Earnings Call: Q4 2012

Feb 7, 2013

Hello, this is the Chorus Call conference operator. Welcome to the Brookfield Renewable Energy Partners fourth quarter and year-end conference call and webcast. As a reminder, all participants are in listen-only mode, and the conference is being recorded. After the presentation, there will be an opportunity to ask questions. To join the question queue, simply press star and one on your touchtone phone. Should anyone need assistance during the conference call, they may signal an operator by pressing star and zero on their telephone. 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. 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. 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%-5% by executing on our growth plans and to deliver 12%-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 MW of wind assets in California's Tehachapi region. This significantly expanded our West Coast operations, bringing our total wind portfolio to 274 MW 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 MW 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 MW hydro portfolio in Maine, with 19 generating stations and eight upstream storage reservoir dams on four rivers. This utility-grade fleet is one of the region's largest independently owned hydro portfolios and includes the two largest hydro facilities in Maine. This portfolio complements our existing 943 MW of capacity in the attractive New England market and increases our footprint to close to 1,300 MW. The transaction is expected to close in the first quarter of 2013. These two portfolios are an excellent fit with our operations and long-term strategy. With natural gas and electricity prices at or near their cyclical lows, we have been able to acquire high-quality hydro facilities at compelling valuations and well below replacement value. We anticipate that over time we can improve operations, create efficiencies in these regions, and surface significant additional value for shareholders. In addition to the significant M&A activity, we made great strides in advancing our development projects. In Brazil, we completed the construction of our 19-MW Pezi hydro project, which achieved commercial operations ahead of schedule during the fourth quarter. Our 29-MW Cavalinhos II hydro project is progressing as planned and remains scheduled for completion this quarter. The 45-MW Kokish River Hydro project in British Columbia remains on scope, schedule, and budget for its targeted completion in mid-2014. On the strength of all of these initiatives, we recently announced a distribution increase, the third since our launch in 2011. This brings our payout to $1.45 annually and represents a nearly 12% increase over the last 14 months. Therefore, for the year 2012, Brookfield Renewable has provided to its shareholders a total return of 13.5%, as compared to 7.1% for the benchmark S&P/TSX Composite Index. Clearly, we were disappointed on the hydrology front in 2012, particularly with very challenging results in the second and third quarter. That said, it is testimony to our strategy and the robust nature of our business that despite the shortfall, we were able to grow our business significantly and fund our operations and capital programs at normal levels. All while maintaining a very strong financial position and ample liquidity. We have come through an otherwise difficult year in great shape, and we expect to see continued improvement in our operating and financial results in the first quarter. Looking ahead to 2013, we remain confident in our ability to find accretive growth opportunities and build on the momentum of last year. We look forward to the continued progress on our growth plans, the completion of development projects, and the beneficial impact of strategic initiatives going forward. On a final note, we had hoped our New York Stock Exchange listing would take effect in 2012. We are continuing to work on the SEC with the Securities and Exchange Commission to achieve final clearance, which would allow us to list our shares on the New York Stock Exchange. We continue to be optimistic that we will achieve this milestone in the first quarter of 2013. I'll now hand over the call to Sachin to discuss our financial operating results. Thank you, Richard, and good morning. Generation of approximately 4,050 GWh 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 $75.4 million respectively, likewise showed a large improvement in Q4, but were still below expectations due to the generation shortfall, in particular regions where PPA prices are higher than our portfolio average. Generation during the year totaled 16,000 GWh, significantly below our long-term average due to the dry conditions in the second and third quarter of 2012. Growth in our portfolio contributed approximately 1,000 GWh 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 MWh. 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 preferred share offerings, raising $425 million. In addition, we raised $175 million for 40 years in respect of our Kokish River Hydro project in BC. Like our other financings completed in 2012, these have provided us with stable and accretive long-term sources of capital at very attractive rates. Interest expense in 2012 was consistent with the prior year, in spite of significant growth in the business, as we continue to issue long duration fixed rate debt at rates that are at historically low levels. Accordingly, we have maintained the duration of our loan portfolio at approximately 10 years and reduced our overall debt cost of capital by approximately 50 basis points. These initiatives represent an approximately $30 million reduction in interest costs on an annualized basis. Looking forward, we have approximately $400 million of subsidiary borrowings maturing in 2013 related to our wind portfolio in Ontario. We have already commenced the refinancing process on these facilities, which should be completed in the normal course. We have no corporate borrowings maturing until 2016. Turning to our balance sheet, our financial position remains strong. We currently have $850 million of available liquidity consisting of cash and unutilized bank lines. Despite generation levels below long-term average in 2012, we've been able to fund growth, CapEx, and our distributions without meaningfully depleting liquidity levels, demonstrating the financial flexibility and resilience of our operations and capital structure. Accordingly, we are very well positioned to capitalize on growth opportunities that are in front of us. That concludes our formal remarks. Thank you for joining us this morning. Richard and I would be pleased to take your questions at this time. We will now begin the question and answer session. The first question is from Juan Plessis of Canaccord Genuity. Please go ahead. Thanks very much. With respect to the purchase of NextEra's 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 valuations being placed on contracted assets in the current market environment? Should we expect to see more merchant power acquisitions in the future? Good morning, it's Richard. Just to sort of make sure that, you know, if you look at our contract profile today, before White Pine Hydro, it was 98% contracted. To your point, I wouldn't say with one year of existence in terms of BREP, you know, our strategy clearly has been to, if you want, have a fully contracted portfolio out of the gate. We look for value, and White Pine was a great opportunity to actually buy facilities that are high quality, low cost to operate, fit extremely well with BREP portfolio, and to do that at 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, you know, we have a preference to have a contract profile that is heavily skewed to contracted and not merchant. But we do see that, you know, 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. Including White Pine, as Sachin mentioned, I think, you know, our contract level in 2013 goes down to probably about just slightly less than 95%. 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, thanks for that. 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 five years out as the longer-term contracts roll off, which is around 85% contract. 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? You're right that at about 5 years out, 85%. I would also point out that that includes about, I would say, 1 terawatt-hour and probably greater than 1 terawatt-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. I would say, you know, our comfort level is quite clearly sort of, you know, anywhere in that zone of 85%-100%. Clearly, we're quite comfortable with that. 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 patience 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, thank you for that. Just finally, a housekeeping item. When do you expect to file your fourth quarter and year-end financial statements? Hey, Juan, it's Sachin. Sachin. You know, typically in the fourth quarter, because we're putting out a fully full-blown annual report, it's not gonna 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. Okay, thank you very much. No problem. The next question is from Nelson Ng of RBC Capital Markets. Please go ahead. Thanks. Good morning, everyone. Morning. Just a quick question on long-term hydrology levels, particularly in Ontario. I just recently read an article indicating that the water levels in two of the Great Lakes reached record lows since record-keeping began about 95 years ago. I'm sure hydrology is just one of the many factors driving low water levels. Like, 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. I can tell you that on a regular basis, and if not annually, we always review and update our LTAs. Ultimately, you know, we also do that upon doing refinancing or financing transactions. We're constantly reviewing these values over time. I would say, you know, the one thing about the Great Lakes area and particularly Ontario, you know, it's always been a bit of a different sort of cycle to these particular regions. Like, Great Lakes does have an effect on the hydrology conditions around our basins. Certainly, I think today, having reached cyclical lows in terms of, you know, the history here on the Great Lakes, you know, we're 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. It's very difficult to tell you that, you know, 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 will be below average for longer durations in Ontario. LTA continues to be the best value to use. Okay, thanks for that. 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, you know, we've recently announced that we've increased our bid to $2.60. We've extended our bid to Monday, February eleventh, 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, you know, I'll refrain from commenting further, other than, you know, stay tuned on Monday. We have, you know, said about just about everything we had to say on the offer in our press release recently issued. Hopefully that's a satisfactory answer for you, Nelson. Okay. Yeah. No problem. Just one last question. In terms of the NextEra hydro acquisition, like what are some of the key milestones that needs to be reached in order to close the deal? I was just thinking in terms of I presume you'll need to repay or refinance the debt in order to close that deal. Well, just on, you know, what needs to happen, like. To close the transaction, we just need FERC approval, which typically is pretty, you know, I would say, you know, 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, 'cause it usually takes about 60 days. Then we have a whole process, as you know, to actually look at the capital structure, and we need to offer to the current bondholders to buy back the bonds because of the change of control. That process occurs after we close, and we have 30 days to actually make that offer and which we're essentially gonna do in the normal course. Okay, thanks. I'll get back in the queue. Okay. The next question is from Bert Powell of BMO Capital Markets. Please go ahead. Yeah, thanks. Just in terms of the NextEra assets, the 1,600 GWh of production, is that the right way to think about the LTA or can you know as we add that into the LTA profile for the company? Hey, Bert. It is. That's the gross generation. That's the gross long-term average generation. One thing you'll start to see us doing in our disclosures 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, you know, 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. You'll disclose that. We'll provide. On a proportionate basis. Yeah, 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. Just, Sacha, maybe just kinda 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 a 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, I mean, it's today, you know, 10%-12% of the business. This is largely a hydro business. I think 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. Just on the Alcoa assets, you know, now that you've got those, I assume those started in November, have you been able to, and given it's a merchant business, have you been able to leverage your trading platform to start to you know fold that into your network such that you're actually realizing, you know, higher price per megawatt out of that asset than 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. That means. Okay. You know, 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. We are currently talking to various sort of groups in that region as to what their interest is for contracting that portfolio. 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. We are doing a little bit of both, but really it won't impact our bottom line until next year. What's the spread between the contract and current merchant prices? There is probably it's flat. It's flat. Okay. 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, just wondering if you could share with us some of the thoughts around that. Yeah. Hey, Bert. I guess let's break it up a little bit there. Discount rates, you've seen the short rates in Brazil come down. CDI rates are kind of 7.25% in Brazil from where we started in the year. 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 was prior to 2017. If you look at where we are today in Brazil, where they're talking about potential rationing and a shortage of power, clearly, you know, one of the themes that we've been talking to a lot of investors and analysts about, you know, 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. I think we can put the regulation aside. It's there, it's gonna 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. Okay, thanks for that, Sachin. Next question is from Matthew Akman of Scotiabank. Please go ahead. Thank you very much. I wanted to delve into a little bit the dynamic of the debt holders on the New England assets. I think, Sachin, you mentioned that supposed to 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 at face value or a premium? And what's their timing for response on that? Sure. The indenture of the OpCo and HoldCo debt that's on these assets currently allows the holders to actually, on a change of control, put the debt back to us at 101. 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 'cause it's a public document, put out a tender offer to those bondholders to offer them the same 101, but on a slightly accelerated basis. 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 on those assets to the extent that people wanna stay in. We'll preserve the debt at its current level for those bondholders who don't want to tender. Okay. What's the rough timing for getting this whole thing resolved? You said at a slightly accelerated basis. The tender offer contemplates that we would, if people tender early, then post-closing, I believe it's five days post-closing, we would actually pay them the $101. Okay. On the other hand, if it went straight through the indenture, it's what Richard said earlier, which is 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 there's some organic growth there. 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. Do you pay a lower multiple for that than you would for hydro, generally speaking, of current EBITDA, say? It's Richard. Let me just point out that, you know, we've always maintained that we're primarily a hydroelectric business, and that, you know, as much as we can, we try to maintain that profile. I would say at the beginning of last year, I think, you know, 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, you know, we may be diluting our hydro portfolio. I think 2012 has shown that, you know, we can find the hydro opportunities, and clearly today we're still about 85% hydro. Our preference is clearly hydro, and we believe that that is the highest quality asset that you can have in the renewable space. 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 complement to what we're doing on the hydro front. At the same time, do we value it the same way? Not really, because, you know, ultimately the life cycle of a wind farm is clearly different. But we do have a long outlook on these facilities by, you know, trying to sign up leases that at least give us the opportunity to rebuild it at the very least once. And we think that, you know, even though the life cycle of the equipment may be 20-25 years, if our leases are 50, we view that as an ability to actually maintain a business for a 50-year period. Do we value it at the same multiples? No. You know, I would say we clearly attach a small premium to what we're looking for on a wind farm. Consider also that, you know, you're returning not just a return on capital, but a return of capital over that period, at least for a portion of it. I think, you know, without sort of giving you exactly a recipe, 'cause it really is case by case and site by site, and what kind of contracts are underlying the revenues of the wind farm. There's lots of variables here that doesn't really sort of get boiled down into a rule of thumb. Right. I do think, you know, that we would attach a lot more importance to trying to find hydro assets. Right across the world than we would on the wind front. Thanks for that. 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, you know, when you look at sort of using the actual private funds that ultimately we used to have about a 25% split, which was the commitment that Brookfield had made to those private funds. 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. If we look at sort of White Pine, we've told you know all of you that we would offer it up to about 50% to these private funds. You know, 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. Could it go to more than 50%? No. All right. I think, you know, the commitment that Brookfield is making to, you know, these funds are essentially now being increased to about 50%. Okay. Thank you very much, guys. Those are my questions. Thank you. Next question is from Andrew Kuske of Credit Suisse. Please go ahead. Good morning. Richard, just continuing on the private funds. How much capacity is left within the private funds, just of uncommitted capital that could be used in acquisitions? Well, I think, you know, when we look at BAIF, which really I think is the fund that we have been participating in, you know, BAIF is almost fully sort of invested. I think there is some capital left there to complete some of the things that we've been doing. I think on the case of BAIF, that one is certainly I think almost fully invested. I guess the follow-up on that is it that would lead one to believe that another infrastructure fund, whether you know regional across the Americas or more global, might be launched. It would be a logical conclusion. Okay. Thank you for that. Just a bigger, broader question, and really it 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? Really the impact you think that has on the demand curve and the outlook for power growth over the next, say, 20 years. How does that impact your view on dispatch and pricing? I mean, obviously as hydro you're gonna 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, you know, again, that's a very sort of broad topic for this call, but I would at least venture an answer which is as follows. In North America, I would say that, you know, 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, you know, conservation programs is price. That is the one lever that North American utilities and governments have actually not wanted to use in order to curb demand and ultimately certainly reduce demand on peak periods. You know, we've heard about smart grids and, you know, real-time pricing, et cetera. Really if you look throughout North America, there's very few places where you actually have that type of dynamic trying to curb demand in peak periods. I think you're a long way away before that actually affects North American demand. Even if it did, I would say that, you know, we're a big fan of, you know, making sure that we're, 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 and the highest value periods. I'm not concerned about how that landscape changes, and I think we have the best asset to service that landscape no matter what. Right. That's very helpful. Just finally, if I may, one question, and it relates to Ontario and just the changing political scene. You know, 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? I won't comment on the political landscape in Ontario other than to say that, you know, we've been, you know, active industry participants in Ontario for a very long time. I think that we're confident that Ontario has, you know, certainly I think been good for us in terms of business, and it will continue to be good for us in the future. Like I say, I'll leave the rest to voters in Ontario. Okay, that's great. Thank you. The next question is from Sean Stewart of TD Securities. Please go ahead. Thanks. Good morning, guys. Couple questions. I wanted to circle back on Brazil and, you know, appreciate what you're saying in terms of the longer term demand dynamics. Wondering if you can speak to, I guess, the drought conditions that have been present in the Northeast. I know that's not where your assets are necessarily located, but, you know, is there a point at which if this drought persists over the midterm, the balancing pool mechanism in that country could affect your price realizations? Well, you know, that's. Let me address that question in a couple of ways. One is that, you know, we've been saying for a while that 2013, 2014 would be years where, you know, the demand and ultimately the lack of responding to that demand with new supply, that would actually, you know, trigger very high prices and a better environment for us to go and contract, you know, this power. I think, you know, 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've 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. Storage in that country has actually been that demand grows, but the storage stays the same, so there's a lot less flexibility. What has occurred is that today, because water didn't show up, the storage reservoirs are fairly low. 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 in the last two months have risen very quickly and very dramatically in that country. We're continuing to be very, you know, 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, you know, 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. Our view here is that, you know, we're quite bullish in terms of that country. Two months ago, you know, people felt that, you know, this may not be, you know, the prices may not hold, et cetera. 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. Thanks for that context. 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. Remember, we own about 25%, so it's, I'd say, negligible to our overall results. I can call you after with the exact numbers, but it's immaterial, Sean. Okay. Okay, that's all I had. Thanks, guys. As a reminder, anyone who has a question may press star and one at this time. The next question is from Steven Paget of FirstEnergy Capital. Please go ahead. Good morning. I'm wondering if you could please comment on the further potential in Canada for development of sub-50-MW hydroelectric facilities such as Kokish River. Are there more Kokishes out there? I would say so. Certainly I think, you know, there is. That I would say is probably where there exists still more in the south of the Canadian sort of border. There probably exists still quite a few projects in that respect. British Columbia, in particular, I would say, Ontario less so, but Quebec for sure. You may have seen recently, I think, you know, with the surplus in Quebec, the natural resource minister kind of put an end to the less than 50-MW program. Again, I think that has more to do with the surplus that is building in Quebec than anything else. The potential still exists, yes. To follow up on that, could you please comment on the overall outlook for wind in the U.S.? Are grids still taking up more wind and contracts are still available? Well, theoretically, I think, you know, a lot of people that have done studies on this topic have said, you know, 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, you know, 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 still probably a lot of capacity to be absorbed. At the same time, grid operators are working every day trying to figure out ways to actually improve their grids to absorb more wind, and that includes not just capacity, but also, you know, being able to absorb the intermittent nature of wind. I think that a good example of that is Texas, by the way, which, you know, has lots of wind built up in its market and is continuing to develop transmission to allow access to further wind in that market. I think, you know, there's still a lot of room to absorb wind in that particular market. Well, thank you, Richard. Those are my questions. Well, thank you. Next question is from Paul Lechem of CIBC World Markets. Please go ahead. Good morning. 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. In the last year or so you've been a lot more heavily focused on acquisitions. But with 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, you know, the acquisition market continue to be quite present. We continue to see a pretty healthy deal flow. Our view right now is that it's preferable to just buy assets that are operating. And that, you know, we continue to move our projects forward, but clearly not at the same pace as we would have, you know, say, four years ago. I think that will continue as a theme for 2013. Okay. I guess just last quick question on the New England assets. You know, the Alcoa assets, I guess, the contract is expiring at, I believe, 2014-ish. Are you kind of comfortable in potentially selling into like the power into, like a near-term market? Or, you know, would you be looking to recontract those assets, as well as, I guess, the pending assets you're acquiring as well? No, absolutely. We're very comfortable in doing that. You know, 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 MW of capacity in that market already, and this increases our capacity to 1,300 MW. New England's a great market. I think so is PJM, which is really where the Smoky Mountain assets would be directed. We're quite comfortable in those markets. Just to make sure it's clear, our expectation in 2013 would be market. 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. I guess you know the markets right now is quite depressed. Would you rather kind of get into a longer-term contract just to you know minimize some of the risks? Or would you like to maintain more of the kind of flexibility to kind of an optionality to kind of benefit as the market does rebound? Well, we see obviously if we are expecting and are essentially sort of underwriting based on current pricing, we see a lot of upside in the future. As gas prices go up, as congestion in New England, you know, it clearly continues to have an impact. Prices should rise, and we should be in a really good position to capture those prices. When we get to a point, 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. 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 a contract that surfaces maximum value for the asset. That would be our strategy at the present time for these two portfolios. Hopefully that is a good answer for you. Yeah. Thank you very much. That's it from my end. Thank you. Okay. Next is a follow-up question from Nelson Ng of RBC Capital Markets. Please go ahead. Great, thanks. 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? Like, the main reason I'm asking is I was just wondering, like for future acquisitions, will you primarily just use your balance sheet to fund those acquisitions? Or at some point, will you need to source equity from the market? Yeah, Nelson, you know, 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. You know, we like to keep a low risk profile. We'll surface values through refinancing if the ability is there, and we'll obviously look for creative financings. I think at 38% we're quite comfortable. 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, thanks. 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 costs have declined to a point where solar looks interesting. I think, you know, 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. You know, 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. Okay, thanks a lot. 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.