Algonquin Power & Utilities Corp (AQN) 2007 Q1 法說會逐字稿

At this time I would like to welcome everyone to the Algonquin Power first quarter results conference call. (Operator Instructions) Mr. Kerr, you may begin your conference.

Good morning. My name is Dave Kerr and I am an Executive Director of the Algonquin Power Income Fund. I would like to welcome you to Algonquin Power's first quarter 2007 conference call. With me today is Chris Jarratt, who is also Executive Director of the Algonquin Power Income Fund, Louisa Paniconi-Read who is our Interim Chief Financial Officer, Vito Cicerotto who is our Chief Operating Officer, and Kelly Castledine, the Manager of Investor Relations.

As a housekeeping issue I'd like to quickly review our forward-looking statements disclaimer. Certain statements contained in the information discussed today are forward-looking and reflect the views of the Fund and Algonquin Power management with respect to future events. Since forward-looking statements address future events and conditions, by the very nature they involve inherent risks and uncertainties. Forward-looking statements are not guarantees of the Funds' 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 Fund's assets, commodity market prices, interest rates, and environmental other regulatory requirements. Although the Fund and its management believe that the assumptions inherent in these forward-looking statements are reasonable, undue reliance should not be placed on these statements.

With that, today I will provide a review of the results of the first quarter 2007 followed by a discussion of the divisional results. I will then provide an outlook of each division and finish off with some additional information about the Fund.

First, a review of the Q1 2007 results for the fund. Revenues for the quarter were $49.5 million, which was the same in Q1 2006. Distributions to unit holders was $17.5 million compared to $16 million in Q1 2006. Cash available for distributions was $15.1 million, which compares to $16.3 million in Q1 2006. Distributions to unit holders were $0.23 and the cash available for distributions was $0.20 and I'd like to point out there was an error in the Release last night when we noticed the cash available for distributions was $0.22. We made a correction that was posted in the Press Release at nine forty this morning, which says "cash available for distributions was $0.20."

These results show a successful first quarter of Algonquin Power consistent with results for the first quarter of 2006. Results in the first quarter were positively influenced by Hydrology and revenue from the St. Leon Wind Energy facilities. These positive results were partially offset by a decreases in revenue from the closure of the Crossroads Facility at the end of 2006 and lower energy rates at the Windsor Locks Facilities. Of note for the quarter, the Fund has started reporting realized gains on foreign exchange hedges on the statements of earnings under gains on financial instruments as compared to previous quarters where gains were reported in revenue.

Now I would like to discuss some highlights of the divisions for Q1 2007. In the Hydroelectric Division for the first quarter 2007 the Fund's hydro assets generated electricity equal to 102% of long-term averages, which compares to 111% for the first quarter 2006. Energy generated above the long-term averages was due to improved hydrology in Quebec and New York regions. These were partially offset by below long-term averages hydrology in other geographic areas where the Fund operates hydroelectric generating facilities.

Operating expenses decreased when compared to the same period in 2006 due to a reduction in cost directly related to energy production. In the Cogeneration Division first quarter production increased compared to the first quarter in 2006 primarily due to increased production at the Sanger Facility, which has involuntarily shut down at the end of 2005 in favor of selling natural gas. Revenue from energy sales in the cogeneration division was consistent with the same period of f2006 due to increased production of the Sanger Facility in the quarter offset by lower energy rates at the Windsor Locks Facility where decreased fuel costs were passed on to the customers in the form of [water] energy prices.

Also reflected in the results in the cogeneration division is the closure of the Crossroads Facilities, which occurred in December 2006. In November 2006 the Fund announced plans to retrofit the Sanger Facility with a General Electric LM6000 turbine. The project expected to result in the improved fuel efficiency, increased facility output, improved maintenance and an extension of the useful life of this facility. The project is progressing on schedule with the commissioning targeted for the fourth quarter of 2007.

In the Alternative Fuel Division production increased primarily due to the inclusion of production from the St. Leon Wind Facility acquired at the end of Q2, 2006. The inclusion of St. Leon was a positive impact to revenue for the first quarter of 2007 when compared to Q1 2006. Higher revenue was partially offset by lower production and reduced average energy prices at the landfill gas facility as compared to the same period last year.

At the Fund's energy from waste facility 39,000 tons of waste was processed in Q1 2007, which is in line with management's expectations for the quarter. In the Infrastructure division during the first quarter 2007 the Fund's wastewater business showed year-over-year growth at 11% where the water distribution business grew by 9% when compared to the same period of 2006. Although the Division is experiencing growth in both water distribution and wastewater customers, there is a trend towards slowing growth in the areas serviced by the facilities in the Infrastructure division. Revenue in the division was slightly lower than comparable period in 2006 primarily due to cooler, wetter weather during the first quarter.

During the quarter the Fund began charging customers at the Black Mountain Facility according to the approved rates resulting in a 20% increase in wastewater rates for that facility. During the quarter the Fund acquired two additional water distribution facilities serving approximately 1,200 customers. These facilities are located in close proximity to other facilities owned by the Fund and, as such, can realize operational synergies.

Now looking out to Q2 2007 and beyond, in the Hydroelectric Division the Fund's hydro facilities are expected to perform as expected based on long-term average hydraulic conditions anticipated for the second quarter and the remainder of 2007. The Fund anticipates incurring about $500,000 over the remainder of 2007 and into 2008 to complete the required technology assessment of its owned or leased dam structures associated with its Quebec facilities. Following these assessments a plan will be made regarding any remaining work that may be required to comply with this legislation.

During the second quarter the Fund will be pursuing the sale of six small hydro facilities located in the New England area that no longer fit the Funds preferred asset profile. All facilities are under one megawatt in size and will not constitute a material change in the Fund. The process is expected to be completed during the third quarter.

In the Cogeneration Division decreased fuel costs at the Windsor Locks facilities are passed on to the customers in the form of lower energy prices. This contract significantly reduces but does not eliminate the facility's exposure to natural gas. Management expects lower than anticipated natural gas prices to reduce operating profits for the Windsor Locks facility for the remainder of 2007. The Sanger facility is expected to meet management's expectations throughout the remainder of 2007. The Sanger re-powering project will continue throughout the year concurrently with regular operations. Its expected completion date remains on target for the fourth quarter 2007. The buy down in the power purchase agreement at the Crossroads facilities was completed by the Fund at the end of the year and the Fund is now examining its options and plans to have a strategy in place to re-deploy or sell the existing equipment of the facility later in 2007.

In the Alternative Fuel Division the Fund will continue to focus on operational improvement projects at the energy from waste facility with an expected completion date later in the year. There is a 14 day planned maintenance outage currently underway, which is expected to improve the incineration availability.

The Fund is also moving forward with a steam sales project at the energy from waste facility with an expected completion at the end of the fourth at 2007. The Fund has currently undertaken the strategical review of the LFG facilities and has taken initiatives to reduce operating costs at these facilities. The investment in the gas treatment facility late in the fourth quarter of 2006 is expected to run with high availability as anticipated from wells for the remainder of 2007. The performance of the St. Leon Wind Energy Facility is expected to continue at or above management's expectations for the remainder of 2007.

During the second quarter the Fund will continue to pursue additional wind opportunities in Quebec, Saskatchewan, and in Manitoba where the St. Leon facility has a 50-megawatt expansion capacity. We are planning to submit this 50-megawatt expansion capacity under the Manitoba 300 megawatt RFP, which is currently under way.

In the Infrastructure division a reduction in the organic growth rate is expected during the remainder of 2007 due to a general slowdown in the residential housing market in the United States. The Infrastructure division is expected to continue to contribute a strong overall performance for the Fund in part because of the division's services one of the fastest growing counties in the United States.

The [rate] case at the Gold Canyon facility is ongoing with an outcome expected at the end of the second quarter or the beginning of the third quarter of 2007. Although effective beginning the second quarter of 2007, an approved 140% rate increase of our three Missouri facilities will be in place. Planned capital projects are expected to continue at Litchfield Park to meet growth and new government regulations in Arizona.

There is just one additional item that we'd like to mention about the Fund today. With respect to the Fund's offer for the Clean Power Income Fund, on April 18th following an announcement of a competing offer for the Clean Power Income Fund Algonquin Power announced that it would not amend its offer to match the terms of the competing offer as the Fund believes that its offer fully valued the Clean Power asset. As such, the support agreement was terminated and Algonquin Power received a $1.75 million termination fee and reimbursement of acquisition costs incurred totaling $850,000. Algonquin Power believes firmly in taking a disciplined approach to making accretive acquisitions and acting responsibly in the interest of our unit holders and remain confident in the decision not to match the.

With that, I will now open the lines for questions.

(Operator Instructions) Your first question comes from Bob Hastings from Canaccord.

Just to clarify on your payments from the Clean Power, is that came into the second quarter but you would have incurred the expenses in the first quarter?

That's correct yes.

And what were the expenses incurred in the first quarter then?

Well, all the costs associated with making our offer.

Would that have been the-- so all of it, none of it came in the fourth quarter for example?

No this is Luisa. The costs that were incurred in the first quarter were very minimal and they were accrued on the financial statements so they didn't affect the statement of earnings.

But in terms of cash or distributable cash, there was almost no impact in the first quarter?

That's right. Correct.

Okay so that was in there. And can you give us some of the impacts from the increase in your water rates for the three utilities, what that will be for the rest of the year? Is that significant?

No the thing that utilities in Missouri are quite small that it won't be a significant impact to revenue.

What about Black Mountain?

Well, Black Mountain we've got 20% increase. I don't have the number exact on me but it's a 20% increase for wastewater.

Okay so that-- but that wouldn't have been material in the quarter either?

No.

Okay and in terms of the impact of the hydro sale that you're trying to do, I gather it's pretty small. Is it-- do you anticipate it to be modestly minimally positive to results?

We haven't really got far into the process and we're not really quite sure what the prices will be for that sale. If we don't get adequate prices, we obviously won't finish the sale or go through with the sale so we're waiting to see what happens there.

Okay and obviously weather was a bit of an impact on your water Infrastructure division. Do you have any estimate of what the weather impact was there?

During the quarter?

Yes because you were down about $1 million for the division.

Yes that's right and it was partially due the colder, wetter weather and that was really where the big impact was.

Yes so it would have been up had it not been for that so would that be about $1.5 million impact from the weather then or--?

No it's not that high, Bob. It was some of it and I think the other impact was as Dave said that the growth in Arizona has slowed down a little bit and it wasn't-- we had made the assumption that some developments in the close by would be hooking on during the quarter which didn't happen because of the slowdown. That was a big part of it as well.

So you were spending for growth but it didn't happen so that was a bit of a negative on the results as well?

Yes it wasn't so much spending for growth as we just didn't get the revenues that we were expecting.

Right so if I'm looking that your operating results were down $1 million, had-- I assume that growth then wouldn't have cost you anything. You might not have done as well as you'd hoped but it wouldn't have been a negative onto your results?

No I think if our revenues were down then we would be down also on our operating profit.

Okay and the Crossroads, you said you looked at the strategic, your strategic options. It sounded like you had something sort of planned. Does that represent some improvement later in the year if you can sell it? Do you have any idea what that value might be?

No we don't. We're still reviewing that.

Tony Courtright from Scotia Capital.

I am interested in your comments regarding pursuing wind development. Can you generally outline how it is that you approach these relative to the risk profile of the Fund given that when you go into Greenfield development you have a lead time as well as how do you protect yourself on your returns, cost overruns and so on?

Well, we're looking at in Manitoba it's a RFP process so we would be bidding in our 50-megawatt expansion capability in St. Leon at a price that makes sense for that project. We're in very good shape in Manitoba because when we built St. Leon we included all the infrastructure for the expansion just as a collection statement to control transformer [relative] size for 150 megawatts so we'll price our competitive bid into the RFP that's appropriate for our risk profile for the Fund but we're in pretty good shape because we have a lot of infrastructure there. And obviously the situation is we'll review them to make sure that they do fit our profile, that they would be accretive acquisitions for the Fund.

All right. I can appreciate that you would only undertake them if they were accretive but in terms of St. Leon you initially financed this mezzanine debt in a-- in somebody's else's development. Would it be Algonquin Power Income Fund per se that would pursue Greenfield development other than the step out development in Manitoba, which I could see making sense but in Quebec or Saskatchewan or would you-- would there be some affiliated partnership that undertakes the development and then it's sort of a farm in to Algonquin subsequently?

Tony, I think each one is kind of a little bit different like if you at one end of the spectrum might be St. Leon where, as Dave said, all the infrastructure is there and probably more important all of the wind information, which is kind of expensive to collect for two or three years before a project, is also available. So the up front costs, the high risk up front costs are already incurred. We wouldn't need those at St. Leon. As to the construction of it, I mean we have a couple of options open to us. It's not in the Fund's interest to be taking front line construction risks if those risks are in our view significant. So I think each one is handled separately depending on the circumstances but St. Leon is a good example of where from a construction point of view it's fairly low risk.

In terms of a 50-megawatt expansion, I'm sure there's been escalation in the cost of wind turbines. We're probably looking at more cost per megawatt of installed capacity than previously notwithstanding some of the benefits of installed infrastructure that you could enjoy?

Yes you're absolutely right. The cost of turbines since we did the first two phases at St. Leon have gone up probably 30, 40% in that range so the cost for this power will definitely go up but it we'll either be successful as the bid or we won't but those costs will be baked into our bid price and hopefully we'll be successful.

And matched against with a commitment for a turnkey construction contract as well?

We haven't gone that far down the road yet, Tony, but obviously we like to pass as much risk as we can off to the construction sector as possible.

And what is the relationship with your major wind turbine supplier at St. Leon? Would you every envisage employing their services for future projects?

Yes I-- they're certainly a good supplier of turbines. I mean we're still involved with them at St. Leon obviously and will be for the next 25 years but there are lots of other people. You don't have to use Vestas turbines just because you already have some there.

I was more referring to the fact that there's still outstanding issues with respect to-- well I don't whether it's contractual terms, substantive completion or I mean they are still receiving-- you're still receiving liquidated damages from them and they're receiving the revenue from Manitoba Hydro. I just wondered when that might get resolved to everybody's satisfaction?

I don't have a date for that because it's not really in our control. It's in Vestas's control but when they complete the outstanding items, I mean if I had to guess I would probably be in the toward the mid to end of this year.

And in terms of because of cost escalation and so higher capital costs, do you have any indication that you could have sufficient combination of non recourse financing in existing undrawn credit facilities to undertake an expansion at St. Leon?

Well, that's one option that would be open to us but we have not arrived at a conclusion as to how we would do this.

And in terms of the timing of the St. Leon or The Manitoba RFP, what's the time line on that?

The submissions are due mid July and I don't think they've actually given a date when they're going to make selections.

They're looking for 2000-- I think installation 2008.

I see and in terms of time lines for Saskatchewan and Quebec what are you looking at?

It's ongoing. With Saskatchewan we're talking size of power rate now and Quebec their RFP is later in the year.

Are you expecting or planning to make a submission in the Quebec RFP?

We have properties in Quebec in the gas bay in the area and we're collecting wind data. I think we're just-- we're looking at them now with respect to submissions.

And just switching to Infrastructure division you'd provided some guidance in the annual report in terms of anticipated connections, forecast total connections, of almost 13 to 14% increase in wastewater and distribution customers respectively. Any sense of how much that might get reduced given this apprehended slowdown in the housing market?

Yes it is slowing down in our areas and we've reduced our projections probably about 8 to 9%, which is still fairly high. It's experience lots of growth in that area.

That was down to 8 or 9%.

Down.

By 8 or 9.

Michael McGowen from BMO Capital Markets.

I'm just wondering could you elaborate a little bit on what the review of the LFG facilities entails? Does it entail a review of the operations or are you looking to possibly divest those assets?

Well, we're going through a review just to find out how we can maximize value under those assets. We've been talking about this for a little while and we're struggling with those assets so sales, there's a potential sale if we get that maximizing value and potentially run them with greater revenues and greater availability we'll do that too but we're going through that process right now. But we're not saying that we're not selling them. That is a potential.

So you're just-- you're reviewing all financial and operating aspects of them?

That's right. We're trying to maximize value.

I'm not sure if you've disclosed this but have you set out what the production from St. Leon was in Q1.

I don't think we disclosed that did we?

No. I don't think we did either because right now we are collecting LDs and the LDs are just not too far off the actual production.

Okay but the amount you're actually accruing in revenue, isn't that a per diem rate based on a specified amount that would be in the construction contract?

Yes we're getting a stipulated liquidated damages per day.

And that's the amount that's showing up on the financial statements?

Yes.

Plus the [WIPI]. We also a $0.01 per kilowatt hour on 80% of our production under the WIPI incentive program, the federal incentive program.

Okay so are those amounts higher than what you would be getting as for revenues then?

No it's roughly equal. It's not too far off.

So if I took the amounts in other income and then divided it by the estimated price for megawatt hours, I'd be able to come close to the production there?

Yes.

You have to include the WIPI as well.

Include the WIPI, okay.

Your next question comes from [Alda Pavan] from CIBC World Markets.

I just wanted to spend a little time discussing your capital expenditure program. It looks to me that it's been reduced slightly for the full year. More so I think has to do with the Infrastructure division and reduced spending there. Can you just talk about what-- if that's a true assessment and what 24 million is going to be spent on specifically at the infrastructure with the water utilities?

Yes just to comment on your observation that it has been reduced, you are correct. It has been and some of that is driven by growth and the fact that if we didn't have the growth we didn't have to make the expenditures. In terms of exactly what is being spent, I mean it is a long, long list so there are some significant items like increased capacity at [Lipsco], couple of new wells are put down in Lipsco as well. Arsenic treatment is another lump. All the rest though I believe are relatively hundreds of thousands, not millions.

Okay and with the capital spending that seems to be more focused on Lipsco, will that require a rate up case in order to recover that capital cost?

Yes.

When do you anticipate filing that?

Well, usually you make the investment and then you go in for a rate case so it's probably 2008 we will look to start the process.

Are there any other large rate applications that you can give us an update on that you anticipate filing in 2008?

No. I think our plan now is to sort of be in rate case almost all the time within the group of utilities so we're not going up with big lumpy rate increases like we did at Gold Canyon and the Missouri facilities. But there's going to be a large rate increase at Litchfield once we make our investment in the infrastructure expansion.

Okay and then I just want to move to the Sanger plant in California and specifically as it relates to the [SROC] component of the energy pricing. Do you have any views as it relates to the interim decision by the ALG-- the ALJ proposal I guess to the CPUC regarding the SROC and the implied heat rate and how that may impact your predicted revenue stream from that project?

Well, I think what happened there is we were offered an arrangement some time ago. I cant' remember exactly when. I would say probably 18 months ago I'm guessing, and we were offered an arrangement to have an implied SROC value which we-- and we opted to take that and in retrospect it worked out well because what they proposed fairly recently is somewhat below that so-- and that arrangement lasted for I believe three years so we anticipate for the next three years our SROC rates under that contract are stipulated.

Would you be able to know offhand what the implied heat rate?

No offhand I don't know that number but we obviously have it somewhere. I just don't know it off the top of my head.

Okay I'll follow up with that question. Thank you.

[Bill Cabell] from [TD Securities].

Actually I'll have to be a little quicker next time. All my questions have been covered off. Thanks.

Michael McGowan.

Somehow I'm not sure that, just following up on a question that was asked earlier but I'm not sure I caught the-- you said you had an interim agreement in California that would last for three years on the SROC pricing there. When is the end of that term?

Well, as I say it was three years from when it started and I don't know the exact date that it started but it was somewhere around I'd say 12 months to 18 months prior to now-- oh, Kelly is just advising me it was last July so it's based on three years from last July.

Okay so it will be effective until July 2009?

Yes.

Okay and you mentioned a bit of your experience in some margin compression at your Windsor Locks facility.

Sorry, I didn't catch that?

You mentioned that you're experiencing some margin compression at your Windsor Locks facility and natural gas plant?

Oh right, right. I understand what you're asking. Okay yes?

Is that based on the plant's operating below the deemed heat rate in the contract and then you're making money whenever the gas price goes up?

No it's based on the fact that the gas price, the natural gas price is a pass through to the customer. Our purchase contract for natural gas is based on about 70, I think 73% of the actual cost of natural gas so at the start of a year you can imagine we pick a number. In this case it was approximately $9 per MMBTU. If gas goes up from that we get to charge the full fare of that gas price, yet we only pay roughly three quarters of that gas price and so that works to our favor. In this case the gas price has gone down and we, as Dave said, it's virtually hedged but not entirely.

So you set a-- essentially you're setting a strike price at the start of each year and then you get to pass through 73% of that cost?

No you actually get to pass through 100% of the actual cost of natural gas yet you only pay 73% of the actual cost of natural cost so it's not a perfect hedge, if you will. It's not a perfect pass through.

(Operator Instructions) Tony Courtright.

Can I just confirm your liquidity in terms of undrawn availability under your credit facilities? You indicate how much is drawn as direct advances. I'm not sure how much is outstanding by way of letters of credit.

We're getting that number for you, Tony.

All right. Also--

We've got about $80 million on the line but for out fees about 45 million.

So 80 million as of today's date? Is that I mean subsequent to quarter end?

Yes, yes.

Okay so 125 of the 175 line is been availed of.

That's right.

The assessment, technology assessment, of the Quebec dams, can you outline what it is they're looking for and how-- do you have any initial feel for how compliant your properties might be with--?

Well, I guess that with the fallout from the floods that occurred-- I can't remember what year but the [Saginae] floods and they changed. The government of Quebec changed the regulations and came up with this new dam safety standards and that's what we're talking about here so phase one is obviously to do an assessment of all the dams in the province and see how they comply with the new dam safety standards. And then phase two is to come up with an action plan to see what changes have to be made. In our case, I think for most of our dams we'll be okay and those dams are fairly recent dams, dams like [St. Alban], [Rodens], some of those dams are all fairly new and we don't anticipate any changes required at all. We so have a couple of older structures, [Donna Conna] being one, [Mount Loray] being another and I think there's probably one at [Beltaire] so it's like probably three structures and we do anticipate some having to make modifications to those. As to what they are exactly, I don't know that yet but we're just advising people that that's something that we're facing right now.

Another question is your release provides the basic financial statements there are no notes. When would you expect those to be available?

Tony, it's Kelly. They'll probably be available-- let me just see here-- by the 15th at the latest. They'll be filed on [CEDAR].

Bob Hastings

Just top follow up on that dam question, the-- sorry how that was phrased but--

That wasn't very nice, Bob.

So in terms of the three structures that might need some work and I appreciate you don't know how much work etcetera, is there any provision that if it requires more work that you can change your rates or recover that somehow?

Well, I mean there's nothing with Hydro Quebec but there is the possibility that you might make a modification to a dam which results in more power coming out of the facility. You know I'm thinking if you increase the head at one of the facilities slightly, that could have an impact, a positive impact. So those are kind of some of the options we are exploring to offset some of the costs that we may incur.

And just one last thing on the water infrastructure just going back, the amount of rate increases that you're looking for, do you know what the year-over-year impact with all of them in place might be?

No we don't have that number.

Even for the ones that you already know them?

Well, we showed a 20% increase at [Black Mound], 140% increase at the Missouri facilities. We're in the middle of Gold Canyon. It's going to be the most significant of those other than the Missouri asset and we'll know that by end of June, early July.

No I was referring to the first two where you already know in terms of the actual dollar amount might be?

We just haven't-- we don't have the math on our fingertips, Bob. Sorry.

(Operator Instructions) There are no further questions. Please go ahead.

I'd like to thank everyone for joining us this morning and we look forward to talking to your about Algonquin Power's performance in the future. With that, we'll sign off. Thank you.

This concludes today's Algonquin Power first quarter results conference call. You may now disconnect.