Algonquin Power & Utilities Corp (AQNU) 2008 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Algonquin Power annual and fourth-quarter 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 would like to remind everyone that this conference call is being recorded on Friday, March 6, 2009 at 10 a.m. Eastern time. I will now turn the conference over to Dave Kerr, Executive Director. Please go ahead, sir.

Well, thank you. 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 2008 fourth-quarter and year-end conference call. With me today on the call are Chris Jarratt, Executive Director; David Bronicheski, Chief Financial Officer; [Louisa Reed], Controller; Kelly Castledine, Manager of Investor Relations and Andrew Ingram, our Treasurer.

To start off, I am very pleased to report that Algonquin had a great year in 2008 with increased revenue and growth in EBITDA due to increased hydrology, great performance from our St. Leon wind farm in Manitoba and improved performance from our Thermal Energy facilities with the Energy From Waste, or EFW, facility having one of its best years ever. Algonquin continues to deliver strong results as a major player in the independent power and infrastructure sector.

For your reference, the financial statements and management's discussion and analysis are available on Algonquin Power's website. I encourage you to review the MD&A as we have spent the last quarter improving Algonquin Power's disclosure as a response to feedback we have heard from our investor and analyst community. As a result of our move to a new business model, we have and will continue to focus on improved communications with the investment community. Before we begin, as a housekeeping issue, Kelly will quickly review our forward-looking statement disclaimer.

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

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

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

Material risk factors include the continued volatility of the world financial markets, the impact of movements in exchange rates and interest rates, the effects of changes in environmental and other laws and regulatory policy applicable to the energy and utility sectors, positions taken by regulators on monetary policy and the taxation of income funds and the state of the Canadian and the US economy and the 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 managers do not attend to update or revise any forward-looking statements whether as a result of new information, future developments or otherwise.

Thanks, Kelly. I would like to start the call today with a few highlights and general updates on the business of Algonquin Power. Following that, the financial results will be delivered by Algonquin Power's Chief Financial Officer, David Bronicheski and at the end of the call, we will have a question-and-answer period.

During the fourth quarter, on October 20, Algonquin announced a change in distributions from C$0.092 per year to C$0.24 per year. It is important to note that the change in distributions was not made because of any fundamental change in the business of the fund. In fact, you will hear shortly from our CFO that the fund is performing very well despite these turbulent times in the economy. Algonquin remains a strong, stable company generating reliable cash flows.

The distribution change was made for a few reasons -- firstly, to prepare for the change in taxation of policies that faces income trusts in 2011; secondly, to fund growth opportunities; and lastly, to strengthen our liquidity given the turbulent credit markets. The level of distributions we established last October takes into account what is required to fund the equity portion of our growth plans and also the new taxation of income trusts that will begin in 2011.

Since income trusts continue to enjoy a tax advantage relative to our corporate peers, our plan is to continue benefiting through 2009 and 2010. When all income trusts, including Algonquin Power, become taxable in 2011, our plan is to convert to a corporation. I would also like to point out to investors that, in 2009 and 2010, we expect our cash distributions to be taxed as ordinary income, but with no return on capital or special distributions.

Later in the call, David Bronicheski will discuss our current liquidity, but given the turbulent credit in capital markets, I would like to stress that Algonquin Power remains a strong and stable power and infrastructure company.

In 2008, we posted record revenues as a result of strong hydrology, high merchant power prices and high gas prices. We continue to advance our development projects and assess acquisition opportunities and we're strengthening our liquidity position. By the end of 2008, we had C$24.2 million of total liquidity and capital reserves.

As an update to our focus of trading value through growth, our development division continues to progress with greenfield development projects and we are seeing acquisition opportunities open up within power generation and utilities as a result of the turbulent economic environment. These opportunities include third-party development projects that are having a difficult time with financing in the current capital markets, as well as capital equipment at discounted prices. We are looking at all these opportunities, which could serve to increase expected returns for Algonquin.

Our strategy is to continue focusing on high-quality renewable and high-efficiency Thermal Energy generation projects that benefit from low operating costs using proven technology. In addition, we are looking at good quality regulated utility assets that provide steady and stable perpetual cash flows. Our long-term goal is to generate sustainable and increasing cash flows in order to achieve high returns on invested capital. We evaluate growth opportunities to determine the best return on a risk-adjusted basis.

Although the development business has a number of high-quality projects in the pipeline, we generally only begin to discuss details of projects we are pursuing when there's a realistic probability that they will move forward. One of the best prospects at the moment I would like to highlight is the 25 megawatt Red Lily project in southeastern Saskatchewan.

In 2008, we reached a major milestone with the signing of the power purchase agreement with SaskPower. We also received confirmation of the project eligibility under the federal ecoENERGY for Renewable Power program and have submitted a technical information package and an environmental impact assessment. Perpetual review of these documents is expected to be complete in the first quarter of 2009.

In the event the project is developed, the current estimate is to require a total capital investment of approximately C$65 million by the time the project is scheduled for completion in March 2011. Annual energy production from the wind farm is estimated to be 92,000 megawatt hours and annual gross revenue is estimated to be C$8.9 million.

In addition to the Red Lily wind project, I would like to highlight a few other development projects we're working on. As a follow-up to the successful repowering of the Sanger cogeneration facility, there is 14 megawatts of additional power available in excess of what is currently being sold under the existing power purchase agreement.

Of this additional capacity, six megawatts can be sold with no further investment in the facility and an agreement to sell the six megawatts of power is expected to be reached in the second half of 2009. In order to market the remaining eight megawatts, an additional investment of C$2 million would be required by the fund. PG&E is in the process of upgrading the transmission line in order to handle this additional capacity, which is expected to be completed sometime in 2010.

Building on the success of the St. Leon wind energy project, Algonquin is exploring options to pursue a future adjacent project and an increase in the installed capacity of the [Zixing] facility. The projects have a potential generation capacity of over 85 megawatts and our estimated required investment of approximately C$250 million.

At the Energy From Waste facility, the development division is currently reviewing several proposals to expand its power generation and waste processing capacity to between 40,000 and 100,000 tonnes. We are currently evaluating a feasibility of expansion, including the associated capital and operating costs and financing trends.

As a power developer, we are very encouraged with the new Ontario Green Energy Act. We are looking forward to more details of that, but we believe that this will open up a lot more opportunities for Algonquin to successfully bring Renewable Energy projects to market.

Although times are challenging with respect to accessing capital, I want to underline that we are in a strong position with C$40 million in equity available annually and conservatively speaking, at a 50/50 debt-to-equity ratio, we have C$80 million of project financing each year.

One of Algonquin Power's unique advantages is the diversity and conservative risk profile of our asset portfolio. Over 85% of our assets are in rate-regulated environments or under long-term take-or-pay power purchase agreements with investment-grade utility customers. This is beneficial in challenging economic environments where there could otherwise be fluctuation in merchant prices and fuel prices -- merchant power and fuel prices.

I would also like to note that we are starting to see signs of softening power pricing in the New York and New England power markets where Algonquin has a relatively small merchant power exposure. We have benefited through 2008 from relatively high power prices. Our strategy to diversify into different markets and to focus primarily on long-term contracted power agreements means that Algonquin's exposure to spot pricing in the New York and New England region is held to less than 4% of our gross revenue.

The price of natural gas has also decreased recently. Our cogen facilities, where the price of gas is essentially a pass-through, we are indifferent to the price of gas. Our contacts act as a natural hedge where we don't see the upside, but we also don't suffer the downside of gas prices.

In addition to prudently managing operations and pursuing growth opportunities, some of our short-term objectives include the following. We plan to submit and complete several rate cases in our Utility Service division that are expected to add C$10 million in annual EBITDA starting in mid-2010. We also plan to have a distribution reinvestment plan in place by the third quarter of 2009. And we also are actively looking to sell our remaining LFG assets by the end of 2009. We currently have several offers and we will be entering into negotiations shortly. We will keep you up to date on achievements of these objectives as we continue to move forward. Now I will hand this over to David to talk about the results.

Thanks, Dave. Algonquin Power posted very strong results for the year ended 2008. Gross revenue for the year ended at C$213.8 million as compared to C$186.2 million the year before, an increase of 15%. Our EBITDA was C$90 million compared to C$86.2 million the year before, an increase of 4.4%. Net loss for the year was C$19 million as compared to net earnings of C$23.7 million, but I would like to point out that the net loss in 2008 is attributable to a C$42.4 million loss associated with the unrealized portion of derivative financial instruments. And the mark-to-market losses are, of course, a non-cash item.

Now some further fourth-quarter highlights. In the Renewable Energy division, during the fourth quarter of 2008, revenue from energy sales totaled C$19.2 million and the division generated electricity equal to 105.1% of long-term projected average wind and hydrology. During the year 2008, revenue from energy sales totaled C$75.5 million and the division generated electricity equal to 106.5% of long-term projected average wind and hydrology. The increase in annual revenue is mainly a result of significantly higher levels of hydrology over long-term averages in all regions and specifically in Quebec where our hydrology was 14% above long-term averages and the New England region where we experienced hydrology of 38% above long-term averages for the year.

For the fourth quarter of 2008, operating profit totaled C$13.4 million and for the year 2008, operating profit totaled C$54.6 million. Overall, the Renewable Energy division exceeded management's expectations due to greater than long-term average resource availability.

During the year 2008, the Renewable Energy division produced sufficient energy to supply the equivalent of 60,600 homes with renewable power and using new standards of thermal generation, Renewable Energy production saved the equivalent of 600,000 tonnes of CO2 gas from entering the atmosphere in 2008.

Turning to the Thermal Energy Division, revenue for the fourth quarter of 2008 totaled C$27.5 million, an increase over the same period in 2007. For the year 2008, revenue increased to C$103 million, a 20% increase over 2007. The increase is mainly due to increased production at the Sanger and landfill gas facilities, the Brampton cogeneration project being fully operational for the full quarter and greater throughput at the Energy From Waste facility as a result of operational improvements that have been completed.

During the quarter, production increased 16,200 megawatt hours at the Sanger facility as a result of the repowering and the landfill gas facilities increased production by 3300 megawatt hours during the quarter. The EFW facility increased throughput by 2300 tonnes as compared to the same period in 2007.

For the year 2008, the Thermal Energy business unit increased by 31,200 megawatt hours at the Sanger facility and by 12,400 at the landfill gas facilities. In 2008, the EFW facility processed a total of over 160,000 tonnes of waste, an increase of 15% over the year before. During the year 2008, operations at EFW resulted in the diversion of approximately 110,000 tonnes of waste from landfill sites.

For the fourth quarter of 2008, operating profit totaled C$7.7 million and for the year 2008, operating profit totaled C$31.1 million. Although the Thermal Energy division has shown improvement during the quarter, overall, the division did not meet the Company's expectations due to increased operating expenses related to our landfill gas assets.

Moving on to Utility Services, revenue for the fourth quarter of 2008 totaled C$9.8 million as compared to C$8 million during the same period in 2007. For the year 2008, revenue totaled C$35.2 million compared to C$33.7 million in 2007. In both cases, increased revenue resulted from organic growth and increased in customer demands compared to the comparable periods of the year before.

The wastewater treatment customer base grew by 1% year-over-year and the water distribution customer base grew by approximately 1.5% year-over-year. For the fourth quarter, operating profit totaled C$3.7 million and for the year, operating profit was C$17.6 million and overall, the Utility Services business unit did not meet our expectations due to the slower organic growth and higher operating costs.

During 2008, operations provided approximately 5.8 billion US gallons of water to its customers and treated approximately 1.9 billion gallons of wastewater and sold approximately 530 million gallons of treated effluent.

I would now like to talk briefly about liquidity. Given the tight credit markets that currently exist in North America and around the world, there is increasing interest in and awareness about the importance of maintaining strong liquidity and capital reserves position. So I would like to take a bit of time to talk specifically about Algonquin's liquidity and highlight that Algonquin continues to have a strong liquidity position.

As noted on page 29 in our MD&A, we ended the year with C$24.2 million in cash reserves and committed bank facilities. In each of the last three quarters, Algonquin has been able to improve its liquidity. I also want to underline that, as at December 31 and throughout 2008, Algonquin was in compliance with all of its covenants under its loans and credit facilities. We continue to have the full support of a very strong syndicate of four Canadian banks who are very supportive of Algonquin's growth plans and prospects.

There is also a heightened interest these days in the potential counterparty risk and I would like to point out two new disclosures that we have worked into our MD&A on page 43 where we set out our major customers and their credit ratings as well. I would now like to turn the call back to Dave Kerr who will share with you Algonquin's view of the year ahead.

Thanks, David. Looking to the year ahead, 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 and New York regions are expected to experience lower market rates as compared to the rates experienced in 2008.

We continue to do our assessments required under the Quebec Dam Safety Act. Currently, we estimate the work will require capital expenditures of approximately C$14.5 million. However, as noted on page 13 of our MD&A, these expenditures will be completed over a period of five or more years. Our MD&A outlines our current estimate for the year-by-year expenditures.

The EFW, Windsor Locks and Sanger facilities are expected to continue to operate through 2009, in line with Algonquin's expectations. The Windsor Locks facility has a planned hot gas path inspection in the second quarter of 2009, which is expected to last 8 to 10 days and reduce operating profits from that facility by C$300,000.

On the development side, we believe that future opportunities for power generation projects will continue to rise given that many areas, both in Canada and the United States, continue to increase targets through renewable and other power generation projects included in the Ontario Green Power Act.

With the major capital programs substantially complete, Utility Services has initiated rate cases at several Arizona facilities and in addition, five facilities in Texas will be initiating rate cases early in 2009. It is anticipated the regulatory review of rates and tariffs will be completed in the second half of 2009 with the new rates going into effect in the second half of 2010. While a firm forecast of rate increases at these facilities is not possible as the rate cases are in their early stages, the expectation is a potential increase in the annual orderings of C$10 million starting in 2010. Further information on the rate cases is detailed on page 22 in the MD&A.

So in summary, Algonquin Power has had a strong year in 2008 and anticipates that we will continue to perform in line with expectations in 2009, generating funds to prudently balance our debt position and growth initiatives to satisfy long-term sustainable distributions of C$0.24 per unit per year.

Algonquin Power is well-positioned to weather the economic instability through our well-diversed, long-term contracted asset portfolio. We are beginning to see increased opportunities as a result of the struggling organizations that lack the strength of Algonquin Power. We are prudently evaluating these opportunities against our return criteria with the goal of rebuilding the market value of Algonquin Power and creating returns for our investors. With that, we can open up the lines for questions.

(Operator Instructions). [Arvin Malek], KMF Investments.

Good morning. Yes, it's wonderful to see the solid operating results that you reported, especially being the long-term shareholders in the fund that we are. It shows the great strength of our existing asset base and just looking at the level of distributable earnings that the business has generated, we are very pleased with that.

Just looking at the current unit price, we are looking at calculating the yield on it. It looks like, at the current levels, Algonquin has a distributable cash flow yield of over 30%. Now just looking at it from the point of view of a long-term shareholder, it is pretty clear to us and seems rather obvious that the ROI of 30% plus with no incremental execution risk, repurchasing shares would be a great option for Algonquin. And we are just very disappointed that there has been no discussion on this call of that.

So I would like you to comment on whether this has been actively considered and how you weigh the decisions on new capital investments, whether greenfield or acquisition, compared with this very high bar that will be very lucrative for long-term shareholders.

Yes, I think we would agree with you that, based on our existing share price, that the rate of return is quite high. What we do believe, and our trustees believe that, at this time, we can prudently reinvest the capital that we are preserving into quality assets to further increase the cash flow and the sustainability of the cash flow of the unit. So at this time, the trustees are preferring to reinvest the capital as opposed to buying back shares. But we are reevaluating that policy all the time.

Could you clarify kind of the logic behind, just the financial logic here, in terms of ROI? It seems pretty clear that there is -- with such a high ROI on repurchase with no incremental risk of due diligence or execution risk of capital projects, how is it possible that this wasn't the highest priority use of capital?

Well, I think we can say that, in these markets, access to credit is tight and it is really just a matter of balancing our view of things over the long term. I think it is fair to say that our trustees are taking a longer-term view of the unit price and really not wanting to react in sort of the heat of the moment, if I can use that term. So we take a longer-term view and given the tightness of the credit markets, credit is a precious thing and right now, that is just not the place where we are choosing to put our credit to work.

But that being said, like I said, the trustees are reviewing that policy all the time and watching the share price all the time. So we hear you and we consider it seriously.

Well, I certainly appreciate that. And just to emphasize our perspective, we are long-term-oriented shareholders and we are not talking about this just in terms of the market perception. We generally think, and this should be very apparent just from the sheer numbers, that the ROI is so high for share repurchases -- and I agree with the liquidity considerations. It is prudent to have a better liquidity position. I'm glad that management has been able to achieve that. But as you compare capital investments for growth, it seems pretty obvious that reinvesting in the business or repurchasing units is far more accretive to shareholders than growth. Just looking at the ROI numbers that you've presented.

Yes, we understand that. Thank you very much.

Tony Courtright, Scotia Capital.

Thanks very much. Could I just get a confirmation of what liquidity position really is because there is discussion of unexercised portion of an accordion feature, but then it seems that that whole accordion feature of your credit facility is not available? Is that correct?

Well, no, that's not correct. And what we are laying out on the table is basically, in the first two lines, is coming down to the C$192.7 million is the amount of committed and available facilities that we have and then we come down after that to on that what we have drawn and the letters of credit to come down to that C$18.2 million, we add the cash, we come to the C$24 million. Now with respect to that unexercised portion of the accordion, if we so chose, we could, given our existing covenants, access another C$8.8 million of that C$32 million that was deducted up above.

So that you are constrained in how much you can avail yourself?

Of the unexercised portion of the accordion, that is correct.

Right. So somewhere in the order of C$23 million of it is -- you are precluded from using because of the covenants?

That is correct. But as our EBITDA grows, clearly we would be able to access more of that. But you are correct in your statement.

And then it's the EBITDA retrospective, so you actually have to demonstrate historical performance before that becomes available?

That's correct.

All right. Can you address what plans you might have to deal with the convertible debentures that are due in 2011?

Well, first, I would like to say it still is 2.5 years away, which isn't to say that we haven't been giving it some thought. Currently, there is a number of options that are on the table and that would not involve conversion of the convertible debentures into equity. There is options such as -- it could be a preferred unit issue, could be a subordinated debt issue, could be a warrant issue where we strike a coupon and see if the existing CD holders would simply like to stay on and continue with that investment. So there is a number of options that we are looking at, but the decision will be made obviously in the context of the markets come 2011.

All right. Then what about the maturing credit facilities in January 2011? What are your plans for those?

Well, as I explained, we have a very strong syndicate -- four Canadian banks. They are very, very supportive of Algonquin. And we have every expectation that we will be able to renew our credit facility going forward again. It will be obviously under the market terms at the time, but clearly all of our banks have indicated that they are very supportive of Algonquin.

This is becoming a large measure of it permanent funded capital and do you see that as being prudent or reasonable for you to be relying on bank credit facilities for that purpose?

I mean I take your point and come the end of the term of the facility, I mean what we will look at -- how much of that facility needs to be turned over in shorter-term debt. Whether it is appropriate at the time to bring in some longer-term debt placement, certainly the capital structure is always under review and when you have an opportunity to renew your credit facilities with your banks, you would look at that at the same time.

And also, Tony, given the quality of our cash flow and our asset base, we have lots of options open to us in terms of credit and debt financing.

I would suspect that any other creditor would not want to be behind the banks, and yet the banks wouldn't want to be behind a lot more senior debt, secured senior debt. So you are going to have to juggle the two competing needs.

Yes, of course. That is why we are always looking at our capital structures.

And one last question. Internalizing management, you referred that it may be being stymied a bit by disruptions in the current credit and capital markets. Can you elaborate on how those factors influence the internalization discussions, negotiation?

Well, the trustees obviously have stated they want to deal with the management contract, and that is one of their priorities. Over the last quarter -- or additionally more priorities. We have been looking at a lot of things. So essentially, the trustees just really did not get to the management contract.

So we made a statement back in October 20th that it would be dealt with in Q1 of 2009, and that is just not going to happen right now because of the priorities with the trustees and management.

It is not an issue of the current capital markets, say the discount rate changing any price negotiation?

No, nothing to do with that.

All right. Thank you very much. Those are my questions.

Juan Plessis, Canaccord Adams.

Great, thank you. Just to follow up to Tony's question, do you have a new timeframe target for internalizing the management contracts?

No, we don't actually. The trustees have acknowledged that it is a serious issue; they want to deal with it. But they haven't really given any timeframe when they are going to deal with it.

Okay, great. Then moving on with respect to new projects, can you add some color around your hurdle rates for new projects? I am just looking at in particular the Red Lily project. It looks like with revenue of about C$8.9 million annually, adjusting for OpEx and stuff, it just looks like the return on C$65 million is a little low.

Yes, it's Chris speaking. Yes -- no, I would agree that that project has got some challenges, and that is what we are working on on a daily basis to try and overcome those challenges. I would say that that project is definitely not a bellringer from the point of view of financial returns.

I mean there may be some opportunities to take advantage of the tax advantages in that project, kind of like we did with AirSource. So that is an opportunity that we are exploring that might enhance those returns.

I'm sorry, you were going to say something?

Well, I was just kind of focusing my comments strictly on that particular wind project. I mean, we approach every project on a risk-adjusted basis. Some projects may not require the same returns that other, in our view, higher risk projects would.

Okay. And then with respect to the Brampton cogen project, it looks like for the seven months that it was in the operation in 2008, it generated about, it looks like C$0.9 million of cash, which if you annualize that it is about C$1.5 million. That is on, I guess, a capital investment of just over C$16 million. Is there anything you have in mind that could improve these returns?

Yes, there are. I think if you look at that, that first nine months, it included the startup woes that you generally have with a new project. And I do think we do have opportunities to enhance that in the long-term.

Okay, so then the C$0.9 million is not representative of what it is going forward?

No, I don't believe so. I believe that there is an opportunity to enhance that.

Okay. On the Energy From Waste expansion potential, you have been evaluating this for quite some time. Do you have any sense of timing in terms of when a decision might be made?

I agree with you, it is taking a long time. And part of the reason is because it involves the Region of Peel. It is not a bid situation where the bids go in on a certain date and they are all awarded. It is being done on a one-to-one basis with the Region of Peel, and that can take a little while.

I do believe we are getting close on that, and I would think in the next two quarters we will be able to advise you where things seem to be heading.

Okay. And you mentioned that you have options, I guess, ranging from a C$60 million investment up to C$250 million. Any probability on the lower end or higher end?

No, I wouldn't say so. I mean really it is long conversations with our customer and what best suits their needs. I would point out that, of the type of projects we like, a project like Peel is exactly what we really like a lot and from the point of view that you are not competing in a bid situation, it is sole-sourced and we feel we have much more control over the situation. So we are very encouraged by that type of project.

Okay, great. And moving on to the Utility Services segment, it looks like the expenses continued to jump up here. I am just wondering if you have considered perhaps reducing your CapEx in these operations going forward given the declining returns you are seeing.

As we described in our MD&A, our major capital program in the utilities is essentially complete as of the end of 2008. And so we are in the process now of initiating rate cases and we are going to greater lengths now to disclose what is being submitted for those rate cases and approximately when we can see the rate cases coming into effect.

I would agree that the expenses in the Utilities division have gone up, but that is also why we are going in for the rate case. And so we will be getting a recovery of expenses going forward. There is obviously a bit of regulatory lag before that happens, but certainly the revenues will catch up to the increase in expenses. And as part of that rate case-making process, we do go through an exercise of comparing our costs relative to other utilities that operate in the state of Arizona. And our cost in the Utilities division is at or below those of our peers. So we are comfortable with the efficiency of the Utilities business unit, but we now just need to get the new rates into effect.

Okay. And given where the economy is now and the recent appeal against Gold Canyon, are you still confident in the rate increases?

At the end of the day, the regulator has to give you your required rate of return. So we are fully confident that we are going to be able to achieve our objectives in the rate cases.

Okay. Thank you very much.

Michael McGowan, BMO Capital Markets.

Good morning. I also have a question about the Utility division. Can you talk a little bit about the difference in regulation in Arizona versus Texas? It seems that you are expecting much quicker turnaround in Texas and I was just wondering what the key differences are that would allow that?

Yes, there are two different regulatory zones in Arizona -- the Arizona Corporate Commission, which is they litigate the rate cases where you actually go in front of a judge, make your case for your rates and there is actually an automatic opposition to that rate case. And so you have to go through the process to get the Commission to sanction the rate increase. And that takes 12 to 18 months. It is just that is the process in Arizona.

In Texas, it is quite different. You increase the rates that you feel that is prudent and if no one objects to that, then it is automatically included in the rate. If someone objects to it, then there is the potential for a hearing. But you are still collecting the higher rates as soon as you announce them. So it is quite different, the two different processes.

When you actually do file or file for rate increases in Texas, is there a window where people are allowed to I guess dispute that or what is the timeframe there?

I don't have it exactly, but it is between 30 and 60 days. I am going by memory, but between 30 to 60 days, they have to appeal that.

Okay.

And if you -- if it is deemed that you are charging too much, then you have to rebate the customers for the money that you have taken over the time.

Okay. So I guess that would be fairly typical whenever interim rates are set?

Yes, that's right.

Can you -- I mean you haven't really said much about the internalization other than it is going to be possibly delayed a little bit. Can you talk about what the potential terms are, the transaction you are thinking about since it is a fairly important initiative?

We recognize that it is an important initiative and everyone is focusing on it, but we haven't got to the point yet where we are prepared to announce the terms of the termination of the contract.

Okay. And Windsor Locks, that PPA, I think that will expire next year and I read in the earnings release that it looks like you are undergoing a repowering there. Can you talk a little bit more about the capital costs, if you are working on extending the PPA and what sort of incremental cash flows you are seeing or you are hoping for from that initiative?

Sure. It's Chris speaking again. Yes, only one of the PPAs expires next year. That is the power purchase agreement with CLP. There is a steam agreement that goes on for another seven or eight years after that -- I think it is eight years -- as well as I think it is like 14 megawatts of electricity. So the whole thing doesn't expire and what the process there is to go through and evaluate the existing equipment that is there and seeing what can be done with existing equipment, that being one series of options. And then a second series of options consists of what can be done with new equipment. And obviously if you just stuck with the existing steam sales agreement and the existing electricity agreement, that would be a smaller facility.

Sorry. Can you repeat that again? Just the last bit -- you are looking -- what was that initial?

Well, I am saying, if you went with brand new equipment and just took advantage of the existing steam sales agreement, as well as the existing electricity agreement with the mill, it would be a smaller project. The problem is you have a fairly large turbine there and so unless you sell that excess power to somebody, and that is an opportunity, but if you can't do that, then you would require a smaller gas turbine.

So then the C$3 million that you are spending this year, does that just relate to exploratory expenditures?

It is really a placeholder and I suspect that is probably on the high side for 2009. But yes, I can imagine we will finish our study and not knowing which option we will choose, it is hard to advise you how much money we will be spending in 2009, but it was really just a place holder of some size.

Okay, so right now, that is meant to highlight the cost of the study rather than any capital upgrades?

No, it is to finish off the study and start whatever work gets started in 2009. Probably towards the end of 2009 something will be started. I just can't tell you which option it is because we haven't finished the study.

Okay. And just one more question about the Utilities division there. The C$10 million lift in EBITDA that you are looking for, is that based on your contemplated rate cases as filed or are you including any contingency in that estimate?

No, that is based on the cases that have been filed and the cases that will be filed. So that is our estimate of the EBITDA increase in 2010.

Okay. And your bond covenants, is there anything in there that restricts or that limits your ability to actually increase your debt to buy back shares?

No, the credit that we have available under our bank credit facilities would certainly permit a buyback of units, but you have to live within the covenants.

Okay, thank you.

Richard Schaefer, RBC Dominion Securities.

Good morning. I listened to your call and the one that someone asked you about, because it was glossed over quickly and maybe it should have been and maybe it shouldn't have been, was the derivative losses, the C$42 million derivative losses. So are these paper losses that you have lost offsetting cash gains you have made? I need to understand it better. It seems to be a very significant number.

Yes, certainly. We have a table both in the MD&A and in the financial statements and we do make reference to it where, in the note, and I am just --

I am on page 4 right now in the MD&A and looking at it.

Okay, in there. So what we are saying -- basically it's the mark-to-market that is occurring on our hedge positions on the FX and the mark-to-market on the interest rate swaps that we have in place. And you can see, on page four, that, for the year, the unrealized loss, which is really the calculation, the paper calculation that is made that, if we were to settle these things or otherwise get out of them today, then that would be a loss. But clearly, those things are not going to be settled today. It is non-cash. The line below that shows exactly what was realized. And in 2008, we actually realized a true cash gain of C$4.7 million.

So it is your expectation that this non-cash loss will go away in the next four or five years?

Yes, I mean that is going to fluctuate quarter-to-quarter year-to-year depending on where interest rates go and depending on where foreign currency goes.

And if in hindsight if you had not done these foreign exchange contracts and interest rate swaps, would you have been further ahead or behind or what?

The way we look at risk -- we don't enter into foreign exchange contracts or interest rate swaps with a view to beating the market so to speak. We don't do it for speculative purposes. I can use -- a good example would be the interest rate swap that we went into with respect to St. Leon, which is our wind farm in Manitoba and in that instance, it is a sizable investment, we have C$75 million of senior debt that had a floating rate associated with it. And when we entered into that, we said what would a fixed rate look like and so we worked that into the model and by putting in place an interest rate swap, we basically eliminated any interest rate risk over the term of that facility.

So at the end of the day, we have a 10-year facility that has an interest rate of approximately 5.5%. So we look at it as a way to mitigate risk. And yes, in the current market, interest rates are like -- the bank rate is down to like 0.5% now. So yes, the interest rate swaps are out of the money and arguably, if we didn't do the swap, we could be benefiting from that. But similarly, it is not that long ago when interest rates were 8%, 9%, 10% and we wouldn't want to see our returns from our St. Leon wind farm disappear just because of the changing rates of interest. So that is an example of how we manage risk within Algonquin through the use of derivative financial instruments.

Thank you for your explanation.

Mac Whale, Cormark Securities.

Hi, just a quick couple quick follow-ups. Can you just review the timing of the rate case reviews in '09? I am just a little confused on how much -- I think you have rate case reviews in '09 and some in 2010. So if all the '09 ones are successful, how much of the C$10 million in EBITDA will you realize in 2010?

We are just trying to look up the numbers in the MD&A, Mac.

The C$10 million is our estimate of what the revenue impact in 2010 will be. If you look at the table on page 22 of the MD&A, you will see that we have already filed rate cases with a revenue increase request of C$13.5 million and we haven't even done all the rate cases yet. So when we say C$10 million for 2010, that is how much revenue we actually expect to see in 2010.

Okay. So this could come in very back-end weighted because of the fact that some of those rate cases won't be heard until 2010?

Yes, that is probably a good assumption, Mac.

Okay. In terms of -- on the Red Lily, when you look at the CapEx, I am just wondering when was the CapEx -- on what basis is the CapEx made. Is it on estimates that were made some time ago or is it sort of an up-to-date estimate?

It's probably -- the C$65 million guess is based on what we believe it is in fairly recent times. The turbine prices have definitely come down a lot in the last six months and so we have kind of incorporated those into the C$65 million.

Okay. And do you actually have a turbine supply agreement?

No.

Okay. And then on Sanger, on the additional six megawatts, I think you expect to hear on that sometime over the next 12 months. I am wondering will the full impact not be seen until I guess Q1 2010, is that correct?

I think we may here sooner than that. We are in discussions with PG&E on the first six megawatts. I think we may here by Q4 of 2009.

Okay. And then, lastly, just looking at distributable cash, I think was down quarter-over-quarter. But presumably I think there was -- was there an unusual cash expense a year ago?

A year ago, there were positive cash incomes that came into distributable cash.

Okay. So that accounts for most of the decline I think.

That's correct.

Yes, okay. That's all I have. Thank you.

Michael McGowan, BMO Capital Markets.

Hi, just had a quick follow-up question. I think we might have talked about this a little bit in the third quarter, but there is comments in the release talking about establishing a capital structure for the Utilities division. Are you contemplating taking those facilities and capitalizing them as a separate entity within Algonquin or is that something you could look at spinning off a part of in order to raise more capital there?

I guess I would have to answer yes and yes. We are looking at doing it within Algonquin certainly. And whether there is, at some point in the future, an eventual spin out of the Utilities division, that is certainly something that has been discussed, but clearly it is just not on given the markets today.

So in terms of establishing a separate capital structure for that business, if you own 100% of it, presumably it would just be status quo.

Yes, it really -- what will be -- it won't be readily apparent to the public markets because it will be an internal structuring of that capital structure, if you know what I mean. But that is how we want to manage that business.

Okay, thank you.

[Richard Tyson], Private Investor.

Hi, I understand that you've had sort of a BBB rating in the past. Do you anticipate any changes to that?

No, we don't anticipate any changes to that.

Okay, thanks.

(Operator Instructions). Juan Plessis, Canaccord Adams.

Thank you. Just a couple of clarification questions. What was the amount of interest expense capitalized in Q4 and in 2008?

I think you've got a stumper here. Hold on. We have to look that up. About C$700,000.

About C$700,000 for the year or for Q4?

For the year.

Okay. And in Q4 then?

Oh, geez. I am thinking in the year. I will have to get back to you on that.

Okay. Then the other question, there was a comment that the US exchange rate for the year was 1.067. Was that the realized exchange rate including the effect of the hedges?

No, that was the translation of the US to Canadian dollars in the operating income. So as we record our revenues and expenses from the US, that effectively was the average rate over the course of the year.

Okay. Okay. And then there was some text around the regional greenhouse gas initiative costs for Windsor Locks in 2009. I think it was between C$0.35 million and C$0.5 million for the year. Is this net of the C$2 per tonne credit from the state of Connecticut?

Yes, it is an expense for us, yes.

Okay, so it is net then?

Yes.

Okay, thank you.

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

Well, thank you for joining us today and we look forward to talking to you in the next quarter. Thank you.

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