Hello, this is the chorus conference call operator. Welcome to the Brookfield Renewable Energy Partners' Fourth Quarter and Year-End Conference Call and Webcast. [Operator Instructions] And the conference is being recorded. [Operator Instructions] At this time, I would like to turn the conference over to Richard Legault, President and Chief Executive Officer of Brookfield Renewable Energy Partners. Please go ahead, sir.

Good morning, everyone, and thank you for joining us this morning for our fourth quarter and year-end conference call. With me on the call is Sachin Shah, our Chief Financial Officer. And before we begin, I would like to remind you that a copy of our news release, investor supplement and letter to shareholders can be found on our website at www.brookfieldrenewable.com. Having launched in November 2011, fiscal 2012 represented the first full year of operation for Brookfield Renewable Energy Partners, and notwithstanding very challenging hydrology conditions in Q2 and Q3, it was an extremely successful year, in which we were able to strengthen our position as a leader in the renewable power sector, meaningfully grow our business and significantly increase distributions to our shareholders. One of the key objectives in forming Brookfield Renewable was to increase distributions by 3% to 5%, by executing on our growth plans and to deliver 12% to 15% annual total returns to shareholders. In the last 12 months, we have met or exceeded each of these objectives. In early 2012, together with our institutional partners, we announced the addition of 222 megawatts of wind assets in California's Tehachapi region. This significantly expanded our West Coast operations, bringing our total win portfolio to 274 megawatts, in one of the most attractive markets in North America. Later in the year, we announced the purchase of 2 large scale hydroelectric portfolios, which we expect to add significant shareholder value in the coming years. The first of these was the 378 megawatts Smoky Mountain portfolio in Southeastern U.S. purchased from Alcoa. That acquisition closed in the fourth quarter, with the assets having now been fully integrated into our U.S. operating platform. Prior to year end, we also announced the acquisition of a 351-megawatt hydro portfolio in Maine, with…

Thank you, Richard, and good morning. Generation of approximately 4,050 gigawatt hours in the fourth quarter was substantially improved from the prior quarter. While still below expectation, Q4 generation was approximately 90% of long-term average, and we see this trend back towards LTA generation continuing so far in January. EBITDA and FFO of $195 million and $74 million, respectively, likewise showed a large improvement in Q4, but we're still below expectations due to the generation shortfall, in particular in regions where PPA prices are higher than our portfolio average. Generation during the year totaled 16,000 gigawatt hours, significantly below our long-term average due to the dry conditions in the second and third quarter of 2012. Growth in our portfolio contribute approximately 1,000 gigawatt hours during the year and resulted in a slightly higher generation level relative to 2011. The recent hydro portfolio acquisition from Alcoa and our expected acquisition in Maine will contribute to our 2013 results. For the year, adjusted EBITDA increased $48 million to $852 million, reflecting the contribution from commissioned or acquired assets, inflation-based escalators in our PPAs and the benefit of a largely contracted portfolio. We continue to have a predictable pricing profile, driven by long-term power purchase agreements. At year end, we had contracted 98% of 2013 generation, at an average price of $83 per megawatt hour. Factoring in the acquisition of the New England hydro portfolio, our generation under contract in 2013 on a proportionate basis remains high at 95%. One of the important objectives we set out to achieve post launching BREP in 2011 was to ensure we maintain a strong financial position and enhance our access to capital. During 2012, we completed nearly $3 billion of financing and capital markets initiatives -- preferred share offerings, raising $425 million. In addition, we raised…

[Operator Instructions] The first question is from Juan Plessis of Canaccord Genuity.

With respect to the purchase of NextEra hydro assets in Maine, you've purchased assets with merchant price exposure, which is a bit outside BREP's traditional strategy. Is this partly due to the high valuation that's been placed on contracted assets in the current market environment? And should we expect to see more merchant power acquisitions in the future?

It's Richard. Just to sort of make sure that, if you look at our contract profile today, before White Pine Hydro, it was 98% contracted. So to your point, I wouldn't say it was 1 year of existence in terms of BREP. Our strategy, clearly, has been to -- if you want -- have a fully-contracted portfolio out of the gate, but we look for value. And White Pines was a great opportunity to actually buy facilities that are high quality, low cost to operate, fit extremely well with BREP's portfolio and to do that, add valuations based on prices that are at cyclical lows, particularly in New England. So we just see it as very strong value going forward. I wouldn't say that we have a preference to have a contract profile that is heavily skewed to contracted and not merchant, but we do see that with the ability and the capability of our platform that we can certainly surface great value for shareholders going forward. And it does bring some level of optionality. So including White Pine, as Sachin mentioned, I think you know our contract level in 2013 goes down to probably about something just slightly less than 95%. So it hasn't really moved the needle in terms of our contract profile this year. And we think it's a great opportunity to create value for shareholders.

Okay. But I don't disagree with you, I'm just looking at a table you've provided in your supplemental. That kind of shows where you would be 5 years out as a longer-term contracts roll off, which is around 85% contract. And I'm just wondering with new acquisitions, how comfortable might you be for an uncontracted proportion of your portfolio? Would it be at 85% or something lower?

And you're right, that at about 5 years out, 85%. I would also point out that, that includes about I would say, 1 terrawatt hour and probably greater than a terrawatt hour in Brazil which, clearly, between now and 2014, those maturities will get recontracted out. It is a fully contract market. So I think that has to be factored in. And I would say, our comfort level is quite clearly sort of anywhere in that zone of 85% to 100%. Clearly, we're quite comfortable with that. But I would also say it's more a factor of value, like if we can buy at cyclical lows, it's more a question of patients and then contracting those facilities when we see the opportunity to sign long-term contracts, secure long-term value for shareholders and surface that value over time.

Okay. And just finally, a housekeeping item. When do you expect to file your fourth quarter and year-end financial statements?

Juan, it's Sachin. Typically in the fourth quarter because we're putting out a fully -- full-blown annual report, it's not going to be as quick as we would normally have in the quarters, which usually comes out a few days thereafter. I think our expectation right now is early March or very late February, once the audit is fully completed.

The next question is from Nelson Ng of RBC Capital Markets.

Just a quick question on long-term hydrology levels, particularly in Ontario. I just recently read an article indicating that the water levels in 2 of the Great Lakes reached record lows since record-keeping began about 95 years ago. So I'm sure hydrology is just one of the many factors driving low-water levels. But are there any plans to reevaluate the long-term average for any of the hydro facilities in that area? And can you just comment about the general water levels in the Great Lakes?

Nelson, it's Richard. So I can tell you that on a regular basis and if not annually, we always review and update our LTAs. And ultimately, we also do that upon doing refinancing or financing transactions. So we're constantly reviewing these values over time. I would say the one thing about the Great Lakes area, and particularly Ontario, it's always been a bit of a different sort of cycle to these particular regions, like Great Lakes does have an affect on the hydrology conditions around our basins. And certainly, I think, today, having reached cyclical lows in terms of the history here on the Great Lakes, we were certainly aware of that and don't see an alarming trend. And we always look for more trends. It's important to note, like trends in weather and weather patterns don't happen over 10, 20, 30, 40 years. They happen over hundreds of years. So it's very difficult to tell you that we can see a trend here towards drier conditions in this area. The only thing we can tell you is that they have longer cycles. We'll be above average for longer durations and we'll be below average for longer durations in Ontario, but LTA continues to be the best value to use.

Okay. I was just wondering regarding Western Wind, are you able to comment on the level of shareholders who have tendered to your latest offer or whether you're able to say anything about Western Wind?

Well, I am ready to say this much, which is we've recently announced that we've increased our bid to $2.60. We've extended our bid to Monday, February 11, which is the upcoming Monday deadline. We continue to really believe this is a good fit for Brookfield Renewable, and that our offer represents strong value for Western Wind shareholders. Beyond that, like I'll just not -- I'll refrain from commenting further other than stay tuned on Monday. And we have said about, just about everything we had to say on the offer in our press release, recently issued. So hopefully, that's a satisfactory answer for you Nelson.

Okay. No problem. Just one last question. In terms of the NextEra Hydro acquisition, what are some of the key milestones that you need to -- that needs to be reached in order to close the deal? I was just thinking in terms of whether you'll need to -- I presume you'll need to repay or refinance the debt in order to close that deal?

Well, just on what needs to happen, like we don't see -- to close the transaction, we just need FERC approval, which typically is pretty, I would say, usual business that we've taken care of in the past. We expect to be able to close the transaction probably by the end of February, early March because it usually takes about 60 days. And then we have a whole process, as you know, to actually look at the capital structure. And we need to offer to the current bond holders to buy back the bonds because of the change of control. So that process occurs after we close, and we have 30 days to actually make that offer and which we're essentially going to do in the normal course.

The next question is from Bert Powell of BMO Capital Markets.

Just in terms of the NextEra assets, the 1,600 gigawatt hours of production. Is that the right way to think about the LTA or can -- as we add that into the LTA profile for the company?

It is, that's the gross generation, that's the gross long-term average generation. And so one thing you'll start to see us doing in our disclosure is trying to provide a bit more proportionate data because if our expectation is that we'll ultimately be a 50% owner of this portfolio, that clarity we'll provide in our disclosures. And we started to do it in the supplemental this quarter. Obviously, we haven't closed on that transaction, so it's not included in there, but you'll see that going forward.

Okay. So you'll disclose that on a proportionate basis?

Yes. We'll provide both, Bert. So you guys have a clear view as to what we manage versus what we actually have a direct economic impact from.

Okay. And just, Sachin, maybe just kind of keeping on the disclosure side. The price per megawatt when you talk about the contract on the portfolio, that's not weighted between wind and hydro, that's just the simple average?

That is the simple average, correct. That's the total portfolio average.

Is there any thought that as the wind becomes more meaningful to split the contract profile out for wind?

. Absolutely, Bert. I think if our wind portfolio meets -- today, it's 10% to 12% of the business, this is largely a hydro business. And I think as wind gets more -- if wind gets more meaningful, which it likely could, given the growth profile we see in front of us, then we would start to split it out on a segmented basis, that way.

Okay. And then just on the Alcoa assets, now that you've got those, and I assume it started in November, have you've been able to, and given it's a merchant business, have you've been able to leverage your trading platform to start to fold that into your networks, such that you're actually realizing higher price per megawatt out of that asset, and might otherwise be the case?

Bert, it's Richard. Just to be clear, one is that the Smoky Mountain assets are contracted till midpoint 2014. So that means, in 2013, largely our revenues are contracted for the year. Therefore, in the future, what we're now looking at is what to do about sort of that period post-midpoint 2014. So we are currently talking to various sort of groups in that region as to what their interest is for contracting that portfolio. But we're also looking at the ability to actually optimize it in terms of making sure that we dispatch the power at the best possible time, and at the highest possible price. So we are doing a little bit of both, but really it won't impact our bottom line until next year.

And what's the spread between the contract and current merchant prices?

Probably, it's flat.

It's flat. Okay. And then just last question, discount rate for Brazil in terms of valuing the assets came down relative to 2011, just curious given some of the regulatory developments that are going on there. I'm just wondering if you could share with us some of the thoughts around that.

Yes. So I guess let's break it up a little bit there. So discount rate you see in the short rates in Brazil come down. CDI rates are kind of 7.25% in Brazil from where we started in the year, so that clearly has an impact on our buildup of our discount rate. I think the regulatory announcements that came out in the fourth quarter are a bit of a red herring. I mean, that's really not impacting our business, we don't have concessions that were impacted for the duration that they were actually targeting, which is prior to 2017. And if you look at where we are today in Brazil, where they're talking about potential rationing and the shortage of power, clearly, one of the things that we've been talking to a lot of the investors and analysts about the lack of supply and enough supply in Brazil, and investment in supply has started to play out through an exposure to not having enough power in that country. So I think we can put the regulation aside, it's there, it's going to impact people who have concessions prior to 2017, but it doesn't change our view of value or our view of pricing in the long term. It's still fundamentally based on supply and demand.

Next question is from Matthew Akman of Scotia bank.

I wanted to delve into a little bit of dynamics of the debt holders on the New England assets. I think Sachin you mentioned that past -- close early March and then after that time, that there has to be an offer made to buy back the bonds. I'm just wondering if you could provide any other details around the offer. Is it a face value or a premium and what's their timing for response on that?

Sure. So the indenture of the opco and holdco debt, that's on these assets currently, allows the holders to actually, on the change of control, put the debt back to us at 101. So there's an extra 100 basis points on top of par value. That's their right. We've, obviously, some of you may have seen, because it's a public document, we put out a tender offer to those bondholders to offer them the same 101, but on the slightly accelerated basis. And all that really does is ensure that we can plan our liquidity and plan our financing requirements in accordance with who ultimately tenders those bonds. We, obviously, are quite comfortable with the current debt levels in those assets to the extent that people want to stay in. And we'll preserve the debt at its current level for those bondholders who don't want to tender.

Okay. What's the rought timing for getting this whole thing resolved? You said at a slightly accelerated basis.

Yes. So the tender offer contemplates that we would, if people tender early, then post-closing, I believe, it's 5 days post-closing, we would actually pay them the 101. On the other hand, if it went straight through the indenture, it's what Richard said earlier, which is it's about 30 days.

Okay. Great. Shifting to the, I guess, Western Wind, not that deal specifically, but more generally, I'm just wondering when you guys look at wind, how you look at it relative to hydro these days? I mean you've obviously made some, I think, pretty interesting acquisitions on hydro and some organic growth there. So when you pursue wind, I mean, how do you look at the multiples I guess that you're prepared to pay on it? Do you look at it -- relative to hydro that is, I mean, the asset lives are arguably shorter, so do you pay a lower multiple for that than you would for hydro, generally speaking, of current EBITDA, say?

So it's Richard. Let me just point out that we've always maintained that we're primarily a hydroelectric business and that as much as we can, we try to maintain that profile. So I would say at the beginning of last year, I think we had built up a fairly hefty wind portfolio in a very short period of time. And a lot of the people following us felt that we may be diluting our hydro portfolio. I think 2012 -- or 2012 has shown that we can find the hydro opportunities. And clearly, today, we're still about 85% hydro. So our preference is clearly hydro and we believe that, that is the highest quality asset that you can have in the renewable space. So we'll always lean that way first. As to the valuation of wind, we still think that wind is part of the renewable space. It's a good compliment to what we're doing on the hydro front. At the same time, do we value it the same way? Not really because, ultimately, the life cycle of the wind farm is clearly different. But we do have a long outlook on these facilities by trying to sign up leases that at least give us the opportunity to rebuild it, at the very least, once. And we think that, even though the life cycle of the equipment maybe 20, 25 years, if our leases are 50, we view that as an ability to actually maintain a business for a 50-year period. So do we value it at the same multiple? No, and I would say, we clearly attach a small premium to what we're looking for in a wind farm. And consider also that you're returning not just a return on capital, but a return of capital over that period, at least for a portion of it. So I think without sort of giving you exactly a recipe because it really is case-by-case and site-by-site and what kind of contracts are underlying the revenues of the wind farm, so there's lots of variables here that doesn't really sort of get boiled down into a rule of thumb. But I do think that we would attach a lot of more importance to trying to find hydro assets right across the world than we would on the wind front.

Final question is, when you do make these acquisitions, can you just remind us how the split is determined between BREP and the private partners?

Well, I think when you look at sort of using the actual private funds, that ultimately, we used to have about 25% split, which was the commitment that Brookfield had made to those private funds. And today, what we're trying to actually do is increase that commitment to 50%, providing BREP a greater opportunity to invest in a greater share of each opportunity that we find. So if we look at sort of White Pine, we've told all of you that we would offer it up to about 50% to these private funds and that, to me, just allows us to have to deploy more capital out of BREP in the opportunities that we find which I think like -- examples like Smoky Mountain and White Pine are good example of them.

So you've got to mark more than 50%?

No. I think the commitment that Brookfield is making to these funds are essentially now being increased to about 50%.

The next question is from Andrew Kuske of Credit Suisse.

Richard, just continuing on the private funds. How much capacity is left within the private funds? So just uncommitted capital that could be used in acquisitions?

Well, I think when we look at BAIF, which really I think is the fund that we have been participating in, BAIF is almost fully sort of invested. I think there is some capital left to complete some of the things that we've been doing. But I think on the case of BAIF, that one is, certainly, I think almost fully invested.

So I guess to follow-up on that, that would lead one to believe that another infrastructure funds, whether regional, across the Americas or more global might be launched?

It would be a logical conclusion.

Okay. Just a bigger, broader question. It really speaks to power pricing and just trends over a longer period of time. Could you just give us your thoughts on the impact of what we've seen from conservation efforts. Really, in the last few years, and really the outlook for conservation efforts, and just simple things like people changing from 100-watt bulbs down to 60 or 100 watt to CFLs. And really, the impact you think that has on the demand curve and outlook for power growth over the next, say, 20 years and how does that impact your view on dispatch and pricing? I mean, obviously, it's hydro, you're going to be dispatched. But if the peaks of the curve effectively get shaved off, how do you think about pricing in that longer-term context?

Well, again, that's a very sort of broad topic for this call, but I would at least venture at least an answer, which is as follows. In North America, I would say that demand side management conservation programs have existed for a very large number of years. Whether they've been successful or not, I continue to believe that the best way to actually, meaningfully start conservation programs is price. And that is the one lever that North American utilities and governments have actually not wanted to use in order to curve demand and ultimately, certainly reduce demand on peak periods. We've heard about smart grids and realtime pricing, et cetera. But really if you look throughout North America, there's very few places where you actually have that type of dynamic trying to curve demand in peak periods. So I think you're a long way away before that actually affects North American demand. But even if it did, I would say that we're a big fan of making sure that we use power sparingly and we use it smartly. Our facilities continue to be the best option, meaning that it can be dispatched at the appropriate time in the highest value period. So I'm not concerned about how that landscape changes, and I think we have the best asset to service that landscape no matter what.

All right. That's very helpful. And then just finally, if I may, one question, and it relates to Ontario and just the changing political scene. What are your thoughts on the new Premier coming in? Do you expect more of the same on green energy policies? Do you expect any changes to happen?

Well, I won't comment on the political landscape in Ontario, other than to say that we've been active industry participants in Ontario for a very long time. I think that we're confident that Ontario has certainly, I think, been good for us in terms of business, and it will continue to be good for us in the future. And like I say, I'll leave the rest to voters in Ontario.

The next question is from Sean Steuart of TD Securities.

Couple of questions. I wanted to circle back on Brazil and appreciate what you're saying in terms of the longer-term demand dynamics. But I'm wondering if you can speak to, I guess, the drought conditions that have been present in the Northeast, and I know that's not where your assets are necessarily located, but is there a point at which if this drought persist over the midterm, the balancing pool mechanism in that country could affect your price realizations?

Well, that's -- let me address that question in a couple of ways. One is that, we've been saying for a while that 2013, '14 would be years where the demand and ultimately the lack of responding to that demand with new supply, that would actually trigger very high prices and a better environment for us to go and contract this power. And I think, even though you call it a drought, I would say we've looked at the numbers and we've looked at the profile, if you look at what they built in Brazil over the last few years, it's been mainly thermal assets, or wind, or very large facilities that are not on stream today, but with no storage. So storage in that country has actually been the demand growth, but the storage stays the same. So there's a lot less flexibility. So what has occurred is that today, because water didn't show up, the storage reservoirs are fairly low. And in order to actually recover that, they need to fuel up and fire up their thermal capacity at full capacity, which has now sort of again, if you look at prices, prices in the last 2 months have risen very quickly and very dramatically in that country. So we're continuing to be very bullish in terms of Brazil as a market. We continue to believe that as demand grows in that country, that you need to respond with new supply and that there's a supply sort of price to every new facility, and we are essentially driving our contract profile to that particular level of pricing. So our view here is that we're quite bullish in terms of that country. 2 months ago, people felt that this may not be -- the prices may not hold, et cetera. And again, it just shows that every time there's a bit of a shortage, you need to fuel up a really big thermal capacity fleet that is very expensive to run.

Got it. One other question, Sachin, I'm wondering if you can give us some context on how much the Smoky Mountain assets contributed to Q4 generation or total sales.

Sure. It's -- we closed right at the end of November, so we had about a month. And remember we own about 25%, so I'd say it's negligible to our overall results. And I can call you after with the exact numbers, but it's immaterial, Sean.

[Operator Instructions] The next question is from Steven Paget of FirstEnergy.

I'm wondering if you could please comment on a further potential in Canada for a development of sub 50-megawatt hydroelectric facility, such as Kokish River. Are there more Kokishes out there?

I would say so. Certainly, I think there is -- that, I would say is probably where there exist still -- more in the south of the Canadian sort of border. There probably exist still quite a few projects in that respect. British Columbia, in particular, I would say Ontario less so, but Québec for sure. You may have seen recently, I think, with the surplus in Québec, the natural resource Minister kind of put an end to the less than 50-megawatt program. And again, I think that has more to do with the surplus that is building in Québec than anything else. But the potential still exists, yes.

Just follow-up on that. Could you please comment on the overall outlook for wind in the U.S. Are grids still taking out more wind and contracts are still available?

Well, theoretically, I think a lot of people that have done studies on this topic have said, wind can be absorbed to the tune of about 15% of the grid capacity. I think that's theoretical. It really is more a question of very specific sort of conditions around the grids across the country. But let's say you use that as a rule of thumb, we're clearly not near 15% in most of these markets, so there's probably a lot of capacity to be absorbed. At the same time, grid operators are working everyday trying to figure out ways to actually improve their grids to absorb more wind, and that includes not just capacity, but also being able to absorb the intermittent nature of wind. And I think that a good example of that is Texas, by the way, which has lots of wind built up in its market and it's continuing to develop transmission to allow access to further wind in that market. So I think, there is still a lot of room to absorb wind in that particular market.

The next question is from Lukasz Michalowski of CIBC World Markets.

Just calling in on behalf of Ian. I had a couple of quick questions. The first one, I guess, following up on the last caller's questions about development. The last year have been a lot more heavily focused on acquisitions, but the acquisition market getting a little more competitive. Do you start to expect to focus more on maybe on the development in the near future?

The answer to that question is probably not in the near term. We still continue to feel that the fundamental drivers of the acquisition market continue to be quite present. And we see, we continue to be -- to see a pretty healthy deal flow. So our view right now is that it's preferable to just by assets that are operating and that we continue to move our projects forward but clearly, not at the same pace as we would have, say, 4 years ago. So I think that will be -- continue as it seem for 2013.

Okay. And just a last quick question on the New England assets. The Alcoa Assets, I guess, the contract is expiring, I believe 2014-ish. Are you kind of comfortable in potentially selling it -- like the power into the near-term market or would you be looking to recontract those assets, as well as, I guess, the pending assets you're acquiring as well?

No. Absolutely, were very comfortable in doing that. We've been doing that for a very long time, particularly in New England, we're extremely comfortable. As I've mentioned earlier on, we have 943 megawatts of capacity in that market already, and this increases our capacity to 1,300. New England is a great market. I think so as PJM, which is, really, where the Smoky Mountain assets would be directed. So we're quite comfortable in those markets. And just to make sure it's -- well, it's clear that our expectation in 2013 would be market. So we're flat to what the market is actually sort of paying for these assets today in terms of how we actually underwrote these investments.

Okay. But I guess would you -- the markets right now is quite depressed. Would you rather kind of get into a longer-term contract just to minimize some of the risks or would you like to maintain more of the kind of the flexibility, the kind of -- an optionality to kind of benefit as the market does rebound?

Well, you see, obviously, if we are expecting or essentially sort of underwriting based on current pricing, we see a lot of upside in the future. So as gas prices go up, as congestion in New England, it clearly, continues to have an impact. Prices should rise and we should be in a really good position to capture those prices. And when we get to a point that I think where we see opportunities to contract these portfolios, I've mentioned earlier on, like trying to contract them is certainly our preferred approach, but we are well equipped and certainly knowledgeable enough to actually place these assets into the market, get the maximum revenue possible in the context and then wait -- be patient on the contract that services maximum value for the assets. So that would be our strategy at the present time for these 2 portfolios. And hopefully, that is a good answer for you.

The next is a follow-up question from Nelson Ng of RBC Capital Markets.

Just in terms of the debt to total cap, it was about 38% at the end of the year. Do you have a long-term target for the debt-to-cap ratio? And the main reason I'm asking is I'm just wondering, like for future acquisitions, will you primarily use your balance sheet to fund those acquisitions, or at some point will you need to source equity from the market?

Yes. Nelson, we don't set a target. But I think, to us, our investment grade ratings are pretty paramount in how we determine our overall capital structure. We'd like to keep a low-risk profile. We'll surface value through refinancing if the ability is there and we'll obviously look for accretive financings. I think at 38% we're quite comfortable and I think the business has the flexibility and the cash flow base to support a slightly higher level of debt, but we don't set a target.

Okay. And just one last question for Richard. In terms of generation technologies. I think in the past you've avoided solar. I'm just wondering whether cost have declined to a point where solar looks interesting?

I think from an investment standpoint, I think solar is becoming more and more interesting to us. Would we build solar based on the fact that the cost to build it has come down, probably not. But would we see an opportunity to invest in a contracted portfolio of solar projects with -- ultimately, that brings good value to BREP, I think we have an openness to that, but no immediate plans to make any investments.

There are no more questions at this time. I will now turn the call back over to Richard Legault for concluding comments.

Well, again, thank you very much, for joining us this morning. I appreciate your questions and your interest, and certainly look forward to seeing and speaking to you for the first quarter of 2013. Thank you very much, and thank you.

Ladies and gentlemen, this concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.