Algonquin Power & Utilities Corp (AQNU) 2011 Q1 法說會逐字稿

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Algonquin Power & Utilities Corp. first-quarter 2011 analysts and investors 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 to you queue up for questions. (Operator Instructions) I would like to remind everyone that this conference call is being recorded today, Friday, May 13, 2011 at 9.00 AM Eastern time. I will now turn the conference over to Mr. Chris Jarratt, Vice Chairman. Please go ahead, sir.

Good morning. My name is Chris Jarratt, and I'd like to welcome you to the 2011 first-quarter results conference call. With me on this call are Ian Robertson, our Chief Executive Officer; David Bronicheski, our Chief Financial Officer; and Kelly Castledine, our Manager of Investor Relations. For your reference, the Q1 financial statements and management's discussion and analysis are available for download on our website at algonquinpowerandutilities.com. I'd like to note that in this call, we will provide information that relates to future events and expected financial positions that 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.

Kelly will provide further details of this at the end of the call. As an agenda for today's call, Ian Robertson will start with a discussion regarding our announcement this morning, along with a couple of highlights from the quarter. Following that, our CFO David Bronicheski will review the financial results, and then Ian will provide some updates on some of our growth strategies and opportunities. At the end of the call, we will host a question-and-answer period. And with that, I will now hand it over to Ian.

Thanks, Chris, and good morning, everyone. And thanks for taking the time to participate in our organization. As you're all likely aware, this morning we announced Liberty Energy's continued commitment to the regulated utility sector with an agreement with Atmos Energy Corporation to acquire their natural gas distribution utility assets, located in Missouri, Illinois, and Iowa. These assets provide regulated utility distribution service to approximately 84,000 customers. The acquisition of these well-maintained, high-quality, utility distribution assets represents continued execution of the growth strategy that we somewhat tongue-in-cheek named Save the Orphans at our Investor Day last fall. But perhaps more importantly, it provides Liberty Energy a great opportunity to accretively expand its regulated utility operations in states that we are already familiar with, to our existing utility businesses.

We look forward to building on the positive regulatory relationships we have already established in these states. The total purchase price for the utilities is approximately $124 million. We expect to acquire net assets, for rate-making purposes, of approximately $112 million -- which represents, in our opinion, an attractive purchase price multiple of 1.106 times. We do expect the acquisition to close in mid-2012, after obtaining the necessary state and federal regulatory approval.

I point out with the longer closing process, which is associated with regulatory assets such as these, compared to the ITP investments made by our APCo subsidiary. The announcements regarding the financing of this utility acquisition should be expected to occur closer to the closing date. I point out that having said that, you can imagine that our recently announced strategic investment agreement with Emera will certainly factor into our approach to securing the necessary equity financing.

Now I'd like to give you a couple of business highlights before I turn things over to David for the Q1 results. In addition to the robust operation of our existing businesses this quarter, we've obviously had a very active start to the year, with a number of exciting announcements in addition to today's news. Firstly, we were very pleased that during the first quarter, our Board of Directors decided to increase the annual dividend paid by APUC, or Algonquin Power & Utilities Corporation, by 8%, to CAD0.26 annually. This increase was delivered in recognition of the successes we've been able to achieve against the value of consolidation objectives established in 2010, and the strength of our growth process. We are confident that our financial results in the news this quarter confirms that decision.

Secondly, as you know, we were pleased to finalize the California electric utility acquisition by Liberty Energy on the 1st of January of this year. Since the commencement of our operational responsibility in California, we are pleased to report that Liberty Energy has been able to continue the reliable and safe service history of NV Energy. We believe that our customer-centric focus is being well received by our California rate payers and regulators.

As a corollary matter, Emera recently agreed to sell its 49.9% direct ownership in the California utility to Liberty Energy. As consideration, Emera will receive 8.2 million Algonquin Power & Utilities Corp. shares in two tranches, with half the shares to be delivered upon ownership transfer following regulatory approval expected this year; and the balance of the shares to be issued following completion of the utility's first rate case, expected to be completed in the latter half of 2012. Liberty Energy is committed to delivering best-in-class customer service and building positive regulatory relationships. We believe that consolidating 100% of the California utility under Liberty Energy will provide us the flexibility and operational control necessary to fully implement this approach to meeting the needs of our customers, our employees, and our regulators.

Thirdly, we have entered into a strategic investment agreement with Emera, which establishes how we as two organizations will work together to pursue specific strategic opportunities. The strategic agreement outlines areas of pursuit, if you will, for each company -- which, for APUC, includes investment opportunities related to unregulated renewable generation, small electric utilities, and gas distribution utilities such as the Atmos acquisition announced today. As an element of the strategic agreement, Emera's allowed comity equity interest in APUC will be increased from 15% to 25%. We will be seeking shareholder approval for this increase at our upcoming annual and special general meeting, scheduled to be held on June 21 of this year.

Our first initiative under the strategic investment agreement was announced two weeks ago, regarding APUC and Emera entering into an agreement to jointly invest in the construction, ownership, and operation of wind energy projects in the northeast US. The Northeast Wind joint venture will own 49% of First Wind's 370-megawatt portfolio of operating wind projects in the Northeast, and an extensive project development pipeline. APUC will own 25% of the Northeast Wind joint venture. APUC and Emera will work with First Wind to grow the operating company and develop other projects in the region. The transaction provides access to a pipeline of northeast US-based development projects, and provides us an effective way to leverage our wind development reach into a new geographic area for us.

Fourthly, on the wind development front, during the quarter we announced that the Ontario Power Authority, or OPA, awarded a contract to our 75-megawatt Amherst Island wind project. The project is estimated to produce approximately 247 gigawatt hours of power annually, due to the planned use of newer, larger-blade, more efficient wind turbine generator technology. We have begun the permitting and other preconstruction work, and will announce capital funding plans for the currently estimated CAD200 million plus project once all this work has been completed. The submission of the renewable energy application is targeted for next summer, with construction to commence shortly following approval of the application. We estimate that the project will take approximately 12 months to construct.

While the recent announcements regarding the Ontario Conservative Party's faltering commitment to new renewable generation in the province were disappointing, we were gratified to hear of their continued commitment to projects which have already received their FIT Contract confirmation, such as Amherst Island. We also announced that the 26-megawatt Red Lily wind project in Saskatchewan commenced commercial operation. While our approximately CAD20 million commitment in Red Lily has been initially structured in the form of senior and subordinated debt, with returns to APUC coming in the form of interest, payments, and other fees, we have the option to formally exchange the debt investment for a 75% equity position in the facility in 2016.

Also during the quarter, we announced an asset purchase agreement to acquire all of the assets in connection with 20 megawatts of wind energy development projects in Saskatchewan. These projects were selected by SaskPower for award of power purchase agreements, in accordance with SaskPower's Green Options Partners Program in May of 2010. The projects will be developed by APCo, and are expected to be completed in late 2013.

Lastly, I'd like to provide a quick update on our important Granite State and EnergyNorth transfer process. After filing our transfer application in February, we have been actively engaged in meeting with the NH -- the New Hampshire Public Utilities Commission staff and the transition planning work. On the approval front, the New Hampshire Public Utilities Commission staff has taken an understandably active role in vetting the capacity of Liberty Energy to responsibly own and operate the important infrastructure assets of Granite State and EnergyNorth. We are committed to developing a relationship based on transparency and trust with the NHPUC. Our agreed-upon procedural schedule confirms a Q4 2011 or very early 2012 closing.

On the transition planning front, significant joint effort between Liberty Energy and National Grid are being expended to ensure a successful transition of operations. Cross-functional area teams from both organizations are meeting regularly to organize the deployment of the human and capital resources necessary to ensure a seamless transition. We are confident that we will be ready to deliver a similarly positive experience to our New Hampshire rate payers to that recently experienced by our new California customers. These successes in the renewable energy and regulated utility sectors reinforce our continued focus on economic longevity, environmental respect, and community engagement. I'd like now to hand things over to David to discuss the Q1 financial results.

Thanks, Ian. And now, a brief review of our Q1 2011 results. Just a note, we use adjusted net earnings to assess the net earnings without the effects of gains or losses on foreign exchange, foreign exchange forward contracts, and interest rate swaps, as we believe these are not reflective of the performance of the underlying business. Our results for the first quarter reflect the results of our growth initiatives that we've been working on now since converting to a growth corporation.

On virtually every financial metric, we have posted impressive, but presumably not surprising, growth. In Q1 2011, our revenue was CAD71.7 million. This compares to CAD48.9 million in Q4 2010 and CAD45.9 million in Q1 a year ago. Our adjusted EBITDA in Q1 2011 was CAD26.9 million, compared to CAD20.7 million in Q4 2010 and CAD18 million in Q1 2010. Net earnings for the year, CAD5 million in Q1 2011, and adjusted net earnings was CAD4.5 million.

Now, some first-quarter highlights from our operating subsidiaries, and I'll begin with the Algonquin Power Company -- or APCo, as we call it. In APCo's renewable energy division, during the first quarter of 2011, net energy sales totaled CAD20.1 million, in line with the same quarter last year; and the division generated electricity equal to approximately 95% of long-term projected average wind and hydrology, as compared to 90% in the same quarter last year. The Maritimes and Quebec regions experienced resources significantly higher than long-term averages, producing approximately 30% and 6% above long-term average resources, respectively. The Western region experienced resources approximately 5% below long-term average, while the Ontario, Manitoba, and New England region experienced resources of approximately 10% below long-term averages. The New York regions experienced results approximately 15% below long-term average resources.

For the first quarter of 2011, operating profit totaled CAD15.2 million, as compared to CAD14.2 million during the same period in 2010. However, overall, the Renewable Energy Division met Management's expectations -- or did not meet Management's expectations, rather, due to a lower wind resource than expected in the Manitoba region. In APCo's Thermal Energy Division, net energy sales revenue for the first quarter of 2011 was CAD6.1 million, as compared to CAD8.1 million during the same period in 2010. The decrease is mainly due to the impact of the shift to the new operating model at the Windsor Locks facility, which started in April 2010 last year.

For the first quarter of 2011, operating profit totaled CAD4.4 million, as compared to CAD3.1 million during the same period a year ago. Overall, the Thermal Energy Division exceeded Management's expectations, due to better than expected earnings at the Windsor Locks facility as a result of improved energy pricing. Looking ahead to the next quarter, APCo's Renewable Division is expected to perform at long-term average resource conditions for hydrology, and based on the trends we are currently seeing, below long-term average wind resources in the second quarter of 2011.

As a result of the capital upgrade completed at the EFW facility last year, the facility is expected to deliver higher throughput with lower operating costs, which should positively affect operating profit generated by the facility for the remainder of the year. The Sanger facility is expected to meet our expectations for the second quarter of 2011, and be in line with our 2010 results.

The Windsor Locks facilities will continue to sell a portion of electricity capacity and all of its steam capacity to the industrial host, with the balance of the electrical capacity available to be sold either into the ISO New England day-ahead market or to industrial customers through the Energy Services Business. The facility did not commit any portion of its remaining capacity to the forward reserve market for the summer of 2011, due to low auction prices. We anticipate that performance during the second quarter of 2011 will be in line with expectations. Ian will briefly describe our planning with respect to a repowering of the facility in a few minutes.

Moving on to Liberty Water, we are pleased to confirm the positive financial results from the finalization of rate cases at Liberty Water and continuing growth in revenues from organic customer growth. In this regard, the wastewater treatment customer base grew by 2%, and the water distribution customer base grew by 2.3% over the same period a year ago. Revenue for the first quarter of 2011 totaled CAD9.9 million, as compared to CAD7.9 million in the same period in 2010. While increases in customers have contributed to increased revenues, water distribution and wastewater treatment revenue increased primarily due to the implementation of the rate increases. For the first quarter of 2011, operating profit totaled $4.5 million, compared to $2.8 million in the same period a year ago.

Overall, Liberty Water's operating profit met our expectations for the quarter. As we look ahead to next quarter, we are expecting continued modest customer growth for the second quarter, as the economy in the southwestern US continues to recover. Revenue increases from rate cases completed in Arizona and Texas are continued to -- are expected to continue to add to additional revenue in Liberty Water in the same -- second quarter of 2011 and for the balance of the year. Liberty Water attributes approximately $1.7 million of the revenue increases in the first quarter of 2011 to the impact of the completed rate cases. Liberty Water received a recommended order from the Bella Vista, Northern Sunrise, and Southern Sunrise utilities, authorizing an annual rate increase of approximately CAD800,000 beginning in April, and this represents about 70% of the requested increase.

Moving on to Liberty Energy. We are reporting the results for Liberty Energy for the first time. Liberty Energy's first electric distribution utility was acquired January 1, 2011, and is located in Lake Tahoe region of California. Our thorough advance preparations for integrating CalPeco resulted in a seamless transition from NV Energy, and the integration of Liberty Energy into Algonquin's operations has gone exceptionally well. Net utility energy sales revenue for the first quarter of 2011 totaled $9.7 million, as compared to nothing, obviously, a year ago. For the first quarter of 2011, operating profit totaled $5.9 million. Overall, Liberty Energy's operating profit exceeded our expectations for the quarter.

I would like to take a moment now to review our credit facility renewal, which was announced earlier in the quarter. In January, we announced that we received commitments with a syndicate of banks for Algonquin Power Co. in the amount of CAD142 million, for a senior secured revolving credit facility, and it carries a three-year term. The renewal of this credit facility is a major element of our capital structure to support our operations and to maintain a strong investment-grade capital structure. Finally, just a brief word on our financial reporting framework, beginning this quarter, we have adopted US GAAP for the purposes of Canadian and US reporting requirements. US GAAP reporting is permitted by Canadian securities laws and the TSX for companies subject to reporting obligation under US securities laws.

One of the major benefits of adopting US GAAP as our accounting framework going forward is that investors will generally see very little difference in our financial reporting, as there are, in the grand scheme of things, relatively few differences between US GAAP and Canadian GAAP as it relates to Algonquin. I'll now hand things back to Ian.

Thanks, David. Before we open the lines for questions, I'd like to give you a quick update on our continuing growth strategies and prospects. I'll start with APCo. Our internal development team is continuing development work on three sites in Saskatchewan, representing a little over 500 megawatts of wind power potential, including Red Lily Phase II; and have responded to Saskatchewan's request for qualifications to procure up to 175 megawatts of additional wind power. These sites have met the qualifications, and APCo is likely to submit project proposals in to future RFPs. In addition to this initiative in the project -- province, we have generally green-lighted the 20-megawatt [More] Saskatchewan wind generation project that is expected to come online in 2013.

At the Windsor Locks facility, we have completed preliminary engineering and environmental permitting work for the installation of a 14-megawatt turbine, one that's more appropriately sized to serve the mill requirements. The total expected capital costs for this project is estimated at approximately $20 million. We expect to be eligible to receive a one-time grant of $6.3 million from the state of Connecticut. One benefit of the new project is that under the state grant, local distribution charges for natural gas used by the new turbine are waived, with an estimate benefit to Windsor Locks of approximately $500,000 a year.

In addition to installing the new gas turbine specifically dedicated to serving the Ahlstrom steam and electrical load, we expect to continue to operate the existing GE Frame 6 base combined-cycle electrical generating equipment in the ISO New England market. In summary, the increased capacity and energy payments under a revised energy services contract with the current steam host, Ahlstrom, will effectively extend the use of life of this facility out to 2027.

Now, over to Liberty Utilities. The business development strategy is to continue to seek attractive regulated utility investment opportunities. With the completion of the CalPeco acquisition in our Liberty Energy business; the progress made on approval and transition planning on our previously announced Granite State and EnergyNorth acquisitions; our three Liberty Water acquisitions; and a natural gas distribution acquisition announced this morning, we expect by the end of 2011, the go-forward percentage of EBITDA generated by regulated utilities will be at least half of our total EBITDA.

For Liberty Energy, we continue to focus on follow-on electric and natural gas distribution utility and transmission-related investment opportunities. As we've discussed, our strategy is to acquire utilities that are located in non-core state jurisdictions, for other utility operators. While the CAD100 million to CAD200 million size of these target acquisition opportunities are generally small for the selling utilities, they are exactly in the sweet spot for Liberty Utilities. And the ability to acquire these businesses at attractive prices provides important accretion to our operations. Acquiring these utilities will allow us to continue to execute on our strategy to generate economies of scale which support best-in-class customer care for all of our utility rate payers.

In conclusion, our primary goal in 2010 was to create the conditions for growth, and focus on creating value for our shareholders. We are pleased to report that we have been successful in this front. We are now delivering to our investors the benefits of these initiatives, and expect 2011 to demonstrate the full-year impact of these activities.

Looking forward, 2011 Liberty Utilities' objectives include completion of the approval and transition planning work in Liberty Energy; prosecution of the transfer approval applications in respect to the Atmos mid-state's utility assets; the closing of the previously announced Liberty Water tuck-in acquisitions; and the continued identification of additional opportunities, which are consistent with the Liberty Utilities growth strategies. Within APCo, our wind development team continues to move its projects forward; and have a new focus in the northeast US, with our recent Emera First Wind transaction.

In summary, we hope that you are pleased, but presumably not surprised, that our financial results demonstrate the impact of the value-creation commitments made in 2010. As to the future, we believe that our pipeline of new value-creation opportunities positioned the organization strongly to allow us to deliver on our continuing total shareholder return proposition of attractive, current dividend yields, augmented with capital appreciation arising through growing dividends, supported by healthy earnings and cash flows. With that, I'd like to open the lines up for questions. So, Operator, if you'd go ahead.

Thank you. (Operator Instructions) Juan Plessis, Canaccord Genuity.

Thank you. And congratulations on today's announcement on the acquisition. I was wondering if you could provide us with a few more metrics. You mentioned the average ROE for the assets is 10%. What equity thickness is this on?

Typically, they've run on a typical 50/50, maybe a little bit thinner than that, Juan, from Atmos' perspective. We have, as you know, when we've acquired the smaller utilities, tend to gone for a little bit thicker equity. I think that's consistent with the risk profile associated with smaller utilities. And so, generally, historically, they have -- they've had slightly thinner than 50/50. In terms of the metrics, I point out that we're stepping into the rate tariffs that really exist today. We're obviously not asking Missouri or Illinois to change the rate tariffs; and hopefully, in the fact sheet that we put on the website, you can kind of back your way into the expected EBITDA. That will obviously continue until we get in for our own rate cases -- at which time, as you point out, the ROEs become more relevant in determining EBITDA, going forward.

Okay. Thanks. And you've seen about a 4% growth in net assets over time. Is this what you would expect, going forward?

Well, we -- there's -- I don't think it's reasonable to surmise that you're not going to see the type of growth we've seen in Arizona; but it has been healthy, as you point out. I don't think those are crazy numbers, as you look at the service territories, the opportunity to penetrate natural gas service into areas that currently don't have it. When we looked at the service territory during our due diligence, we were pleased at the general economic robustness of the areas that are being served. And so, I -- over the short to medium term, I think those are reasonable estimates going forward, Juan.

Okay, thanks. Now, you have a real full portfolio of growth initiatives on your plate with today's announcement, as well as acquisitions of another 50% of CalPeco, Granite State, EnergyNorth, your Northeast Wind investment development of Amherst, [Morris] Quebec wind project. So, the first question is in respect to your targeted 5% EPS growth. That seems a bit low, given what you've announced in recent months. Is 5% reflective of what you expect over the next couple of years, or is this the number that looks out a bit further? And secondly, do you think Management is starting to stretch itself a little thin with all that you have in front of you? And might that limit Management's capacity to seek out further growth opportunities?

Well, let me start with the question with respect to EPS. I think it is important to under-promise and over-deliver. I think we didn't want to go into the 2010 growth -- our value consolidation initiatives by setting the bar at a point where it might be difficult for us to achieve. But I think if your comment is, my gosh, with all of the initiatives you have in front of you and the apparent accretion that comes from them, you guys are going to exceed, certainly in the short term, a 5% growth rate, I think I probably agree with you. I -- what I don't think we want to do is be out there, as I said, changing the promise bar.

With respect to your comment about Management's capacity, I think it is important to note that this organization very much is divided into two quite separately managed business units. Our APCo subsidiary and Liberty Utilities have very separate leadership, very separate business development, very separate transition planning groups with respect to a number of the initiatives that you mentioned for our wind development, including the First Wind -- those are all managed by a dedicated APCo business development team, led by Jeff Norman, our VP of Development.

I would point out that, with respect to First Wind, one of the most attractive aspects of the First Wind is that, here's an opportunity for to us lever our reach by taking advantage of First Wind's development team and being able to make investments in attractive projects without, in fact, if you will, burdening our existing organization. So, we see that as a strategy to actually extend our reach, without bringing up the issue that you raised of Management's business.

On the utility side, we have staffed up appropriately to manage the transition process in Granite State and EnergyNorth. With respect to these new acquisitions that we talked about, I think you'll hopefully note that the timing is such that these are layered, if you will, and staggered from a transition-planning perspective, that the team that are currently dedicated to Granite State and EnergyNorth can shift their focus over to the Atmos assets as the transition work for EnergyNorth and Granite State comes to a close, and that with -- lastly, I just mention with respect to the acquisition of the other 50% of CalPeco -- heck, that's an opportunity we obviously know well and have been operating and are pleased, if you will, just to add that economic -- additional economic exposure -- and actually don't see that as taxing.

I think just in summary, Juan, this is an organization that has promised to our shareholders that we will deliver a fair portion of the return proposition through growth in dividends, but that can only be supported by growth in earnings and cash flows. We've chosen this path. I think the organization is well staffed and capable of meeting the challenges. I don't know if that answers your question, Juan.

No, that's very good. Thank you very much.

Thanks, Juan.

Nelson Ng, RBC Capital Markets.

Congratulations on the transaction.

Thanks, Nelson.

Just a question on the natural gas acquisition. I presume that the fuel price -- or the cost of fuel is a straight pass-through to the customers?

That's correct.

So, how frequently do you update the price of the gas that you charge customers? Is it every quarter, or semi-annual?

It's basically aggregated over the entire year. There's an annual planning process. It's different for different states, but there's an annual planning process where you establish what your expected cost of gas is. You track what your actual cost of gas is, to the extent that you are over- or under-collecting. You include carrying costs of not over- and under-collection. It's really done, if you will, realtime, Nelson.

Okay. So, is there any kind of -- does that include any kind of weather normalization adjustments?

Well, it's different from different states. These states are very supportive of decoupling, if you will, so that the revenues that a utility earns should be generally decoupled from actual volumes, which is effectively a weather normalization. And so, the short answer is, yes. I think that's important, given that we're not taking price risk on the commodity, it's only appropriate that we not take volume risk as well.

Okay. So, just in terms of the EBITDA, is it seasonal, in terms of being much stronger during the winter?

Oh, yes. I think that's -- certainly is -- for sure, that it is, obviously, driven by volumes. There is, obviously, base charges that get charged every month, which provide a portion of the EBITDA. But to the extent that there is a portion that's tied to volumetrically -- to volumes, that it's obviously adjusted for monthly use.

I see. How much of the EBITDA would you expect to see during the winter, as a percent?

Well, as a percentage, the winter months, your big months, is probably -- over that six-month period, probably is not unreasonable to expect 60% or 70%, maybe even 75%.

I see. Okay. And then, just jumping onto CalPeco, in terms of the rate base, it was a little bit higher than I expected. So, I think you indicate that the rate base is about $134 million. Is there a reason for that rate base being slightly higher than what I thought?

Well, the only -- I guess I'm not sure exactly what your expectations were. Obviously, when we announced the transaction back in 2009, we gave some guidance as to where the rate base in the utility stood going forward -- or stood at that time. Going forward, NV Energy continued to make investments in capital, and that's great. We are obviously happy that they continued to invest in the utility. With respect to the rate base and, David, I wonder if you -- ?

The actual rate base, there's a distinction between assets per rate for regulatory purposes, which would include basically all of the assets of the utility, for all intents and purposes, versus the actual rate base that the regulator will be looking at for earning of return on and a return of. That portion, as far as the sure rate base goes, is closer to the $117 million mark, whereas still in the process of finalizing the final purchase price with NV Energy. And we'll have that obviously wrapped up in Q2. The balance, obviously there's a portion of it that is the premium above rate base. And then, there's also working capital adjustments. And it's all of those things together which add up to the total purchase price that we had at January 1.

I see. So, it's roughly -- currently, it's about $117 in terms of the value for rate base -- rate case-making purposes?

That's correct. There's about $9 million. Our notes to the financial statements do give an initial breakdown of the purchase price. And there, you can see kind of where it's at, as far as the breakdown. We have about $9 million working capital. There was a $10 million premium paid for the assets acquired. And then, there's regulatory liabilities and other liabilities that were acquired on the transaction, as well.

Okay. And then, just one last question on CalPeco. So, the EBITDA on Q1, is that representative of a run rate? Or again, is there more seasonality, given that it's in Lake Tahoe?

Yes, in Lake Tahoe, you can imagine, it actually is a winter peaker, with all of the ski hills in operation. So, certainly, it was nice that we closed the transaction at the end of December. So, we're sort of coming in in the middle of the winter peak. So, we did get the benefit of a bit of an uptick in the EBITDA, as a result of seasonality.

Okay. Great. Those are all my questions.

Tony Courtright, Scotia Capital.

Thanks very much. I guess it's a little similar with the recent -- or, the announcement this morning of Liberty Electric's acquisition in the Midwest. Rate base versus assets for -- because when one looks at Atmos' release on the -- perspective on the same transaction, they referenced property, plant, and equipment being sold of $112 million, but a rate base of $98 million, and then a rate base excluding SSU, which I'm not clear, of $91 million. Can you give some clarity here? How -- do you expect the differences to migrate into an ROE rate base over time? Is that what you are anticipating and planning?

Tony, I think the major issue that needs to be considered in the difference between perhaps the way Atmos is looking at it and the way it's looking at it from -- I mean, the way it's being looked at from our perspective relates to the fact that we're undertaking this on an asset-based transaction. Obviously -- and attendant to that are a whole pile of adjustments that exist in rate base, with respect to the corporate owner. And the primary one is accumulated deferred income taxes; so that we'll be buying the assets from Atmos, who have on their books certain accumulated and deferred income taxes arising from the timing differences through MACRS depreciation and GAAP book depreciation.

But nobody's settling up, if you will, that outstanding obligation to the IRS as a result of the sale of these assets to us at $112 million. And so, consequently, when they settle up that bill, they'll have reconciled their regulatory obligation that was created -- the taxpayers, in effect, lent them money, and they paid it back by paying their taxes. And so, we would expect -- and this is similar to CalPeco, that when those assets transfer onto our books and we set up a brand-new utility, Liberty Energy Midstates Corp., it will have assets for rate-making purposes equal to the $112 million versus the $98 million -- with the primary difference is -- difference being accumulated deferred income taxes, which would go away as a result of the transaction, because Atmos will pay their bill to the IRS.

So, having said that, will the local, state regulators, I guess, agree with this treatment? Are you writing up the assets? You're not writing it up to the purchase price of $124 million, you're only getting it to the $112 million. Is that -- ?

Absolutely. We have never sought the purchase price adjustment, if you will, above the net regulatory book value of those assets. That's just not -- we just think that's inappropriate; and so, we would carry that difference, if you will, on our books as goodwill going forward. But those assets that we're acquiring have a regulatory book value of $112 million, and that's what we'll be putting them on our books for. It's really just the way the accounting treatment works, for the fact that there is a timing difference between MACRS and GAAP depreciation. But it would get sorted out as a result of the transaction. I don't think there's any harm or foul as a result of it. It certainly was the way it worked in California, but I think it's really just an execution on it -- execution on the normal transaction accounting.

Okay. In terms of the EBITDA margin indicated of about 50%, isn't -- do you consider that low?

Well --

I don't have -- I look at some US utilities, some Canadian utilities, and they have much higher EBITDA margins.

I think really what we were trying to give people an opportunity was to kind of back their way into a revenue net of gas costs, so that people could back their way into an operating cost level. We've obviously tried to give guidance as to what the -- under the current act, following the 2010 rate case in Missouri, tried to give some guidance as to what the expected EBITDA of these utilities are. Really, that EBITDA margin was really just an opportunity for individuals such as yourself to kind of back in to get an estimate of -- what are the annual operating costs, going forward?

All right In terms of buying assets and then offering employees continued employment, how does that transition -- you have unionized workers, presumably they have, perhaps, defined benefits pension plans and so on. Are there unfunded liabilities? Are you assuming all of the contracts or arrangements -- similar arrangements with the collective bargaining that previously existed with Atmos?

The issues that you raise, Tony, are the absolute nitty-gritty details of every one of the transactions we take over -- that we undertake. It is generally our philosophy that employees -- this should be seamless to employees. And that means seamless in terms of assuming their union contracts, and so work rules and wages stay the same. It speaks to providing them similar benefits, and that's obviously what our intention is. I'd point out that, generally, all those costs are baked into rates. And so, I think it's only appropriate that we continue that.

With respect to pensions, it differs in different -- for different transactions. In the case of CalPeco, we set up our own separate brand new cash balance pension plan for the California employees that we hired, and basically offered a continuation of that. In this case, specifically with respect to Atmos, they do have a defined benefit pension plan. We will be spinning those planned assets off, if you will. We will end up actually with a fully funded pension plan for the relatively small portion of the employee -- the Atmos employees, who will be transferring over to us. As you know, I think we're only taking a little over 100.

But the pension plan, the transfer agreements that we entered into with Atmos basically have that pension plan coming over to us in a fully funded state. So, I think we'll be starting things off in a good place; but then, going forward, we obviously have the attendant issues associated with providing employees a defined benefit pension plan. The good news is, the regulator is used to managing and dealing with the costs associated with their [WIP]. And so, I think we're comfortable that we can meet that proposition of a seamless transfer of employees, without unduly burdening rate payers.

Great. And just one final question. Switching to Windsor Locks, you say you are proposing to substitute a smaller engine to satisfy the needs of the thermal and power requirements of Ahlstrom or whoever the counterparty is. How -- are you negotiating extension to the current energy sales agreement with them, to meet the useful life of that new asset?

Absolutely. In fact, I'd actually argue that that's kind of the fundamental obligation here, from our perspective, Tony, is you can appreciate that large [Frame 6] turbine made total sense when you had a long-term contract with CL&P to offtake all of the balance of the energy. But when -- during those times when the market is not supportive of operating that Frame 6, we found ourselves either having to operate and lose money, or otherwise negatively arbitrage. The smaller turbine would run basically full out to serve the needs of Ahlstrom. But attendant with this is an extension to 2027 from 2017 of the energy services agreement.

So, really, it's about extending the life for another decade beyond 2017; but perhaps most importantly, de-risking the overall proposition, because it takes the Frame 6 out of the equation, in terms of servicing the needs of Ahlstrom, and allows that Frame 6 to participate if, as in when, the market conditions support it in the New England ISO. And so, really, it's about decoupling, if you will. But with the extension for the life, an absolute fundamental aspect of it.

Okay, great. Thanks.

Thanks, Tony.

John Safrance, M Partners.

Just a quick accounting question -- will it be -- how do you plan to treat the C-93 Cap Ex? Will that be expensed or capitalized?

It will be capitalized. There's portions of it that demand [up] being expensed. But I think for all intents and purposes, if you're modeling, that it would be appropriate to treat it as capital.

Okay, thank you. And just in your thermal business, I notice that sequentially tons are down that have been processed. Is this Q1's tons fairly indicative, go-forward, or would you expect that to jump up a little bit?

You are referring to the waste process at our EFW facility?

Yes.

Well, we processed 41,375 tons in Q1. Clearly, that's well above what was done a year ago. Because for the most part, the facility was down for, I'll say, 10 of the 12 weeks a year ago. So, I'm not sure necessarily where you're getting your numbers that the tons processed this quarter are down.

Sorry. I thought I had you doing it sequentially quarter over quarter down, but maybe I just looked at the wrong number. But I guess the question still stands. Would this be fairly indicative, go-forward, in terms of -- ?

Yes, yes. Absolutely.

Okay. And the 42 megawatts of wind that you have awaiting the economic connection test, do you have any sense, if the Conservative Party wins the next provincial election, what happens to some of these projects that are in that pseudo-limbo, go-forward? Would they still be protected, just as some of the already awarded FIT projects would? Or do you think these would perhaps be canceled outright?

Well, John, I guess my guess is as good as yours. I think the announcement that -- from Hudak should have -- I don't think augurs well for anything that can reasonably be canceled, and the projects that are sitting in that kind of connection queue. They would be, in my mind, the most obvious targets to take a bullet. We could be pleasantly surprised, there's a lot of water that needs to flow under that bridge before we get there. But as I mentioned in my prepared remarks, I think we are pleased that Amherst Island got through and actually got the FIT contract today. But I think, as I said, I think the future is uncertain for anything that hasn't reached that status before the Conservatives got in, if they did.

Okay. Thanks for that. And a question just on your utility business. What, typically, from a rate-based perspective, are the depreciation rates? And are they fairly uniform from state to state, or do they differ?

Well, typically, the depreciation is done on a useful life basis for the asset; componentization, pipes, would have a long life, whereas you can imagine electrical poles, being wood, have a shorter life. In the assets -- in particular, if you think you're making reference to our Atmos transaction, they are generally pipes in the ground, which tend to have a longer life. It's a relatively new system, that most of it is plastic, which obviously has much longer longevity than either cast iron or [bare] steel. Typical depreciation remaining life in these assets, specifically, it's probably going to be between 20 and 30 years, if you wanted to work your way back into an annual depreciation number.

We, as part of every rate case, file a whole depreciation study where we do look at the various classes of assets and look at their average lives and work our way through. But they tend to be quite long, because as you can imagine, the assets that we're using are very long-lived -- pipe and poles and wires and that sort of stuff. So, depreciation lives in the 25 to 45 years are not unreasonable for brand-new assets as they go in.

Okay. Thank you. And I went back, just for posterity's sake, and looked at your CalPeco fact sheet when you first announced the acquisition. And at that time, the financial metrics that were provided on that appeared as though they did not incorporate, at least on the revenue side, the majority of the pass-through costs. And it looks like now you are consolidating that into the revenue line. Is that indicative of what you'll be doing across the board, as you consolidate and execute further on the closings?

Yes. What we presented on the fact sheet, we didn't want people to get hung up on the energy cost, which effectively our pass-through. It appears in the revenue and it appears in the expenses. And so, we just treated it as a net number. But you are correct -- in our Q1 numbers that we just reported, we are consolidating CalPeco. So, we are putting 100% of that utility onto our balance sheet and putting 100% onto our income statement. We have a carve-out for minority interests, representing Emera's portion of it. And then, within that, obviously, the revenues do contain the energy pass-through. And so, in connection with that, I'd guide you to our MD&A, where on page 18 we do provide the split-out of the energy costs. So, you get to see exactly what the cost of the fuel is, and therefore, the revenue on both a gross and a net basis.

Okay. Great, thanks. And I just have one last question -- and it's probably a really dumb one, so don't laugh at me. But with the flooding in Manitoba, does that at all affect St-Leon?

It's Chris Jarratt talking. No, it doesn't. Fortunately, the St-Leon project is up on a bluff, which is kind of why it's windy up there. So, it's fortunately -- it is not in harm's way.

Okay, great. That's all for me. Thanks, guys.

Matt Gowing, Mackie Research.

You mentioned that CalPeco's seasonality was about 70% to 75% in the winter months. Wondering if you can make a similar sort of guidance for the Atmos acquisitions announced today?

Sorry, Matt -- if I said that, I misspoke. The CalPeco acquisition isn't as nearly heavily weighted toward the winter as that. I was speaking, actually, of the Atmos acquisition. Obviously, natural gas has -- being a primary fuel -- a heat fuel, is primarily driven in the winter months. CalPeco, while, as David points out, is a winter-peaking utility -- which is, I don't say, unusual. But obviously, something like LA would obviously have a summer-peaking utility, given the air conditioning load. We have a winter peaking, but it isn't nearly as much. It's probably more like, let's call it, 55%/45%, or something like that. It's not nearly as heavily weighted as a natural gas utility.

Thanks. And historically, what have the annual gas commodity costs been for the Atmos assets?

I think the total revenue for those assets is in the CAD80 million range, and so you back your way into the portion of that which is natural gas. Again, as Nelson had asked, these are generally a pass-through to us. We're really -- I don't want to say indifferent, because we obviously strive to ensure that the total bills to our customers are both reasonable and affordable. But from an economic proposition perspective, it really is very much -- it's intended very much to be a pass-through.

Thanks. And do you have any view as to what Atmos' motivations were for selling these assets? It looks like they're consolidating their operations down to nine states from 12. Do you have any more color on that, Ian?

Yes, we -- I met with Bob Best, the Chairman of Atmos, and we had a conversation about what their strategy was. I think Atmos is probably an organization that has preceded Algonquin, in terms of its ability of its growth profile. It's obviously grown to a very large organization right now. And I think as they think about their business going forward and their strategies, it is about consolidation. And I think that is the underlying thesis to our Save the Orphans strategy -- an opportunity for Algonquin, which is attractive in terms of its accretion. It's a much smaller opportunity than one that might work for Atmos. And so, it really is, as you said, it is about consolidation for them. For us, it's about leveraging operations we already have in the state of Missouri, building a strategically sized footprint for an organization of our size. And so, I think it's all great. I think what works for them also works for us. And isn't that the wonder of it?

Great. And then, going back to the EnergyNorth and Granite State transactions, the motivation for those deals were some follow-on either in-scope acquisitions or project development work behind that. Can we read through some sort of similar opportunities for the Atmos deal?

We very much look at trying to lever, if you will, the monopoly utility footprint that each one of our utilities gives us, to generate opportunities for either investments in rate based in that utility, for roll-up acquisitions of additional utilities, or as you point out, the opportunity to ply our trade as an IPP developer. I think CalPeco is a perfect example of getting our foot, if you will, in the door and being able to lever that knowledge to participate in the California IPP space. So, yes to your question. We very much look at the acquisition in the mid-states as giving us a beachhead in an area that, while we already had some utility operations, we'll have much more substantial offices and operations to be able to participate in all of the energy and utility landscape of that area. So, yes to your question, Matt.

Great. Thanks. I'll get back into the queue.

Thanks, Matt.

Wojtek Nowak, Fraser Mackenzie.

First question is on CalPeco. You mentioned in your MD&A that the operating profit there exceeded your expectations in Q1, and is expected to do so in Q2. Can you give us some color on why that is?

I think the electricity demand in Q1 certainly was what was higher than what we expected; and the energy mix, what was higher; and our customer account was all slightly higher. So, for all of those reasons, we enjoyed a better EBITDA in Q1 than we expected. And you know, some of that trend obviously -- particularly with respect to the customer count, is expected to continue into Q2.

Okay, that's great. And just lastly, further to a previous question on Management's bandwidth to handle all of the activities that are going on right now. It's one thing to close on acquisitions, and it's another thing to deliver on the expected earnings improvement through rate increases and service investments that you talked about. How will those capabilities be addressed, and will you need to bulk up your internal resources to address those?

Wojtek, it's Ian. I think this organization is -- you can't make the statement that we're going to grow without an acknowledgement that the resources have to be increased. I think the nice thing on the utilities side is that it's a cost of service model, so that the costs to providing all of those services are recoverable. The organization has already bulked up, if you will, to effect the transition work that David mentioned in his prepared remarks, with respect to CalPeco. That team has turned its attention to Granite State and EnergyNorth; and they have their next task in hand, which is the Atmos acquisition when they're done with Granite State and EnergyNorth. The team has bulked up.

We'll continue to look at the resources, and add them as necessary to ensure that we do meet the expectations of our regulators going forward. I think we're pleased right now that -- and cautiously optimistic that we have the resources in our organization to make good on those propositions. But to be frank, if we need more, we'll get more. On the APCo side, to be frank, managing a number of development projects is a little bit like pushing six or seven peanuts down the table. You push a little bit on one, and while the other ones are sitting, you move over and push them a little bit at a time.

And so, our development team, which consists of seven full-time individuals, are able to focus our efforts, at times where projects need focused. And other times projects get a little bit on auto-pilot. So, I think we're confident that on both the utilities and the power side, we have the staff on the ground, but we are always mindful -- I think Juan's comments right from the very beginning are something that certainly are front of our mind -- we will not be making a misstep on our growth strategy due to lack of resources.

Okay, that's great. Thank you. And just lastly, can you give us an update on your CapEx forecast for the year?

Yes, absolutely. We do provide additional guidance on that on page 22 in our MD&A. But I can say that what we're looking at this year is going to be capital in the neighborhood of about CAD25 million. There's certainly an expectation of about CAD22 million of solid capital expenditures that we are expecting, and then we obviously hold a bit of a contingency in our capital plans for additional capital that may be required as the year unfolds. So, I would guide you to our MD&A on page 22, where we do provide a little more detail on that.

Okay, that's great. Thanks. That's it for me.

Michael McGowan, BMO Capital Markets.

Just have a question, I think it was asked earlier, between the difference between the regulatory assets for rate-making purposes and rate base on Atmos' -- their fact sheet that they published, as well. I certainly understand your argument with respect to deferred taxes and how you need to clean that up for your own books. But from the regulators' perspective, they're allowing a return on the $98 million. So, is that the amount we should actually think about when we're looking at the regulated returns and the earnings power of this utility for the next couple of years?

No. Actually, I think quite the opposite, Mike, is that just like in California, if you think of ADIT, the reason it is a grind to rate base -- and let's -- rate base is obviously what's approved by the commission. It's a grind to rate base because of the timing differential between MACRS and GAAP depreciation. Effectively, the rate-making process allows, if you will, a loan being made by the rate payers to the utility. The rate payers are paying for taxes that the utility doesn't actually have to pay; because under MACRS, the tax depreciation rates are faster.

At the time of a transaction where those assets are then sold, there is a reconciliation with the IRS, and the utility who's selling those assets needs to repay that loan. But from the rate payer's perspective, that loan was advanced, it's now been repaid. As in California, the assets now go on our books at their net regulatory book values, and we would expect to earn fully on that. We will be starting our own ADIT account, if you will, going forward.

And if you look at the difference between MACRS and GAAP depreciation, we'll probably get ourselves back to a not too indistinguishable position, from an ADIT perspective, within three to five years, given the front-end loading of MACRS. And so -- but no, we fully expect that if we magically did a rate case on closing, in the case of the Atmos transaction, that we would have assets for rate-making purposes upon which we would earn of $112 million.

Would that require a rate increase?

It certainly would, because from what has happened is that the utility payback is loaned, if you will, to the IRS. It had to, in effect, pay that loan back; and so, therefore, you would reverse that ADIT. It's frankly no different, if you will, than the ADIT reversing over time. As you know, ADIT is a timing difference, anyway. And so, over time, the ADIT would reverse itself, which would basically have rate implications itself. It just happens obviously much faster when it -- when the reconciliation happens in the context of a transaction.

I think the net effect, though, and this is from your perspective, the net effect is that given that we won't be getting in for a rate case on these assets for a couple of years, I think the effect gets pretty muted when you start to look at -- what will our ADIT actually be when we go in for a rate case when we get in there? But our starting position, and it's from our perspective, and I think it's supported by both regulatory precedent and GAAP, is that we should have $112 million, as I said. Practically, though, we'll be building our own ADIT balance pretty darn quickly, because of the front-end loaded of MACRS.

Okay. Just a question, even with the $112 million, if you assume that balance, you're still paying a bit of a premium. Is there any large capital plan or plan investment in this utility? And how do you intend to grow into that premium?

I think as Juan had pointed out, in our fact sheet they showed about a 4% net gross -- net of regulatory depreciation [that lasted] three or four years. I think it's not a super high-growth area, but I think we are confident that as you continue to grow this business, going forward, that you, if you will, dollar average yourself down out of the premium. I think it is important to point out, and it's definitely square in the wheelhouse of our strategy, that you can't pay a huge premium for assets that don't have that ability to dollar average down quickly.

And I think the relatively modest premiums are reflective of the fact that there is ongoing but somewhat modest growth. So, I think it is commensurate with the growth. I think we will dollar average our way down. So, I think all in all, we felt that the deal was fair in the context.

Okay. And if I could just ask a procedural question about CalPeco and the transfer from Emera -- the 50% that you currently don't own. They're going to -- you're going to pay them in two tranches, through share consideration. Now, when we take a look at this, are you initially going to own approximately 75% of it when you receive regulatory approval, and then when the rate case has been completed, then the remaining 25% of the utility will be transferred, so we'll still see some minority interest throughout the next year or so?

No, no. It's -- think of it as just payment terms, Mike -- that on regulatory approval, the entire 49.99% will be transferred to Algonquin. But we'll still, if you will, owe them something going forward. And the reason that makes sense is we tried to match, if you will, the earnings profile from what Emera would otherwise have seen had they maintained their 49.99% interest, they would have worn that profile going forward. And so, they'll now see it through Algonquin. But really, think of it as payment terms. We will not have a minority interest upon the transfer which will occur after regulatory approval, although we will only have paid about half the purchase price.

Good deal for you guys. Thanks. Those were my questions.

James Morrison, Comark Securities.

I'll try to be brief here, but you moved really aggressively so far on your acquisition strategy. Do you expect to continue kind of at somewhat at this pace, or do you expect to take a breather here while you try to get all these things closed and ramp up for preparing to integrate all these businesses?

You know, look, you have to be opportunistic from an acquisition point of view, James. I think that you appreciate we're not in total control of this. And I think we are pleased that we at least, so far, have been able to introduce the concept of staggering these, with respect to Granite State EnergyNorth. I think we are mindful of the comments that people have made with respect to capacity of Management going forward. I think we think about these things where, at some point in time, you may well have to say, our machine is full right now. I don't think we're at that stage, but we are mindful of it.

I would point out -- and I think this is just an important observation with respect to utility acquisition, is they do have a long fuse. You think of CalPeco. We made the announcement back in April of 2009; and gosh, it didn't close until the end of 2010, almost an 18 -- well, more than an 18-month process. I think it's about building a pipeline of committed opportunities; it's about ensuring that the transition teams that we have in place have their work cut out for them, going forward. But we are mindful of the comments that people raise. As I said, I think we are cautiously comfortable that we have the resources in place, but we think about it.

Okay. And that's a good segueway into the timing of -- your expected timing of regulatory approval for the Atmos acquisition. And maybe you already answered it, but I didn't hear it.

Sure. I think mid-2012 is probably not an unrealistic expectation. We are dealing with more than one regulatory jurisdiction in the acquisition, and that obviously complicates matters. We'll be taking our time over the next 60 or so days preparing those applications. So, I think we're confident that this will fit lockstep well with the Granite State acquisition, which will hopefully be coming to a close from a regulatory approval process in Q4. And so, that in the early part of 2012, that things will obviously be in high gear there. So, mid-2012 is kind of where our target thinking is, James.

And is it reasonable to think that it could possibly get pushed out of 2012 entirely?

No. I think that would be -- we would be very disappointed if that was the case.

Okay. And then, finally, just how much are you planning to apply for, in terms of a rate case at Liberty Energy in August?

It's -- look, we're obviously -- we're still going through all of the analysis right now. But look, nothing has come to our attention that would make the general commitment that we made to the regulator, that our operating costs were not materially different than those that were incurred by NV Energy before our watch. Keep in mind that this represents the aggregation of three years' worth of inflation and other impact on operating costs; and so, there -- we are totally confident there's no rate shock coming, if you will.

Yes.

But I think it's going to be generally in line with the type of rate increases that NV Energy has historically sought in the utility. Obviously, I don't want to bind ourselves in from a regulatory perspective, but I think we are comfortable that there is no rate shock coming as a result of this transaction. I think that's pretty fundamental.

Okay, that's good. Those are my questions. So, thanks, guys. Thanks, James.

Ian Tharp, CIBC World Markets.

Thanks for taking my questions, and congrats on a flurry of activity here in Q1.

Thank you.

So, we've covered a lot of ground already. Just a couple of things on the Midwest Atmos assets. First of all, you talk about the growth rate that you've seen in the past -- and Ian, I think you referenced a four-year period for that growth rate of 4.3%. What has been the more recent experience, I guess, 2009, 2010, in terms of growth? Is it the lesser part of that to have that average?

No, actually, I think we gave in the little fact sheet there, Ian, gave kind of 2008, 2009, and 2010, if my memory serves me correctly. You can run the math for yourself, but I think it wasn't materially distinguishable from that 4% range. I think they've done okay in those past years. I mean, I think one of the nice things about these utilities is there is ongoing opportunities to invest capital, particularly for replacements, systems that originally had a lot of cast iron and [bare] steel, that kind of irrespective of economic conditions, there is an opportunity, perhaps you might say an obligation, to continue that revitalization program. And so, I think they have not fallen off the cliff , if you will, from a growth perspective, if that's where your question's headed.

Yes, I just wanted to get some color on recent experience, but it sounds pretty positive.

Yes, it's been pretty good.

Yes, okay. And obviously, Missouri is the bulk of the connections and assets, and it looks like perhaps Missouri's had a recent rate case cycle. Are there expectations on rate cases in the other jurisdictions in the near term, or what are your expectations on rate cases for those other areas?

Look, they are all pretty healthy earning utilities. You can back your way in, just based on EBITDA. I think the only utility -- and if this had stayed in Atmos' portfolio, they had advised us that they had a rate case plan for Illinois. We'll obviously have to take a look at this in the context of our operating costs, to see if that's something that makes sense for us. I think Iowa is probably pretty healthy earner right now, so nothing really on the horizon there. But again, there's no rate shock coming as a result of this transaction. As we've looked at our operating costs internally against those that are embedded in current rates, I think we're totally comfortable we can continue to operate the utilities largely in line with those -- or materially in line with those. So, the only one, Ian, might be Illinois; but again, nothing earth-shattering.

Okay. And we talked a lot about capacity for handling growth, et cetera. You're at eight states in the US now across your utilities businesses. Is there a thought now that perhaps you'd fortify around some of the beachhead markets that you've created a presence in? Or would there be more expansion into new states? You've taken on new states on both the water and energy sides now recently. So, any thoughts around that?

Yes, I think -- look, we obviously like the concept of -- economies of scale, to be frank, is one of the drivers for the Atmos transaction. As you know, we had Liberty Water operations in Missouri and Illinois, and it'll be now nice to have some size and scale behind them. So look, we recognize the benefit of that scale, I think, as we have looked at our -- in particular, continuing execution on our Save the Orphans strategy. Looking for opportunities that are -- perhaps in New England, maybe they're not in New Hampshire, but that somehow we can capitalize on the work that's being done in Granite State EnergyNorth. That could certainly be a focus, as we think about our operations in the southern US, California.

Look, we do appreciate the concept of scale. I think on the other hand, it is important to keep in mind that these are not inconsequential operations unto themselves. And the fact that they may be but a rounding error on the balance sheet on somebody as substantial as Atmos or National Grid, they are significant to us. They are strategic. And so, we are comfortable that California, as an example, particularly owning 100% of it, is a very healthy, standalone operation that is appropriately staffed. And we're comfortable that we can continue to do this for a while. Obviously, when we're a $9 billion Company, maybe we'll have to look at it, too. But we have a little bit of road between here and there.

You're making good progress. Then finally, one -- just one point I perhaps have missed, in terms of timing on Windsor Locks, sounds like that activity will be quite active this year. But what's your expectation on completion?

Oh, it's very specific. That -- the grant that we have, that $6 million grant, really looks to a Q2 2012 commissioning. So, we're into it now, and we'll be actively pursuing it over the next 12 months. So, timing -- think of it as a here and now.

Okay, great. And then, the grant, is it similar to the federal grant, where at 60 days post-COD that you get essentially a check in the mail?

That's my understanding.

Okay, good. Those are all my questions. Thank you.

Thanks much.

Rick [Van Stone], private investor.

Many significant activities underway, and there have been a few questions around the Management capacity to handle that -- not so much on the future financial capacity to handle. But my specific interest is, I want to get a little more granular around Amherst Island. Overall, it seems like it's a relatively small potatoes project at a CAD230 million cost, relative to everything else you're up to. Have you made a final decision to proceed with that project at this time?

You know, I think we're -- a final decision would be made when turbine orders have been placed and construction work would begin, I think. But before we've actually made that commitment, the answer is no. Final decisions haven't been made. I think we're obviously want to be sensitive to all of the issues associated with wind development, both here in Ontario and elsewhere, in North America. So, the short answer to your question is, no, no final decision's been made. But we are working our way through that permitting and consultation process, trying to understand -- what are the issues, how can we best mitigate them and address them?

You also mentioned somewhere through that the predictability of wind power's a little higher-risk than some of the other activities you're in. How have your preliminary wind analysis tests come from Amherst? What do they look like?

We've collected wind data from Amherst for a number of years. Ontario wasn't blessed with great wind resources, in general. But I think with -- with the location of Amherst Island, it's a pretty good wind resource. I think that, coupled with the ability to use some of the newer technology turbines, the larger sweep -- windswept area turbines, the project can be attractive from an energy production perspective.

Have you negotiated a price with the province for that permit?

Well, when you say for the permit, we do have a power purchase agreement under the FIT contract; and so, that price is stipulated. It's --

Okay.

It's a statutory rate. So, it's not really up for much for negotiation, while we might like to.

Okay. Those are my questions. Thanks, gentlemen.

Thanks for your interest.

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

Thank you very much for your time today. I -- we obviously are thrilled that we are delivering on what we've hopefully said we're going to do. And with that, I wish you all a good morning and weekend.

Certain written and oral statements contained in this call are forward-looking within the meaning of certain securities laws, and reflect the views of Algonquin Power & Utilities Corp. 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 climates 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 dividends to shareholders. 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 uncertainties.

We caution 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 those presented in the Company's most recent annual financial results, the annual information form, and most recent quarterly Management's discussion and analysis. 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 does not intend to update or revise any forward-looking statements, whether as a result of new information, future developments, or otherwise.

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