Algonquin Power & Utilities Corp (AQN) 2009 Q2 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Algonquin Power second-quarter analyst conference call. (Operator Instructions). I would like to remind everyone that this conference call is being recorded on Friday, August 14, 2009, at 10 AM Eastern time. I will now turn the conference over to Chris Jarratt, Executive Director. Please go ahead, sir.

Thank you, Joanne. Good morning. My name is Chris Jarratt, and I am an Executive Director of Algonquin Power. I would 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; Luisa Read, 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 position, 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, 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 CAD3.25 per unit, which is expected to represent 9.9% 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% of the newly-formed California Pacific Electric Company, which intends to acquire 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, 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 Power on a one-for-one basis.

Shares of the corporation will continue to receive monthly dividends equal to current distributions of CAD0.24 per unit annually, and will also be listed 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 offer -- offers are available on Algonquin's website.

The Board of Trustees and the manager believes that having Algonquin's business conducted under a new corporate structure will benefit Algonquin Power within the capital markets and will increase Algonquin Power's competitive effectiveness in the power and utilities 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, 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 a 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 from 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 regulated 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 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 cogeneration 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 passthrough to energy prices.

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

Thanks, Chris. Now for a review of the Q2 2009 results.

In the second quarter, our revenue was CAD46.5 million, as compared to CAD54.2 million the year before. Our EBITDA, though, came in at CAD20 million as compared to CAD22.9 million in the previous year's quarter.

Net earnings were CAD15.3 million, compared to CAD8 million last year. On an adjusted net earnings basis, our net earnings were CAD3.8 million compared to CAD4.3 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 totaled CAD17.5 million, and the division generated electricity equal to approximately 101% of long-term projected average wind and hydrology.

The small decrease in revenue is mainly a result of lower weighted-average energy rates in the New England region, which was partially offset by increased average hydrology, compared to the same period last year, in Québec, New York, and New England regions.

For the second quarter of 2009, operating profit totaled CAD12.4 million, as compared to CAD14.5 million during the same period of 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, revenue for the second quarter of 2009 totaled CAD13.2 million, as compared to CAD14.4 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 passthrough in the rates.

During the quarter, production increased by 5,000 MWh at the Sanger facility and 8,000 MWh at the Windsor Locks facility. The landfill gas facilities increased energy production by 3,000 MWh during the quarter, and the EFW facility experienced decreased throughput over the same period in 2008, processing just over 35,000 tons.

For the second quarter of 2009, operating profit totaled CAD6.3 million, as compared to CAD7.2 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 from steam -- or 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 totaled CAD9.9 million, as compared to CAD8.7 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% over the total customers at the same time in 2008.

For the second quarter, operating profit totaled CAD4 million, as compared to CAD3.6 million during the same period last year. Overall, the 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 entered the quarter with CAD26.7 million in cash reserves and committed bank facilities, an improvement over Q2 2008 where total liquidity was CAD17.7 million.

I also want to underline that Algonquin remains in full compliance with all of 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 renewables division is expected to perform at or above long-term averages in the 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 an 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 expectations 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 CAD10 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?

Great. Thanks, David. I will start today with an update on the 25 MW Red Lily wind project, which is located in southeastern Saskatchewan. In addition to the milestones achieved to date, 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 a large -- Phase 2 of the project.

During the quarter, Algonquin and Natural Resources Canada executed a contribution agreement under the ecoENERGY for Renewable Power Program for Phase 1 of the Red Lily project, which secured funding for the project.

The environmental impact assessment documentation has been submitted for review by Natural Resources Canada and during the quarter, the Saskatchewan Environmental Assessment branch confirmed that the requirements under the provincial Environmental Assessment Act had been satisfied for Phase 1 of the project.

Building on the success of 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 MW and are estimated to require an investment of approximately CAD250 million.

As a follow-up to the successful repowering of the Sanger cogeneration project, there are 14 MW of additional power available in excess of what is currently being sold under the existing power purchase agreement. Of this additional capacity, 6 MW can be sold with no further investment in the facility.

A supplemental supply contract is being negotiated with PG&E to sell this 6 MW 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 8 MW, it is forecast that an upcoming interconnection voltage change by the utility will eliminate the current 48 MW connection capacity limitation. And our development team has begun the process of applying for interconnection capacity for this additional 8 MW.

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 MW of electric capacity and 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 these options, both these options, as we continue our review.

The energy-from-waste facility -- the development division continues to negotiate with the Region of Peel to expand power generation and waste-processing capacity by between 40,000 and 100,000 tons per year. If the expansion is pursued, depending on the proposal selected, an investment of between CAD60 million and CAD250 million would likely be required.

We are 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 Instructions). Tony Courtright, Scotia Capital.

You have a very detailed table of liquidity on page 30. I appreciate that. I did notice at the topline, the committed bank credit facilities declined by about CAD3.7 million, quarter over quarter. Could you elaborate on what accounts for that?

Certainly. It's really the -- as a result of the slight dip in our EBITDA, the upper limit of that facility is now CAD189 million.

Is that a permanent reduction or could it float back up if EBITDA improved?

No, it can float back up as EBITDA improves.

What's the upper limit?

Right now, we have committed facilities of CAD192.750 million.

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

It's the -- the governing covenant is the debt to EBITDA.

So, debt to EBITDA. And what is the numeric -- what is the ratio -- absolute ratio limit that constrained it?

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.

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 with Connecticut Light and Power.

What would transpire if you didn't choose to honor the energy sales agreement to Ahlstrom? Like, is there a commercial penalty that you might be exposed to? What's the walkaway cost from not honoring the energy sales agreement with Ahlstrom after the Connecticut Light and Power PPA expires?

It's Chris speaking, Tony. I don't believe there is one, but we are very confident that we would be able to honor 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.

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

Yes, there was -- there is a slight penalty that way. But that is -- we believe that's more than made up for by the second part to that option, which is to basically be -- 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 to sit there to fill that role.

In terms of emission allowances or greenhouse gas offsets, are they a passthrough to the power purchaser, the energy sales purchaser, or do you absorb them yourself?

Are you talking on Windsor Locks?

Specifically, yes.

No, we absorb them ourselves.

Would an investment in new, appropriately-sized turbine 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.

Yes, of course it would. We would have to -- we are in the midst of conversations with Ahlstrom about getting that extended, as well as exploring opportunities to take on other customers.

Okay, so I mean you'd only commit new capital if you had sufficient contractual horizon to ensure recovery of it?

Yes, absolutely.

Bob Hastings, Canaccord Adams.

Just the -- to finish up on what Tony had raised there, at Windsor -- Windsor Locks, the -- once Connecticut Light and 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?

No, it would offset that to some degree. It may not be a complete offset, but it's certainly -- you get paid quite well to be -- to have capacity there if it's needed.

So right now, that Windsor Locks throws off normally something around, what, CAD10 million of operating income?

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

So, if we were looking at once Connecticut Light and Power is gone, does that get cut in half, or is it more? Can you give us some kind of guidance, say, without the spinning reserves?

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.

Fair enough. The St. Leon warranties and payments that will be starting up, and maintenance payments, is that -- is that kicking in just in the second half here? Can you give us an idea how significant that might be?

Yes, it kicks in starting September, and in terms of the quantum, it's probably about CAD1 million in 2009. It may be a bit less than that.

So we should pro-rate that for next year and say it's a few million dollars?

Yes, (multiple speakers) probably not far off, yes.

Okay. And you've deferred some CapEx spending this year, CAD3 million in one instance for Windsor Locks and CAD3 million on the dam. Can you sort of give us some details around that?

Yes, sure. The CAD3 million at 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 a couple of minutes ago, it looks like there is a very good opportunity to -- basically, to set the option one at Windsor Locks, which is to have -- being in the spinning reserves and satisfy the needs of Ahlstrom with the 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 CAD3 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 CAD3 million.

Right. And I was kind of interested in that one because there had been talk 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 this spending might be -- you know, the net impact might be lower or at least delayed.

Yes, and that's the type of things we are exploring and, of course, we're very hopeful that we'll be able to do something there.

Carolina Vargas, Clarus Securities.

A few questions. The first one is that you had a rather large gain from derivatives instruments, and if you can elaborate on that. What is your expectation for the next quarters?

Certainly, yes. The -- in the financial statements, as I think many people have noticed, there is an unrealized gain of CAD11.7 million.

But overall, it nets when you take the realized losses into account. I mean, that really is the 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 truly give guidance on what that's going to be going forward because it really is just dependent upon where the FX rates go. If we have an appreciation in the U.S. dollar relative to the Canadian dollar, that would be 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 well the unrealized mark-to-market gains or losses on the swaps.

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.

The next question is -- you mentioned that you are assessing different funding opportunities for the different projects. And I just want to get your view in the -- what is happening with the markets in terms of financing of these projects, in terms of rates and funds available for development?

There is -- it really does depend on the project. 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, we'd also mesh that up with the possibility that we could be doing a [sirsi] 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 is a little bit of loosening up in the credit markets and spreads are coming down. So as we move a number of these projects forward, we are fully confident that we'll be able to have the financing in place.

Matthew Akman, Macquarie Research Equities.

Were hydro levels in New England on your facilities above or below normal in the quarter?

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.

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

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 those -- the energy that comes off those facilities.

Is there anything you can do with Emera there? Because they obviously have a business that does that in that region.

Yes, and we're exploring all options.

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 are 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 CAD60 million to CAD250 million you would be investing there?

Can you just -- I'm a little unclear what you're looking for in the first part of that question. The first question?

Who is your customer?

Oh, the customer is the Region of Peel.

But they're a steam customer as well, is that correct?

That is correct. 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 we -- the other customer, I suppose, is OEFC with regard to the electricity that we sell into the grid.

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

Yes, that would be our first choice. It's a waste-burning facility that's located right in Peel. If Peel, for whatever reason, were -- something didn't happen, 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 about 10% on an unlevered basis. That's just kind of a guideline as to where we are trying to head to.

How do you measure that? Is that an IRR calculation?

Yes. And, of course, we are very cognizant of the early years as well. Like, having a backend-loaded IRR calculation for 20 years probably wouldn't do us much good.

Matt Gowing, Research Capital Corporation.

I'll start off with your power prices in the New England and New York merchant region, where you have some hydro facilities there. Wondering if you can give us any color on what your total average price per megawatt hour was this quarter, and how that compared to the same quarter in last year?

Yes, it's about between CAD0.03 and CAD0.04 this year, and last year it was basically twice, so it's between CAD0.06 and CAD0.08.

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

I don't have that number. I'd be guessing, but every site is different. But I would say -- if I had to guess, I would say the average is probably in the CAD0.06 range.

I have some questions around steam sales. You talked about lower steam sales at Windsor Locks and Sanger as 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?

Sure. I don't know if I can quantify it 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 passthrough of your costs.

The way it has evolved is it's more or less a passthrough 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.

The same goes for Sanger. It's essentially the same arrangement.

Okay, so there is a capacity payment portion and then some other payment variable tied to the variable volume amount.

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?

It shouldn't be a significant one because, as I say, the capacity payment is -- we still receive that.

Impressed with the performance from the utility services business, year-over-year growth of 14% in both revenue and EBITDA. You talk about the challenged housing market down in the south -- in the southwest U.S.. So what drived the pretty solid results there?

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.

Okay, right, and just on the Windsor Locks, the repowering options that you are exploring. Do you have any sort of timeline when you think you will have a decision made on that and when you will make that decision public?

No, I don't have an exact timeline, but I can say we are getting closer -- close. So I would expect in the next couple of quarters. If not next quarter, probably the quarter after we will have something.

Tony Courtright, Scotia Capital.

Thanks very much. Just a clarification in terms of timing. You are anticipating circulating a management information circular for the proposed re-organization, are you not?

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, is we have over 25% of our unitholders are in the United States. And so, because of that, the transaction has required an SEC filing. And so, we are in the process now of working through -- it's called a Form F4 SEC filing.

And so, we are in the comment period right now with the SEC and we expect to work through that over the next two to three weeks. As soon as we have the SEC clearance, then we will be looking to put out the takeover bid circular.

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

Obviously, we want to close it as soon as we can, but our current expectation right now is that it would close sometime in October.

Great. So that would be post a meeting -- so the meeting, then, would likely transpire sometime in October and you would (multiple speakers)

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.

[Angela Land], Fraser Mackenzie.

I would 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?

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.

It's still a pretty good quarter if you look at it from a capacity factor point of view. I think the capacity factor worked out to, like, 39%. Which -- one of our windiest quarters is the first one, which was up 49%.

James Morrison, Cormark Securities.

Maybe you could take us through -- in the thermal division, you're saying that the natural gas prices are essentially a passthrough. But they are also being blamed for their impact on profitability. So maybe you could take us through that.

Sure. What I said was it's largely a passthrough. 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% hedged.

So you've got a 25% unhedged -- on page 42 of our report, you will find a more detailed description of it, but that's the big driver there is Windsor Locks gas contract.

Okay, great, and then, in terms of your transmission curtailment that you're talking about for Sanger, does have the ability to impact current production or is that just for the expansion?

It's just for the expansion.

Okay, and then, what kind of impact would that have on the profitability of that expansion?

It wouldn't have any, as we stand today. It's just an upside potential that's there.

Right, so it's limiting you to six?

Yes, right today, it limits us to six.

Carolina Vargas, Clarus Securities.

Just a follow up on the internalization of management. What kind of progress have been made in that front?

As we noted in page 4 of our MB&A disclosures, the Board has retained advisers to assist them with the internalization, and discussions do continue between the manager and the Board. The Board, at the moment, believes that they should have this process completed by the end of the year.

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

All I can say is that, clearly, the management contract does have some value. And that's part of the reason why the Board has retained advisers in that process.

But at this point, we can provide no guidance on what that number might be.

Matt Gowing, Research Capital Corporation.

Just a follow-up question on your waste disposal business from Peel. You talk about a contract due to enter 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? Just wondering if it's going to be a lingering impact in the Q3 results.

It's Chris Jarratt talking. It doesn't really have an impact, and the reason is is because, right today, that Peel facility handles about 50% of the Region of Peel's waste.

For a few years there, we ran about 10,000 tons per year of international airport waste through the facility, and for that, we got paid a fairly high rate to take that waste.

But 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.

Great. And just my last question, just following up on the back of the question regarding the utility services business and the growth in 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?

I believe we've quantified that in the MB&A discloses with respect to utilities. But that -- pretty much because the customers were flat and we had no rate increases largely, to speak of, the change would've been relatively small.

So we are attributing, by far, the majority of that change to the movement in the FX rates.

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

Great. I would like to thank everybody for joining us on this call today, and please remain on the line for a review of our disclaimers.

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