Algonquin Power & Utilities Corp (AQNU) 2009 Q1 法說會逐字稿

Good morning, ladies and gentlemen and thank you for standing by. Welcome to the Algonquin Power Q1 2009 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 would like to remind everyone that this conference call is being recorded on Friday, May 8, 2009 at 10 am Eastern time and we will now turn the conference over to Mr. David Kerr, Executive Director. Please go ahead, sir.

Thanks, Yvonne. Good morning, everyone. My name is Dave Kerr and I am an executive director of Algonquin Power. I would like to welcome you to Algonquin Power's 2009 first-quarter results conference call. With me today on the call are Chris Jarratt, Executive Director; David Bronicheski, Chief Financial Officer; Luisa Read, our Controller; Kelly Castledine, Manager of Investor Relations; and Andrew Ingram, our Treasurer.

To start off, I'm pleased to report that Algonquin had a solid first quarter with increased revenues, growth in adjusted net earnings, stable EBITDA, which is primarily due to the increased performance of our Canadian renewable energy office, including outstanding performance from our St. Leon windfarm in Manitoba, which achieved a capacity factor of 49% for Q1. Algonquin continues to deliver strong results as a major player in the independent power and utility sectors.

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

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

I would like to start the call today with a few highlights and general updates on the business of Algonquin Power. Following that, our CFO, David Bronicheski, will deliver the financial results and Chris Jarratt will finish the call with a review of some of our growth opportunities and development projects we are working on. At the end of the call, we will open up for questions and answers.

Highlighting a recent successful business transaction, on April 23, Algonquin was pleased to announce plans to acquire an electrical utility through a strategic partnership with Emera. Algonquin Power and Emera will each own 50% of a newly formed California Pacific Electric Company, which intends to acquire the California-based electricity distribution and related generation assets of [MD] Energy.

This is a very positive step in strengthening our utility business and leveraging Algonquin's proven utility management and independent power generation expertise, while Emera brings a wealth of expertise and experience owning and operating local electric distribution utilities to the transaction. The transaction enhances Algonquin's cash flow quality and stability and will contribute to the long-term success of Algonquin.

Later in the call, David Bronicheski will discuss our current liquidity, but given the turbulence in the credit and capital markets, I would like to stress that Algonquin Power remains a strong and stable power and utility company. We continued to boast solid revenues at the beginning of 2009 as a result of strong hydrology and wind resources. We continue to advance our development projects and assess acquisition opportunities. We're strengthening our liquidity position. At the end of the first quarter, we had C$26.6 million of liquidity and capital reserves.

As an update to our focus on creating value through growth, our Development division continues to progress with greenfield development projects and we have seen acquisition opportunities open up with utility areas as evident with our recent acquisition. Our strategy is to continue to focus on high-quality, renewable and high-efficiency thermal energy 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 perpetual cash flows. We evaluate growth opportunities to determine the best return 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 in our recent partnership and co-acquisition of California Utility.

I also want to underline that we are in a strong position with C$40 million in equity available annually and conservatively speaking, on a 50/50 debt to equity ratio, we have about C$80 million of project financing each year.

As mentioned in the last quarter, we are starting to see signs of softening of power pricing in the New York and New England power markets where Algonquin has a relatively small merchant power exposure. While we benefited through 2008 from relatively high power prices, our strategy to diversify into different markets and to focus primarily on long-term contract and power agreements made Algonquin's exposure to spot pricing on the New England and New York regions has held to less than 4% of our gross revenues. While this is the case, as David will outline in a few minutes, there is an impact on results in our Renewable Energy division.

At our cogen facilities, where the price of gas is primarily a pass-through, there can be a positive/negative impact from changing prices. Recently, the price of natural gas has decreased, which had a small negative impact. But as mentioned, our contracts act as a natural hedge where we don't see great upside, but we also don't suffer from great downside of gas prices.

As an update to some of our short-term objectives, last quarter, we mentioned our plan to submit and complete several rate cases in our Utilities division that are expected to add C$10 million to annual EBITDA starting in mid-2010. As an update, during the last quarter, two additional rate cases were filed for facilities in Texas.

Based on our growing interest from our investors, we are progressing with our plans to have a distribution reinvestment plan in place by the third quarter of 2009 and we will provide information once we have it in place.

As an update on the sale of our remaining landfill gas assets, we continue to have discussions with several interested parties and anticipate a sale later in the year. We will keep you updated on the achievements of these objectives as we continue to move forward with them. I will now hand it over to David to talk about the results.

Thanks, Dave. Algonquin Power in Q1 2009 reported revenue of C$52.2 million compared to C$48 million in Q1 2008. Our EBITDA this quarter was C$21.1 million compared to C$21.6 million in the quarter ended a year ago. Net earnings in the quarter was C$4.2 million compared to a net loss of C$1.6 million in Q1 of 2008 and our adjusted net earnings for the quarter was C$7.9 million compared to C$3.9 million in Q1 of 2008.

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 rates swaps as these are primarily non-cash items that are not reflective of the performance of the underlying business and assets of Algonquin.

Now some further highlights from our business units beginning with the power generation and development business unit. In renewable energy during the first quarter of 2009, revenue from energy sales totaled C$19 million and the division generated electricity equal to 107.7% 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 we mentioned last quarter we would begin to see in Q1, and lower average hydrology compared to the same period in 2008. These impacts were offset by higher levels of hydrology over long-term averages in Quebec, Ontario and the West and strong wind resources at our St. Leon facility in Manitoba.

For the first quarter of 2009, operating profit totaled C$13.9 million as compared to C$15.2 million during the same period in 2008. Overall, the Renewable Energy division did not meet management's expectations due to lower weighted average energy rates in the US.

During the first quarter of 2009, the Renewable division produced sufficient energy to supply the equivalent of 60,000 homes with renewable power. Using new standards of thermal generation, renewable energy production saved the equivalent of over 148,000 tons of CO2 gas from entering the atmosphere in the first quarter.

In our Thermal Energy division, revenue for the first quarter of 2009 totaled C$23.5 million as compared to C$20.6 million during the same period a year ago. The increase was mainly due to increased production at the Windsor Locks facility and as a result of the BCI steam sales facility achieving commercial operation in June of last year.

During the quarter, production decreased 2000 megawatt hours at the Sanger facility and production increased by 2000 megawatt hours at the Windsor Locks facility. Our EFW facility increased throughput by 7.8% over the same period in 2008 processing over 41,000 tons of municipal solid waste.

During the quarter, operations at EFW resulted in the diverse of over 29,000 tons of waste from landfill sites. For the first quarter of 2009, operating profit totaled C$6.2 million as compared to C$5.5 million during the same period in 2008. Although the Thermal Energy division has shown improvement over the first quarter of 2008, overall, the division did not meet management's expectations.

Moving on to the utility services business unit. Revenue for the first quarter of 2009 totaled C$9.7 million as compared to C$7.5 million during the same period a year ago. Increased revenue resulted from organic growth and an increase in customer demand compared to the comparable period in 2008. The wastewater treatment and water distribution customer base remained essentially unchanged from the year before.

For the first quarter, operating profit totaled C$3.6 million as compared to C$3.2 million during the same period in 2008. Overall, utility services business unit exceeded Algonquin's expectations in the quarter. During the quarter, operations provided approximately 1.05 billion US gallons of water to its customers, treated approximately 500 million gallons of wastewater and sold approximately 55 million gallons of treated effluent.

As an update to Algonquin's liquidity position, given the tight credit markets that currently exist in North America and around the world, there is an increasing awareness and sensitivity about the importance of maintaining a strong liquidity and capital reserves position. Therefore, I would like to take a bit of time to talk about Algonquin's liquidity and highlight that Algonquin continues to have a strong liquidity position.

As noted on page 21 in our MD&A, we ended the quarter with C$26.6 million in cash reserves and committed bank facilities. At each of the last four quarters, Algonquin has been able to improve its liquidity position. I also want to underline that Algonquin remains in full compliance with all of its covenants under all of its loans and credit facilities. We continue to have the full support of a strong syndicate of four Canadian banks who are supportive of Algonquin's growth plans and prospects.

I would now like to turn the call over to Chris Jarratt who will share with you some of Algonquin's growth and development projects and our view for the next quarter. Chris?

Great, thanks David. I will start today with an update on our 25 megawatt wind project located in southeastern Saskatchewan. In addition to the milestones achieved to date, we have secured additional property and are assessing the viability of an expanded project, which would be conditional upon the operating results from the initial 25 megawatt phase of the project.

Last quarter, we mentioned that we had submitted a technical information package and environmental impact assessment. We are pleased to report that the environmental assessment is now complete and in March, Natural Resources Canada approved the project technical information package. Algonquin has submitted the environmental impact assessment for review in relation to obtaining funding under the federal ecoEnergy program and we expect a positive ruling in the second quarter of this year.

Building on the success of the St. Leon wind project, Algonquin Power continues to explore development opportunities for an expansion of the existing facility. The expansion opportunities have a potential generation capacity of over 85 megawatts and are estimated to require investment of approximately C$250 million.

As a follow-up to the successful repowering of the Sanger cogeneration facility, there are 14 megawatts of additional power available in excess of what is currently being sold under the power purchase agreement. Of this capacity, six megawatts can be sold with no further investments in the facility. An agreement to sell this six megawatts of power is expected to be finalized in the second half of 2009.

In order to market the remaining eight megawatts, an additional investment of C$2 million will be required by Algonquin and PG&E will be upgrading their transmission line in order to accept this additional capacity. Both of these activities are expected to be completed in late 2010.

Algonquin is also pursuing the redevelopment of the Windsor Locks facility located in Connecticut. If the power purchase agreement with CLP reaches maturity in 2010, a variety of options are being considered, including selling additional electrical capacity to an adjoining industrial customer. The energy services agreement with the papermill will, if not further extended by mutual agreement, continue until 2017.

At the energy from waste facilities, were are exploring several options with the Region of Peel to expand the waste processing capacity by between 40,000 and 100,000 tons per year. If the expansion is pursued, an investment of between C$60 million and C$250 million will be required depending on the proposal selected. We are currently evaluating all aspects of an expansion, including the associated capital and operating costs, tip fee arrangements with the Region of Peel and financing terms.

And on a final development note, as a power developer, we are very encouraged with the new Ontario Green Energy Act. While we are looking forward to learning more details of the Act, we are maintaining relationships with potential partners for the development of a number of projects that could qualify under procurement initiatives by the Ontario Power Authority and we will update you with further information as it becomes available.

The Renewable division going forward is expected to perform at or above long-term averages based on wind and hydrologic conditions. In addition the hydro facilities in the New England and New York regions are expected to experience lower market rates as compared to the rates experienced in 2008 as a result of a decrease in the demand for electricity.

We continue to undertake dam assessments required under the Quebec Dam Safety Act and currently, we estimate the work will require capital expenditures of approximately C$15.8 million. As noted on page eight of our MD&A, these expenditures will be completed over a period of five or more years and our MD&A outlines our estimate of the year-by-year expenditures.

In the second quarter, the EFW facility is expected to continue to operate in line with the 2008 results, while the Windsor Locks and Sanger facilities are expected to operate below 2008 results due to lower natural gas costs and a reduced demand for steam.

In addition, the Windsor Locks facility has a hot gas [pass] inspection planned for the second quarter, which is expected to last seven days and will reduce operating profit from this facility by approximately C$300,000.

For the remainder of 2009, Utility Services is not expecting any material reduction in water or wastewater customers. With the major capital program complete, the Utility Services will conduct rate cases at a number of its facilities, including four Arizona facilities and three Texas facilities. It is anticipated that regulatory review of the rates and tariffs for the Arizona facility will be completed in the latter half of 2009 with the new rates going into effect mid-2010.

While a confirmation of rate increases at these facilities is not possible as the rate case process is not yet completed, our expectation is an increase to EBITDA of C$10 million per year starting in 2010. Further details on the rate cases are detailed on page 15 of our MD&A.

In summary, overall, we are pleased with the results of the first quarter and we remain a stable business in a turbulent economy, which allows us to continue to conservatively pursue low-risk growth opportunities. We will continue to focus on conservatively managing the business while also managing the long-term success of the Company and growing investor value.

Thank you, Chris. With that, Yvonne, we can open up the lines for questions.

(Operator Instructions). Bob Hastings, Canaccord.

Hi, thank you. Chris, you mentioned about the rate increases and that you hope to get C$10 million of annual EBITDA increase from that starting in mid-2010. Just to be clear, you are asking for more than that and that is what your assessment is or is that what you are asking for?

Bob, it's Dave Kerr. That is a tough one to answer. We are making rate cases in front of the Arizona Corporate Commission and Texas as well and we filed the rate cases according to our capital investments and our operating costs. So we don't really want to get into exactly what we are filing, but our expectation conservatively is C$10 million of EBITDA.

Right. So nobody gets what they ask for in utility regulations, so just want to make sure that that is sort of what you are expecting to get as opposed to what you have asked for.

Yes, that's what we conservatively think we are going to get.

Okay, great. And the Red Lily project looked like an interesting one. You are looking at about a 42% utilization rate, if I did the math right on how much par you expect to get out of there.

Yes, Bob, it's Chris and that is fairly close to what we are expecting. It is located actually a few hours away from our St. Leon project. So it is an excellent wind resource and we have been collecting wind data for a fairly long time for wind projects. So we have pretty good expectations on that project.

Okay. And your financial plan, I believe you said you had surplus cash flow of about C$40 million a year at this point.

That's right, yes.

Free cash flow and you hope to lever that one to one, so you would have about C$80 million going forward?

Yes, that is what we are estimating, yes.

Okay. And you're also planning to put in a DRIP, which might then expand those numbers a bit I guess?

Yes, depending on the take-up of the DRIP program, yes. But we have had a lot of interest from our unitholders about a DRIP program. We had to make some changes to be able to put that in place, so we have done that.

That's very common with what other utilities are doing and I think probably a good idea. I was just trying to get an idea of how much capital you might have available and the C$40 million to C$80 million is the conservative number. Then it could expand a bit?

Yes, I would say that is, again, a conservative number.

Okay. And now Mr. Huskilson will be joining the Board of Trustees. I couldn't quite catch when is he expected to join?

Our expectation is it will be at the annual meeting.

Of this year?

Yes.

Okay. So it is not -- because you said the next annual meeting, I could've taken that one of two ways. So it is not next year, it is this year?

That is correct. The one that is planned for June 29.

Okay, perfect, perfect. And just regarding the financial statements, what were the changes? I noticed there was a footnote that the 2008 numbers had changed a little bit because of changes in accounting. What were those changes?

There were two new accounting pronouncements that came in beginning January 1 of this year. One was with respect to CICA 3064 with respect to intangible assets. The change on our books there is the deferred rate case costs, which were being carried on our books, no longer qualify under the new definition of intangible assets. And so therefore, those were removed from our balance sheet. Of course, it's done on a retrospective basis and so there is an opening restatement. So that was the primary change on that accounting policy.

The other accounting policy that came in in the quarter was EIC 173 and what that requires us and really I mean every company out there is, with respect to the derivative financial liabilities, you are required to risk-adjust that liability on your books to take into account the specific credit risk of your company because, up to this point in time, almost universally out there companies were going with the risk-free discount rate that was implicit in those derivative financial liabilities. And so now it has to be risk-adjusted according to the individual risk profile of the companies.

Okay. And have you changed the presentation style for foreign exchange? I know you hedge out and I think normally you reported your US dollar earnings in sort of your effective currency rate. And it looks like you are now using the actual currency and then your FX changes through at another line lower down?

No, there has been no change to how we translate our US foreign currency. I think what you may in fact be seeing is really the effects of a large swing in the Canadian and US dollar. A year ago, we were essentially looking at a Canadian/US dollar at par. In Q1 of this year, the exchange rate was 1.26. So a big difference. So I suspect that is what you are seeing.

Okay. And -- okay. And debt to -- when I look at your free cash flow, I guess I would expect your total liquidity to be improving at a little better clip than it may have. Can you sort of go through with us how that sort of transpires through the year?

Certainly. In the quarter, you will notice that the liquidity did improve by just about C$2.5 million. There is a few spiky things that happen in our cash flow in the year and in Q1, there were really three factors that were affecting that. First of all, our debenture interest happens twice a year and so we had the first installment of that in Q1 and so that accounts for a bit of that. We had a bit of a spike in the CapEx in Q1 and we don't -- we expect a more even spread of CapEx through the remaining quarters. And the other thing you will note is under our other debt, we had almost C$1 million of debt repayment on our facility-specific debt.

Right. Okay. Yes, I noticed it was a little light in the quarter given the C$40 million forecast. So that will swing back in as the year -- or swing back appropriately as the year progresses?

That's correct.

Okay, great. Thank you very much.

Michael McGowan, BMO Capital Markets.

Good morning. Can you give us an update on the Windsor Locks, just the PPA renegotiations and really what you are thinking about -- you mentioned I think last quarter the potential repowering of that?

Yes, it is Chris Jarratt, Michael. We are exploring probably three options and I guess the options can be divided into two. One is to try and use the existing equipment and basically create an opportunity which requires no capital to be -- or not a lot of capital to be injected into the project. And the other is to do a repowering and the repowering option involves a smaller gas turbine than what is in there now. So those are kind of the two options that are being explored.

In relation to option number two, have you estimated how much a project like that would cost?

Well, it depends on the size, of course, but if it -- and that's why I said there are three options. The two size options for that are roughly about a 13 megawatt project and about a 23 megawatt project. So just the typical capital costs for that are roughly a couple thousand dollars per kilowatt.

Okay. And what about discussions to renegotiate the PPA there?

Well, we are underway with conversations with the existing [mail astrom] and we are also having conversations with, as we mentioned in the little presentation, with an adjacent industrial customer.

Okay. Taking a look at your balance sheet, it looks like there is a C$10.5 million derivative liability at the end of this quarter. Now does that primarily relate to just the current positions of your interest rate swaps and your foreign exchange contracts and essentially we will just see basically that liability reduce through the year as those instruments are settled?

Yes, that's correct. And obviously the amount will vary depending on what happens with interest rates and FX through the year. We do have a breakdown of that number in the note to the financial statements.

Okay. And just -- I didn't see anything in the earnings release. Can you also provide maybe an update on the internalization of management initiative?

Yes, we have been talking about that all week with our trustees. The trustees are in the process of engaging third-party advisers to provide advice on the internalization. They expect to get going on that in Q2 with results later in the year. But it is a process we have to go through and the trustees are fully engaged in it.

Okay. So you hopefully will see something maybe second or third-quarter release?

Mike, it is hard to really put a definite timeline on that. All I can say is that the trustees are engaged and they are now talking to advisers.

Okay. Thanks a lot.

(Operator Instructions). Matt Gowing, Research Capital.

Hello, all. Just want to say congratulations on another quarter of cash flow stability. I do have a couple questions. Some might have been answered, but with respect to your growth plans going forward, do you foresee a lot of the growth coming from greenfield development opportunities or more so acquisitions similar to the news we have seen with Calpeco?

Well, that is a tough question to answer. We look at both greenfield development and acquisition opportunities on a value basis, what adds the greatest value to our Company and what we get the biggest bang for our buck I could say. So we don't have definite plans to do greenfield development versus acquisitions. We look at what comes along and we are seeing a lot of acquisition opportunities and of course, we are engaged in a lot of development opportunities. And it is just really what gets the best return because we have limited capital at this time.

Okay, thanks. And a follow-on question to Calpeco, could you maybe give us a little bit more color on what types of power gen development opportunities could come out of that acquisition?

Yes, it's Chris Jarratt. And I think as we mentioned on the previous call, there is a program in California where utilities are obligated to provide up to 20% of their output with renewable power. So that includes all the obvious ones -- wind, hydroelectric and solar. So those are the big ones that are being pursued under that program.

Okay, thanks. That's it for me.

Bob Hastings, Canaccord.

Yes, thank you. Now that you are focusing in more growth and getting your mindset sort of out from under the old trust way of thinking of paying out everything and distribution, a lot has changed in the capital markets. Obviously hurdle rates have gone up. Can you give us some kind of guidelines of what you're thinking of projects that -- and you are limited to your capital. So sort of where is your cut-off or how do you pursue projects in here? And then as a follow-up to that would be when you are looking at something like the EFW expansion, which could be massive depending on which way it goes, sort of how you think of financing something like that?

Okay, Bob, it's Chris. I mean we don't really necessarily have one hurdle rate for all projects because we kind of see all the different types of projects with different risks, different risk profiles. Obviously we compare it to what we own right now. We compare it to how accretive it is, it would be.

In terms of financing something which is as large as the EFW plant, I agree with you. If you went to the full-sized expansion, that is a pretty significant project. And the one positive that project has going for it is that it has a pretty strong partner, I will call them a partner, in the Region of Peel and that is certainly one of the options that we are exploring with the Region of Peel of doing it in partnership with them.

Okay. And as you are looking around at various projects, do you look at balances of long-term contractual arrangements, trying to get the stability cash flow or merchant with maybe higher returns or sort of what is the strategy there?

And that comes back to the every project is a little different. We obviously much prefer projects that have long-term agreements. We have always thought, in a perpetual mindset when we looked at assets, we think in terms of perpetual assets and perpetual cash flows. And that is why we've always liked assets like wind, hydroelectricity and the utility space.

Okay. And your thinking in terms of returns? At one time, you and most other trusts would have said, well, our distribution yield is, pick a number, 8%, so that is our cost of capital. How do you think of your cost of capital today?

Well, obviously, our cost of capital is somewhat higher than that today. So every project we look at we think about -- it has to provide much more return -- a much higher return than that.

So Bob, this is David Bronicheski. As an example, in the utility sector, capital asset pricing model is now indicating that the cost of capital in the utility sector is now in that 12% to 13% range. So we have -- we do recognize that the cost of capital, at least in the near term, has gone up significantly.

Okay. And all your projects would meet at least that hurdle rate? The ones you are looking at?

In the utility sector, we would be taking that cost of capital into account in all of the rate case applications that are currently before the regulators.

And Bob, all projects would have to meet that criteria or else we would not foresee to hit on them.

Right. Okay, that's great. And then lastly then, if I were to look at you earning that kind of cost of capital on new projects, it seems like your earnings growth rate would rapidly accelerate in here to a fairly strong level. Do you have any sort of expectation? A lot of companies will sort of say our longer-term growth rate plans are X. Do you have anything, any estimates like that? Targets?

I think we have pretty much put out the guidance that we have. We have an estimate of the free cash flow that we can put to work. We can marry that up to the cost of capital expectations that we have on the assumption that we are not issuing new equity and certainly we are not at this time. I think you can pretty much drill down to a number fairly quickly.

Yes. I just noticed your units, even though they have accelerated nicely, are still trading about 10 times earnings. Okay, great. Thank you very much I appreciate your answers.

Thank you, Bob. Thanks for the questions.

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

Okay, thank you. I would like to thank everyone for joining us this morning, but please remain on the line for our exciting review of our forward-looking statement disclaimer.

Certain written and oral statements contained in this information are forward-looking in the meaning of certain securities laws and reflect the views of Algonquin Power Income Fund and its manager with respect to future events based upon assumptions relating to, among other things, the performance of the Company's assets and the business' financial and regulatory climate in which it operates.

These forward-looking statements include, among others, statements with respect to the expected performance of the Company, its future plans and its distribution to unitholders. Statements containing expressions such as seems, anticipates, continues, could, expect, may, will, project, estimate, intend, plan and similar expressions generally constitute forward-looking statements.

These forward-looking statements relate to future events and conditions. By their very nature, they require us to make assumptions and involve inherent risks and uncertainties. We caution that although we believe our assumptions are reasonable under the circumstances, these risks and uncertainties give rise to the possibility that our actual results may differ materially from the expectations set out in the forward-looking statements.

Material risk factors include the continued volatility of world financial markets, the impact of movement in exchange rates and interest rates, the effect of changes in environmental and other laws and regulatory policy applicable to the energy and utility sectors, decisions taken by regulators on monetary policy and the taxation of income funds and the state of the Canadian and US economy and accompanying business climate.

We caution that this list is not exhaustive and other factors could adversely affect our results. Given these risks, undue reliance should not be placed on forward-looking statements, which apply only as of their date. Except as required by law, the Company and its manager do not intend to update or revise any forward-looking statements whether as a result of new information, future developments or otherwise.

Thank you, Kelly and again, thank you, everyone, for joining us.

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