Algonquin Power & Utilities Corp (AQNU) 2008 Q2 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Algonquin Power Q2 2008 results 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. (Operator Instructions).

I'd like to remind everyone that this conference call is being recorded on Friday, August 15, 2008, at 10 AM Eastern time.

I will now turn the conference over to Mr. Dave Kerr, Executive Director. Please go ahead, Sir.

Thanks, Maria. Good morning, everyone. My name is Dave Kerr and I am an Executive Director of Algonquin Power. I'd like to welcome you to Algonquin Power's second quarter 2008 conference call.

With me today is Chris Jarratt, an executive director of the Fund; David Bronicheski, the Chief Financial Officer; [Louetha Reed], our Controller; Kelly Castledine, our Manager of Investor Relations; and [Andrew Ingram], the Fund's Treasurer.

As a housekeeping issue, Kelly will quickly review our forward-looking statements disclaimer.

Certain statements contained in the information discussed today are forward-looking and reflect the views of expected future events of Algonquin and Algonquin Power management, the entity which provides management services to Algonquin, including advice and consultation concerning business planning, support, guidance and policymaking and general management services.

Since forward-looking statements address future events and conditions by their very nature, they involve inherent risks and uncertainties. Forward-looking statements are not guarantees of Algonquin's future performance or results and are subject to various factors including, but not limited to, assumptions such as those relating to the performance of the Company's assets, commodity market prices, interest rates and environmental and other regulatory requirements.

Although Algonquin and the manager believe that the assumptions inherent in these forward-looking statements are reasonable, undue reliance should not be placed on these statements which apply only as of the dates hereof.

Thank you, Kelly. Also up today was an announcement that was made during the quarter.

On May 13, Algonquin announced the intention to amalgamate with Highground Capital. Subsequent to the end of the quarter, Algonquin announced that the Highground shareholders approved the amalgamation at a special meeting held on July 28th with over 99% of the shares voted at the meeting being cast in favor.

The transaction was completed on August 1st and shareholders of Highground received 0.9749 trust units of Algonquin Power for each share of Highground. Algonquin issued approximately 3.5 million trust units and will receive between $7.71 and $8.14 per unit comprised of cash in the amount between $22.2 million and $23.7 million, dependent on the final proceeds of the realization of certain Highground investments.

In addition, notes with an aggregate face value of approximately $4.8 million related to the St. Leon and Brampton cogeneration projects having returned to Algonquin. The transaction represents a cost-effective way for Algonquin to access the capital markets on an attractive basis without payment of the typical costs or discounts. Proceeds will be utilized for general corporate purposes, including reduction of debt.

Before we move on to the second quarter results, I'd like to give you an update of Algonquin's internal realignment that took place in January. The realignment into two major business units, power generation and development, and utility services, was completed in order to more effectively positioned Algonquin to compete in the renewable energy and utility service business sectors.

To date we have successfully moved into the new internal structure and are focused on effectively managing the different operations and building on past successes.

Now a review of the Q2 2008 results. Revenue for the quarter was $54.2 million, which compares to $47.8 million for the same quarter last year. Distributions remained at $17.5 million. Cash (inaudible) for distribution was $15.9 million for Q2 2008 which compares to $18.8 million for Q2 2007. And on a per unit basis, distributions were continued at $0.23 per unit.

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 2008 revenue from energy sales totaled $19.7 million, and the division generated electricity equaled to 97% of long-term average wind and hydrology. The increase in revenues in the only result of an inclusion of production revenue from the St. Leon facility, higher energy production, and average rates in the United States regions and higher energy productions in Quebec, Ontario and Western regions.

For the second quarter of 2008, operating profits totaled $14.5 million and overall the renewable energy division net Algonquins expectation due to greater than long-term average source availability for both wind and hydrology.

During the quarter the renewable division produced sufficient energy to supply the [equivalent] of 60,700 homes with renewable power. Using a new standard of thermal generation, renewable energy produced saved the equivalent of 155,000 tons of CO2 gas from entering the atmosphere in the second quarter of 2008.

Also during the quarter on April 2nd, Algonquin acquired the remaining 50% interest in the [Camel for] Partnership for net cash consideration of $7.1 million. The Camel for Partnership owns a 4 MW hydroelectric generating station on the Trent River near Camel [Trail], Ontario.

In the thermal energy division, revenue for the second quarter of 2008 totaled $25.9 million, an increase over the same period in 2007 mainly due to increased production and energy rates for the Sanger and Windsor Locks facility and the Brampton cogeneration project became operational and greater production at the [LFG] facilities.

Revenue from weight disposal sales for the quarter increased due to increased throughput and improved recovery of ferrous material at the Energy From Waste facility or EFW. During the quarter, production increased [to] 5500 MW hours as a result of the Sanger facility repowering. The EFW facility increased throughput by over 14,600 tons as compared to the same period in 2007 which was negatively impacted by a planned 14 day major outage.

For the second quarter of 2008, operating profit totaled $7.6 million but overall the thermal energy division did not meet the Company's expectation due to increased operating expenses related to the division's landfill (inaudible). During the quarter operations at EFW resulted in the diversion of 26,500 tons of waste from landfill sites.

In our development division, our development team is working to actively identify, develop and construct new renewable and thermal energy generating facilities as well as seeking to construct other projects that maximize the potential of Algonquin's existing facilities. Some of the potential projects encompass new wind energies and hydroelectric projects in different stages of development and opportunities for various thermal projects.

During the quarter the development division successfully commissioned the Brampton cogeneration project located at the EFW facility. The project operates the acquired facilities to supply a nearby paper (inaudible) manufacturer with 90,000 pounds of steam per hour that is used in the manufacturing process. At the end of the quarter, the project's total net investment was approximately $16.2 million.

Following the commissioning of the project, the project was transferred to the thermal energy division of the power generation and development business unit. The project is expected to generate cash from operations of approximately $1.5 million in its first full year of operation.

At the EFW facility, development division is [reviewing] several opportunities to expand its power generation and waste processing capacity. This project could increase the generating capacity of the facility and increase waste processing by over 100,000 tons annually.

The development is currently completing a feasibility study to assess expected capital operating costs of an expanded facility. Accordingly, the likelihood of Algonquin proceeding with this project will depend on the result of the study and the outcome of negotiations with municipalities for reliable supply municipal solid waste.

The division is also continuing to review its options to market the increased capacity at the Sanger facility. This project would increase the generating capacity of Sanger by 14 MW.

I'm moving on to the utility service business unit. Revenue for the second quarter 2008 totaled $8.7 million, which is consistent with the same period last year. Second quarter revenue was positively impacted by the July 2007 rate increase of [Gold] Canyon facility as well as organic growth. The business unit also experienced reduction in revenue from operations as the result of the stronger Canadian dollar.

The wastewater treatment customer base grew by 7.3% year-over-year and the water distribution customer base grew by 2.9% year-over-year. For the second quarter, operating profits totaled $4.9 million but overall the water division did not meet Algonquin's expectations due to slower organic growth, higher operating costs and the strong Canadian dollar.

During the quarter, operations provided $1.5 billion -- 1.5 billion US gallons of water for to its customers, treated approximately 450 million gallons of wastewater and sold approximately 150 million gallons of (inaudible).

Now looking out for the next few quarters, the renewable division is expected to perform at or above long-term averages based on wind and hydrology conditions. In addition the hydro facilities in the New England region are expected to continue to benefit from improved market rates as compared to the rates experienced in 2007.

During 2008, several projects (inaudible) increasing hydroelectric production have been or will be completed in the third quarter and include automatic trash rack cleaning equipment and an inflatable dam at one of the US facilities. The Windsor Locks and Sanger facilities are expected to continue to operate to 2008 in line with Algonquins long-term expectations.

The facilities have no planned major outages in the third quarter 2008. At EFW, the throughput is expected to continue at current levels throughout the remainder of 2008.

On the development side, we believe that future growth opportunities for power generation projects will continue to arise, given that many jurisdictions both in Canada and the United States continue to use increased targets for renewables and other power generation projects. The division will continue to identify these new projects and pursue growth opportunities within our existing facilities throughout the remainder of the year.

Utility service is expecting lower growth rates with approximately 4% average organic growth forecasted for 2008, due to the slowdown in the US housing market. However the business unit continues to provide services in one of the fastest-growing counties in the United States.

The utility service is initiating rate cases at its Litchfield Park, Rio Rico, Black Mountain, Northern Sunrise, Southern Sunrise facilities in 2008 and a rate case at its [Vela] Vista facility in early 2009. (inaudible) intents made the regulatory review of the rates and tariffs would be completed in the second half of 2009 with the new rates and tariffs going into effect in the fourth quarter 2009 or the first quarter of 2010.

A firm forecast of rate increases at the facilities is not possible as the rate cases are in their early stages. Several capital projects are expected to be completed in the Litchfield Park service area during the remainder of 2008. In particular, these projects are expected to increase the water distribution storage and pumping capacity and wastewater treatment capacity, in order to meet the demands of existing customers as well as expected growth.

Also, additional arsenic treatment systems are scheduled for translation for the last quarter 2008 in order to meet new standards of naturally occurring arsenic and drinking water under US federal drinking water legislation. These investments will include -- these will be included in future rate applications.

Now, an update on Algonquin's US currency position. Algonquin attempts to manage currency risks through the use of forward contracts. At June 30th, 2008, the Company had effectively hedged 94% of its expected 2008 US dollar cash flow at $1.19 and 79% of its expected 2009 US dollar cash flow at $1.14.

During the quarter, Algonquin realized $1.9 million gain on forward contracts sold during that period. Using the foreign exchange rate on June 30th, to exercise these forward contracts will generate $3 million in distributable cash through the remainder of 2008; $3.2 million in 2009; and results in the use of $0,1 million in [distributable] cash for the remainder of the period beyond 2009.

Algonquin has told forward contracts to sell US dollars from 2008 to 2012 totaling US$109.1 million, carrying an average rate of $1.07.

So in summary we all -- overall, we anticipate that Algonquin's assets will continue to form in line with their expectations for the remainder of the year as their newly relying business units continue to provide innovation, progress, and a vision for the future.

So, Maria, with that, we will open up the line for questions.

(Operator Instructions) Bob Hastings from Canaccord Adams.

Good morning. Just dealing with your last point at your -- at the end of your closing there. You mentioned that you expect the Fund to meet expectations. Can you tell us what your expectations are? Do you have expectations in terms of distributable cash flow?

We don't provide forward-looking guidance specifically with respect to distributable cash flow going forward, but I think it's fair to say that the hydrology conditions that we experienced in Q1 and Q2 do appear to be holding in Q3. I mean who knows for Q4, obviously, but so far it's been fairly positive for Q3.

So each of the business units is performing to our satisfaction. And so what we continue to expect with that will be the case as we move into the latter part of the year.

As your seasonality changes, [all] normally you've got about half your cash flow in the first six months and but you are sitting at I think $0.42 so far. So -- and I obviously got some wind in there now that will you don't have a lot of experience in, but has that seasonality changed at all?

I don't know that the seasonality has really changed that much, but I will drop your attention to the fact that we do have our BCI facility now online. That effectively became commissioned May 28.

So we really didn't have much in terms of results of our steam sales in the first two quarter of the year, but we will be seeing that in the last half of the year. And clearly we have strong performance from our Sanger facility as the results of the repowering. So that will continue.

I suppose one of the wild cards which nobody can really predict is the price of oil, which tends to have an impact on gas prices and the rates that we get in the electricity market. So that is a bit of a wild card.

So even though our production might be the same, there could be fluctuations in revenue just depending on market rates.

Okay so BCI was up and running May 28th, you said?

Yes.

And it contributed about $[100,000] so it's about $100,000 a month I think he said annually you expect about $1.5 million.

That's right.

So June was just a little bit slow as you started up?

Yes. We had some started issues during the commissioning, but it is running now.

Okay. But speaking of that and the costs and I know it was originally budgeted about $11 million at the end of the last quarter. You had mentioned it was about $15 million and now it is $16.2 million.

Can you start of explain why the cost increases and can that at all be passed through on the contractual side?

Yes. And I can just say that we had some construction issues and I would classify them as probably more than what we expected. So we did spend more than our contingency. We actually had to change contractors halfway through the project. So costs went quite a bit higher than what we expected and there is not really an opportunity to pass that through to the buyer of steam.

But a couple of things probably worth note. That is still a pretty good deal for us. It started out to be a great deal and it ended up to be an okay deal, but there's a couple of things that are hidden in that that make it a pretty good project for us.

One is, we now have a hedge and it's hard to explain this over the phone, but we now have a built-in hedge for gas which is consumed by the [Peel] facility and that is something that we were seeking on this transaction. So that's one of the hidden benefits of the project, as well as it opens up a bunch of opportunities for additional steam sales.

And, incrementally, they would be cheaper to connect? Or they (inaudible) the same customer?

Both. Both.

So the $1.5 million -- I realize there are start ups. I don't know the terms of the contract. Does that escalate over time?

Yes.

Okay so $1.5 million should the growing modestly over time and that will improve the returns as well?

That's correct.

Okay. And sort of a -- staying at Peel. Good to see EFW production achieving a reasonable rate there and you expect that to continue on for the rest of the year. Would that be looking out to '09? Is that the same kind of quarterly rate I should -- the last quarterly rate? Should I be just annualizing that out for next year? Or do we have any major turnarounds or any major issues next year?

No, we don't. We are not expecting any major issues over the next several quarters at EFW.

But '09 either? Like there's no scheduled turnaround or anything?

A good question. I don't know that, Bob. I'm not quite sure if we have a scheduled maintenance in to '09. I'll get back to you on that.

Okay. And the gas turbine that's at that location, you mentioned in your last call I think that you were talking to [OPA]. Has anything been settled on that? Are we going to see that starting up?

We haven't settled on anything yet.

Okay. Does it look like that will start up at some point?

Hard to give you guidance on that one.

Okay. Just -- in the utility side the waterside was a little bit of a disappointment. You are still getting growth though and I think you were looking for about 3%. That doesn't look like it's changed very much.

What I'm wondering about is, you are going for rate increases. Are the rate increases to get returns on your future investments? Are you going to spend a lot more money on it this year than originally planned? So is it to get your return on your future investments and inflation? Or are you actually trying to recover a little bit of shortfall from what you see now?

We are in -- starting to get in [test] years right now which would mean the money that we have invested in the ground rate now would be included in the rate case.

And just to the clear that will extend back to whenever the last rate case was. So since the last rate case, if we've invested capital in the ground, all that capital since the previous rate case will be included in this rate case. Not just the capital that we've deployed, say, this year.

So given that, would it be --? And I know you don't know if you are going to be successful. No utility ever knows, but they usually know what they are filing for. Would you expect that you are sort of under earning right today based on your current investment rate?

Yes. On an overall basis -- we have 16, 17 utilities. There's a few in there that are overearning. But the largest ones are underearning and that is why we are proceeding with rate cases at this time.

Okay. So the numbers we are seeing out of this division under utility type analysis are just too low. We have got to get those up through rate increases. And then we would expect to get some growth from your future investments that you will be making.

That's correct.

And now the CapEx numbers really seem to have grown quite a bit here. Originally the numbers were like $30 million overall. Now we are talking close to the 40 -- or about $40 million I believe, plus the $7 million acquisition. So is that mainly all the water division?

Yes, most of that CapEx is going into the water division and a lot into the Litchfield Park service area.

So what changed from the last quarter to sort of push those numbers out nicely?

There's a couple of projects that we've advanced. I think we've experienced some higher costs on a few of the projects. There's a couple of projects in there that are extremely large and as you know when you are into large capital projects. It doesn't take much for it to creep up above the original target.

So as we get closer to the end game on somebody's projects, we are seeing some higher costs associated. But again all of that will form part of rate base.

Right and no surprise looking at CapEx. In any industry they've certainly all gone up. So I'm not real surprised.

It's just the magnitude. I wondered if maybe some of the water treatment facilities are going to have to be more extensive than originally thought or anything like that?

No.

Okay and would it be possible in future or maybe off-line to get more information on your gas costs in volumes by quarter? We get that from some of the others. It would just be nice to see in your disclosure in the future.

We will take that under advisement for additional disclosures going forward. We are always looking for input on that.

Great. Thank you and I will let somebody else ask some questions now.

Tony Courtright from Scotia Capital.

Just following on utility segment. So the guidance for the balance of the year is about close to 22 -- or 21.5 split between various segments there, but what about the operating costs? Are what we saw in Q2 reflective of what your current run rates are likely to be?

Are you talking specifically in the utility division?

Yes, I think that's the one that had the biggest sort of step up.

Yes. I think it would be a fair comment to say that we would expect the same in Q3.

All right. In terms of the rate case that I believe you referenced one was delivered a decision. How would you describe that, relative to your application or expectations?

How -- Are you asking how do we compare the Gold Canyon rate case and what we got compared to our future rate cases?

No to what you applied for. In other words did you get what you were applying for (multiple speakers)

We got what we were looking for, maybe a little less. There were some costs that weren't included in the rate base. I think they had to do with actually prosecuting the rate case.

What was interesting is that we built a large treatment facility that was larger than we needed, but because of the cost of this scale of the project they allowed all those costs into the rate base.

So you won some, lost a bit?

Yes. We won some, we lost a bit.

With respect to Sanger, are there any contingency [fees] you use that will likely be payable to the manager? You indicate some construction fees, but I'm unclear whether this thing has been fully commissioned in there for you. You know whether you -- there were surpluses in the contingency that might flow to the manager otherwise?

We are just finalizing that now. And we do expect some contingency remaining in that project.

Do you have any idea of the magnitude? Are we talking $1 million, $2 million or something more material?

As I say we are just finalizing it now, but it is certainly not that high.

You've referenced in terms of the thermal facilities and no major planned outages in Q3. Do you have any scheduled for Q4 or 2009 that might be material?

We don't -- like I said to Bob, we're not -- I'm not sure about 2009 but we have nothing for 2008.

Maybe a little ways out, but Windsor Locks if I am not mistaken has a PPA that expires in 2010. Can you provide some color in terms of what the current market outlook is and whether you anticipate that facility can get re-contracted? Not necessarily specifying what the margin will be, but just trying to get a feel for what your sense of the market is.

Our sense of the market is that it's quite vibrant in that area. It is a very congested area in the New England states. This is existing capacity that is installed.

We've -- we are undertaking a study right now. We've retained a consultant who is an expert in that area to give us some options on what we can do with that -- with that power. But we are quite positive about what conclude a good deal there.

And I would say like we are experiencing very, very favorable electricity rates in that whole area. So the market as Dave said is very strong.

When you say "experiencing" -- this is, in other words, the market is experiencing favorable rates or you are under your contract?

We are.

Under your contract. Your contract seems to be in terms of the sensitivity described relative to a unit cost increase in gas to be quite favorable. You actually benefited rather than being neutral pass-through.

Yes. Higher energy costs is a benefit to us.

Right. So I mean I'm wondering about the overall market rather than just your contract. Looking forward to say recontracting, do you still think that the congestion constraint might make it viable even --?

Yes we do.

We feel that existing generating capacity in the ground is valuable. And so we have it. We are there.

Switching to the energy from waste facility. The expansion -- I know that you're undergoing a feasibility. Any sort of quantum, is this material capital project if you were to expand it or is it minor and more just off costs versus whatever throughput tonnage you get so that it's marginal contribution?

Like I don't (inaudible) idea of the quantum that you can be specific, but is it a material expenditure?

Yes. I would say it is a fairly significant expenditure. Because that plant was built so long ago, Peel has so much more garbage now as you would expect.

And so what we are looking at is an expansion to take in their current garbage levels. And so it is a fairly significant expansion. It could be as much as 150,000 tons a year. So that's a fairly significant expansion.

Right now we take [50]% of Peel 's (inaudible) solid waste and they are looking for a solution for the next 50.

Right. Now, if I'm not mistaken that was acquired through the acquisition of another power income fund, KMS, from many years ago, but I am just trying to get a ballpark. If you -- how much does this cost per 1,000 tons of expansion or are we talking $20 million, $40 million, $60 million? I have no quantum.

I don't want to pass that out right now because we are in conversations with the region appeal. I don't want to be advising what our rate is, but it is at the upper end of that range you just gave. And maybe even a little bit beyond.

Okay. Thank you. One last thing. The -- well, two things. One of them is I think in previous -- and maybe I didn't read it. Quite a lengthy document to release, but previously you have indicated to have expected -- this might have been at the beginning of the year, but to be able to generate enough to sustain the current distributions. Do you still adhere to that view in terms of sustaining the current level of distributions? Or do you refrain from prognosticating on future distributions?

Yes. Our position is that we don't provide forward-looking guidance with respect to distributable cash and that. I think that we've gone to great lengths to beef up our disclosures and to make as much information publicly available, so that people are able to make their own assessments.

Right but in terms of -- this isn't so much a prediction of your performance, but more forward policy on those decisions as to the level of distributions. So you just won't make a comment on that?

Trustees monitor the level of distributions that we make. They do it on a regular quarterly basis. And they keep in mind the medium-term when making those assessments.

Okay. And just the final topic -- as transitioning [SIFT] taxes or corporate reorganizations -- I've read what you've written and I noticed that there was no specific reference to the most recent draft, legislative proposals that were issued by the Minister of Finance of late.

I wonder if they have given any additional color to how you might see yourselves evolving, going forward?

Like we said, I guess last quarter is that our trustees have asked us to look at different alternatives and the changing of the (inaudible) and we took it under advisement, the new clarification.

But we are still working through that with our trustees. Do we don't have anything to report on that yet.

Then, just specifically in terms of SIFT and future there's a reference in the risk section to a subsidiary partnership that may not meet certain ownership requirements that might exempt it from sort of a SIFT owning a SIFT. And what is the implication there? Is that there might be double taxation then?

I guess that would be the worst case scenario that they might be an element of double taxation that --. The issue -- and it's really an anomaly in the legislation because the legislation contemplated, I guess, SIFT of SIFTs, but we've got at one level in our organizational chart like a SIFT of a SIFT of a SIFT.

And so because of that, it appears just at straight face value that that bottom level SIFT might not be captured by the legislation. But we are working with our tax advisers on that. There's different ways to restructure ourselves internally to put it on side, but alternatively we think we probably could be successful in getting an advance tax ruling on that if we decided that we needed to do something. Because it just appears that it was an anomaly.

Is that partnership the AirSource wind power firm?

Yes.

Relative to your US earnings that you repatriate, some entities believe that they will -- that those earnings will be exempt because they are US business income. That doesn't apply in your case because of your internal structure, is that correct?

No, I wouldn't say that. Right now we are going through the process of modeling what those cash flows from the US would look like. There's nothing particularly unique in our structure that would make our US cash flow look any different than any other income trust that is out there.

Okay. Thank you.

Bill Cabel from TD Securities.

Can you just go over again -- you said on the utility side, air CapEx, you've increased a few projects and costs have increased a little bit. Am I correct -- it looks to me like the amount you expected to spend in the remainder of the year has basically gone up. Like it's more than doubled.

So can you maybe break up how much of that is from new projects versus costs escalations?

It's a combination. It's a combination of both. I don't have the exact breakdown in from me, but we did decide that we were going to declare a test year at a number of utilities.

So some of the capital projects have been moved up and there are some in there that have experienced some cost overruns. It's just in front of me at the moment I don't have that breakdown, but if it is critical to your analysis we can certainly look to try to provide you a little more color on that.

I guess I'm just looking at your new estimate for I believe spending of about $17 million in the rest of the year and I'm curious if -- I mean if that had the potential to increase by 20, 30, 50%? (multiple speakers)

No. I mean as we get closer into the year I mean those capital projects become more right in front of you. So your estimates become more accurate.

Do you have flexibility to push some off into next year or are these all -- all these projects are required in the near-term?

I would say forth the utilities segment, we want to get this capital deployed. So I wouldn't say that we would be pushing that off. I mean, in other aspects of our operation, yes, I mean there's certain capital projects whether we do it in December or whether we do it in January our February. It's not going to make or break things, but right now that's our estimate.

Okay. Can you go over your liquidity position? I think you have $6 million in cash on your balance sheet. You're having about somewhere between $22 million and a bit and $23 million and a bit coming in from the unit issue. And then you have I think I read about $11 million and a bit of room on one of your line of credits. Is that the extent of your available capital?

We also have an additional $32 million that's unexercised on our accordion feature associated with our term credit facility.

When we renewed our term credit facility back in January, we negotiated an additional $50 million through an accordion feature. We've triggered $17 million of that earlier in the year. And so there's an additional $32 million available to be triggered on that if we feel we need it.

I thought the 11 was the 32 net of some letters that were pledged (multiple speakers) I must have misread that.

No.

With 11 plus 32 plus your cash that comes in from the unit issue and your concurrent cash position?

Right.

Okay. Thanks. That's me done. Thank you.

Michael McGowan from BMO Capital Markets.

Can you provide any estimates of incremental production associated with some of the upgrades that you are making at your hydro facilities?

I don't think we can. A lot of those projects are in place. I don't think it's -- it is not going to be a material increased. When you are talking about cleaning trash racks and replacing wooden flashboards with a rubber dam. I think it just really goes to more operational efficiencies. So as opposed to increased generation.

So will that potentially lower your operating costs?

No.

How much capital are you spending to do this?

You know, I'm not sure. Do you have those numbers?

Before the --

I will get back to you on that. We have those numbers but we don't have them in front of us.

Okay. Regarding the work you did at Sanger last year, you increased the capacity there. Are you actually dispatching incremental capacity into the markets?

No. You know what the situation there is, that PG&E was just the utility. It has to upgrade the transmission system that goes to Sanger. That's what the restriction is and also some of our control equipment needs to be replaced.

So we won't be able to actually get that extra capacity into the market until 2010.

Okay. And at that time you will be open to dispatch?

Yes.

Brampton [Coach] and you mentioned -- you talked about this a lot in past conference calls, but there's incremental cash flow you are expecting of about $1.5 million and you mentioned that that escalates.

In terms of an escalation rate is assuming -- is it safe to assume that increases with inflation?

Yes, it's based on CPI.

Okay. Just on Campbell (inaudible), when you acquired the remaining 50% of that facility, just wanted to know who was the seller of that?

It was -- that portion was done with a partnership with some private individuals that decided they wanted to exit the business. So we bought the (inaudible) owned, the 1/2, the private individual and the other half. They were actually in the business so we just bought the rest of the facility.

How did you arrive at the price?

That was the value of the second half. Since we own the facility, we know exactly what it generates. So it was not difficult to calculate the purchase price.

Okay. So -- I mean the PPA for that facility expires in about 11 years so you would anticipate entering into a new PPA, I suppose, when that comes off?

Yes. It has -- yes. You're right. It was a 20-year PPA and that facility is owned for 25 years. So we would enter into another PPA at that time.

So you -- effectively you own the facility and you will be able to enter into a new PPA for a subsequent term like, say, 20 or 25 years?

Yes. It will not be for that long and the reason is because that facility is on leased land. And the lease arrangement is for 25 years. So the PPA would be for a five-year PPA at that time.

Is there any options to extend the lease?

There is one, but it is not -- it extends it for a very short period of time.

(Operator Instructions). Bob Hastings from Canaccord Adams.

Just a couple of clarifications. On Sanger in your written report, you mentioned that there was 5500 MW hour of additional power sold because of the repowering, but you just said that you couldn't do any until 2010. So I'm just wondering what the difference there is. What am I missing?

Because it's a new facility, a new generator, we had better uptime than we normally do at Sanger. Better availability. It doesn't include that 14 MW of extra power. That has not been generated, but just the efficiencies and availability of the [all new] 6000 is better than the old turbine.

Okay. So say you are going forward, we should expect similar performance, better efficiencies, etc. than we had before and then 2010 we might get a step up from selling the extra 14 MW.

That's the plan, yes.

Regardless I would assume that that whether you sell it or contract are not, it would be available for spot and that we just be an economic decision.

Exactly.

[Campbellford] you said the seller is a private individual. Any relations to anyone in the Fund?

No.

So completely independent?

Yes.

Great. One of the things in the EFW, in the report it was mentioned that benefited from the sale of ferrous materials recovered in the higher pricing. When I looked at the actual revenues per ton of waste, it really never even changed to within 0.04%.

So was that more for the first half or is that happening in the second half? We should expect a better rate or what's happening?

No, we just entered into a new deal to sell the (inaudible) comes off of the EFW for substantially more than what we had been selling them for in the first quarter of '08.

But there was no change in the second quarter year-over-year. So -- .

Yes we are just trying to benefit from that now.

So it's really -- we are going to see that in the third quarter?

Yes.

So we will see the good continued production plus the better rate. Can you tell us how material that rate might be? Is that going to add $1 million a year or --?

No, I don't think so. I think -- yes, we are thinking sort of $0.5 million a year.

Okay. A quarter for the rest of the year.

The LFG and -- there was a final adjustment of $600,000, not a big deal maybe, but I just wasn't clear on what that really was to do with.

We have got a lot of [crinkle] pros around here. (multiple speakers) I'm not sure what you are referring to so maybe if you shoot Kelly an e-mail we can respond.

Okay. It was on page 10 of your statement. So you can respond to me later, but it basically says results also include $600,000 increased operating costs at the LFG facilities related to final adjustment with regards to the investments in the landfill gas tax credit program. So I was not sure of that.

That's the section 29 tax credits with Chevron.

Is that a onetime item and it's all behind us now?

That's a onetime item.

You mentioned in the power generation development, you are looking at lots of projects and I was wondering if you could give us maybe a little color on the kind of things that you are looking at whether you are bidding into BC hydros, current offerings and sort of the strategy you are going to use to fund that, given your unit price is so low.

Some of the types of projects we are looking into that is obviously lots of RFPs around to the various provinces, and you have to be a little careful on some of those on what you disclose.

So that's why we are being a little bit vague as to which ones we are participating in and which ones we're not. But primarily we are interested in a couple of the wind opportunities as well as some of the thermal opportunities.

We haven't participated a lot in the BC programs, but up to now. So I think our main focus and development is in a couple of wind opportunities. Some of the thermal opportunities which are there as well as the EFW.

We think that's a fairly significant amount of development work for our Fund.

Is there anything going on in Manitoba, given that the original looked like winner. The bid may have had some difficulties financing?

I was just talking with Manitoba government the other day and they advised me that there's still a process and we are still part of that process, but how successful the first proponent is we don't have any idea, but we were told by the government the process is still going on.

So you are not really having discussions, you are still in the process in case the first one doesn't work?

That's the way I interpret, yes.

And what about the financing issue as you look at these projects. I assume your hurdle rates have all changed?

Well, Manitoba, we are not at that point yet, but we are looking at different models for financing.

But I assume that you wouldn't be wanting to do equity down here?

I don't think we've landed on anything yet. I think once the project gets to the point where it's financeable that is when we will start looking at how to finance it.

Given that you are also pursuing, intentionally pursuing a greater growth profile which I applaud you for, are you looking at other changes? I know -- obviously you are looking at conversion and there's nothing to report on that, but are you looking at other changes in terms of internalization of management contract? Because it basically changes a lot of things from what you would have been doing before?

Like I said earlier to somebody, we are looking at all the alternatives and I don't think anything is being ruled out right now. Trustees are looking for solutions to the current environment that created shareholder value.

So we are looking at a lot of different things, but we haven't really landed on anything yet.

Right, so it's just that it's a difficult to pursue growth without knowing what the terms might be or whether they are workable. I mean, I just -- you know I see the BCI project going 47% over the original cost estimate. But still money paid out for supervision. There's still target sort of -- a sharing over certain levels of return and I see business expense as being -- or business development expenses being expensed, and not maybe going to the capital cost.

I'm not sure if that is coming in through the sort of measurement metrics or not which of course they should.

No. Just to be clear, I mean there's no gamesmanship at all being played in terms of the business development expenses. The rules surrounding what can be capitalized under General and Accepted Accounting Principles and what can't be are changing.

There's going to be a significant change coming out later this year. You are probably already aware of it. It is a Section 3250, I believe, and as we move into international financial reporting standards, it will make it even that much more difficult to capitalize what we call development expenses in the predevelopment stages.

And generally speaking under the new standards that are coming out, it is going to the much more difficult to capitalize expenses than under the previous accounting rules. So it is really just a matter of changing accounting rules. It's -- as the CFO I would love to capitalize more, but the rules just don't allow for that.

And certainly let me be clear. First of all I wasn't suggesting there was some gamesmanship going on. And, secondly, I actually like expensing of business development because so many things never actually come to fruition. So it's best to expense those as you are doing the development side.

But what I meant was that your original contracts would have been set up under the assumption of how trust used to operate and as you are pursuing those growth things, I'm not sure that is really going to capture maybe the change to accounting rules. It is not going to capture the change in the growth profile and maybe the right metrics for decision making may not be in place.

So I thought it had to be looked at and just wondered if you were looking at that?

Well, of course, Bob. We are managing our business the best we can and we are always looking at those issues when we make decisions.

There are no further questions at this time. Please continue.

Thank you very much. Thanks for joining us today and we look forward to talking to you next quarter.

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