks, Tony.

OPERATOR: Next question comes from Angela Lam, of Fraser Mackenzie. Please go ahead.

ANGELA LAM: Hi there. I’d just like to ask a question on behalf of John Safrance. Why was power production at the St. Leon wind facility down so much sequentially?

CHRIS JARRATT: I think it was down primarily because, on a quarter-by-quarter basis, there are windy quarters and not-so-windy quarters, and Q2 is a not-so-windy quarter. I mean, it’s still a pretty good quarter if you look at it from a capacity factor point of view. I think that the capacity factor worked out like 39 per cent, which one of our windiest quarters is the first one, which was at 49 per cent. So…

ANGELA LAM: Okay. Thank you very much.

CHRIS JARRATT: Great. Thanks.

OPERATOR: The next question comes from James Morrison, of Cormark Securities. Please go ahead.

JAMES MORRISON: Hi, there. Just maybe you could take us through at the… in the thermal division you’re saying that the natural gas prices are essentially a pass-through but they’re also being blamed for their impact on profitability. So, maybe you could take us through that.

CHRIS JARRATT: Sure. What I said was it’s largely a pass-through. Most of the gas is hedged and it’s a bit of a complicated formula for how it’s done. But at the Windsor Locks facility, you can think of it as about 75-per-cent hedged; so you’ve got a 25 per cent unhedged. I think on page 42 of our report you’ll find a more detailed description of it, but that’s the big driver there is Windsor locks gas contract.

JAMES MORRISON: Okay, great. And then in terms of your transmission curtailment that you’re talking about for Sanger, does that have the ability to impact current production or is that just for the expansion?

CHRIS JARRATT: It’s just for the expansion.

JAMES MORRISON: Okay. And then what kind of impact would that have on the profitability of that expansion?

CHRIS JARRATT: It wouldn’t have any, as we stand today, it’s just an upside potential that’s there.

JAMES MORRISON: Right. So it’s limiting you to six.

CHRIS JARRATT: Yes. Right today, it limits us to six.

JAMES MORRISON: Okay, great. Thank you. That’s all my questions.

CHRIS JARRATT: Great, thank you.

OPERATOR: And we have a follow up from Carolina Vargas, of Clarus Securities. Please go ahead.

CAROLINA VARGAS: Thank you. Just a follow up on the internalization of management; what kind of progress have you made in that front?

DAVID BRONICHESKI: As we noted in page four of our MD&A disclosures, the board has retained advisors to assist them with the internalization and discussions do continue between the manager and the board. And the board, at the moment, believes that they should have this process completed by the end of the year.

CAROLINA VARGAS: By the end of the year. And, in terms of that, if there will be any cash outflows if you decide to bring the management in-house, meaning that if there’s any penalty on bringing management in house?

DAVID BRONICHESKI: All I can say is, you know, clearly the management contract does have some value, and that’s part of the reason why the board has retained advisors in that process. But at this point, we can provide no guidance on what that number might be.

CAROLINA VARGAS: Okay. Thank you.

OPERATOR: Your next question comes from Matt Gowing, of Research Capital. Please go ahead.

MATT GOWING: Hello again. Just a follow-up question on your waste disposal business from Peel. You talk about a contract you’d entered into for airline waste processing and that contract was at higher

rates than most of your other business within there but had a lower volume aspect to it. Can you just quantify what percentage of the waste comes from the airline and when will that contract end? I’m just wondering if it’s going to be a lingering impact in the Q3 results.

CHRIS JARRATT: Right. It’s Chris Jarratt talking. It doesn’t really have an impact, and the reason is because right today that Peel facility handles about 50 per cent of the Region of Peel’s waste. For a few years there, we ran about 10,000 tones year of international airport waste through the facility. And for that we got paid a fairly high rate to take that waste.

What’s not in any of the statements is the fact that the costs associated with that waste were also higher. It had to be handled in a different way, so there were much higher internal costs to deal with it. So it doesn’t really have any impact because yes, the tip fees will go down because we have lots of excess waste within the Region of Peel that we can fill that void with and our operating costs will also drop because it’s a different type of waste and it’s much easier to handle. So there is no real impact.

MATT GOWING: Great. And just my last question, just following up on the back of the question regarding the utilities services business and the growth and revenue and EBITDA, if you strip out the impact from foreign exchange, on an organic basis how much do you think that revenue changed and EBITDA changed year over year?

DAVID BRONICHESKI: I believe we’ve quantified that in the MD&A disclosures with respect to utilities. But pretty much because the customers were flat and we had no rate increases largely to speak of, the change would have been relatively small. So we’re attributing, by far, the majority of that change to the movement in the FX rates.

MATT GOWING: Okay, thank. Thanks for taking my questions.

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

CHRIS JARRATT: Great. I’d like to thank everybody for joining us on this call today and please remain on the line for a review of our disclaimers.

OPERATOR: Certain written and oral statements contained in this information are forward looking within the meaning of certain securities laws and respective views of Algonquin Power Income Fund and its manager with respect to future events based upon assumptions relating to, among others, the performance of the company’s assets and the business, financial and regulatory climate in which it operates. These forward-looking statements include, among others, statements with respect to the expected performance of the company, its future plans, and its distribution to unitholders.

Statements containing expressions such as believes, anticipates, continues, could, expect, may, will, project, estimates, intend, plan, and similar expression generally constitute forward-looking statements.

Since forward-looking statements relate to future events and conditions, by their very nature they require us to make assumptions 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 the continued volatility of world financial markets, the impact of movements in exchange rates and interest rates, the effects of changes in environmental and other laws and regulatory policy applicable to the energy and utility sectors, decisions taken by regulatory or monetary policy and the taxation of income fund and the state of the Canadian and the U.S. economy and accompanying business climate.

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

Expect as required by law, the company and its managers do not intend to update or revise any forward-looking statements whether as result of new information, future developments or otherwise.

This communication has referred to the proposed takeover bid by Hydrogenics Corporation to the security holders of Algonquin Power Income Fund. In connection with the proposed transaction of Hydrogenics initially filed on July 13, 2009 a registration statement on Form F-4 containing a preliminary takeover bid circular/prospectus with the U.S. Securities and Exchange Commission. Each of Algonquin and Hydrogenics will be filing other documents regarding the proposed transaction with the SEC.

Before making any investment decision, securityholders are urged to read to registration statement, including the takeover bid circular regarding the proposed transaction and other filed documents carefully in their entirety, when they become available because they do and will contain important information about the proposed transaction.

The final takeover bid circular will be mailed to Algonquin’s securityholders. Investors and securityholders will be able to obtain the registration statement contained in the takeover bid circular prospectus and other documents free of charge at the SEC website, www.sec.gov, or from Hydrogenics Corporation, 5885 McLaughlin Road, Mississauga, Ontario, L5R 1B8, Canada, Attention: Relations at 905-361-3660.

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

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