Brookfield Renewable Partners L.P.

Thank you, operator. Good morning, everyone, and thank you for joining us this morning for our first quarter 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, supplemental information and letter to unitholders can be found on our website at www.brookfieldrenewable.com.

I'm pleased to say that the year is off to a very strong start, and the business has been performing to expectations with respect to our objectives in the areas of operations, growth and capital market initiatives.

Our portfolio is performing well, and that includes the more than 550 megawatts of hydro and wind facilities that were acquired or commissioned in recent months. We have continued to expand our business in both the Hydroelectric and Wind segments.

In Hydro, our 2 new facilities in the United States, Glen Ferris and Lower St. Anthony Falls, are contributing to results and performing to expectations.

In Brazil, development continues as planned on 2 hydroelectric generating stations with a combined capacity of 48 megawatts and which are expected to enter commercial operations in early 2013.

We also look forward to beginning construction in the next several months on the 45-megawatt project in Western Canada having received the material permits to proceed. As you know, in addition to our predominantly hydroelectric focus, we have also assembled a high-quality wind portfolio, which provides our business with complementary long-life renewable power assets and resource diversification.

We operate nearly 800 megawatts of wind capacity today, and our facilities are situated in attractive markets in Canada and the United States.

One of these markets is California, and specifically in the Tehachapi region in the southern part of the state. We did not have a presence in California's renewable power sector prior to 2010, so this represents a relatively new market for us that is strongly aligned with our growth strategy and operating philosophy.

We were drawn to the Tehachapi region for a number of reasons. First, the area benefits from an attractive, proven wind resource and was one of the first areas in the United States to experience wind generation on a commercial scale.

The wind resource is, therefore, not only attractive but has many years of data supporting it. The region also benefits from close proximity to the demand centers in the southern part of the state, most notably the greater Los Angeles area, one of the most populous and fastest growing regions in the country.

The relatively-limited availability of land for wind power development and high barriers to new development, combined with strong demand for renewables, underpin the attractiveness of this market.

Together with a 30-megawatt hydroelectric facility in northern part of the state, we now own, with institutional partners, 300 megawatts of renewable power generating capacity in California, a market with high scarcity value in which we would like to continue to expand our business.

Despite being one of the largest power markets with 60,000 megawatts of installed capacity, the California market will require new supply over the next decade, a significant portion of which is intended to come from renewable resources.

California's renewable power standards currently mandates that 33% of the state's electricity supply must be met by renewable sources by 2020. Among the available options, wind power assets such as ours offer the most scale and the lowest cost to meet these future supply requirements.

The combination of high-value resources and strong long-term fundamentals make California a desirable place for further expansion, and we will continue to pursue new opportunities in the region, as well as in other core markets, which share many of its attributes.

We are well-positioned relative to our distribution payout policy of 60% to 70% of funds from operations, and with the accretive growth in the last several months, we remain confident in our ability to produce long-term distribution growth in the range of 3% to 5% annually.

It is also important to note that the increase in our distribution to $1.38 per unit announced earlier this year took effect with the first quarter distribution.

We continue to strengthen our position as the leading pure-play renewable power company, and that also means continuing to enhance our capital market profile. Last week, we filed a registration statement with the Securities and Exchange Commission, which is the first step in achieving a listing on the New York Stock Exchange.

Subject to the required approvals, we would anticipate that a listing would be achieved in the second half of 2012. We expect that the New York Stock Exchange listing, together with the distribution reinvestment plan introduced this quarter, will make it easier for existing and new unitholders to participate in our growth over time.

Clearly, Brookfield Renewable is off to a strong start in 2012. We're confident that additional opportunities will present themselves as the year progresses, and that we will be in a position to capitalize on them.

I'll now ask Sachin to present the financial and operating results for the quarter. Thank you very much.

Thank you, Richard, and good morning. Before I begin, I wanted to point out that comparative financial results, including revenue, EBITDA and FFO, are being discussed here on a pro forma basis, which assumes that the combination has taken effect on January 1, 2011.

Given the material impact of the combination agreements and contract amendments, we believe this approach will better assist investors in assessing our results, both relative to the prior year and to the long-term average.

We operate our business on the expectation of long-term average generation, and from time to time, generation will be above or below long-term average. This quarter, generation was 4,800 gigawatt hours, which is 23% higher than Q1 of last year and 6% higher than the long-term average.

That being said, we encourage you to refer to our financial information to assess results, keeping in mind average generation, which is reflective of our long-term expectations.

The first quarter results reflect higher -- reflect improved hydrologic conditions from strong inflows in North America, and our generation from our wind portfolio was also slightly above expectations and higher than the prior year due to favorable wind conditions at existing facilities and the contribution from new wind farms in Canada and the United States.

Revenues in the first quarter totaled $430 million, representing a year-over-year increase of $102 million, and EBITDA increased 33% to $318 million from $239 million in 2011.

Interest costs reflect the costs related to approximately $1.5 billion of corporate debt and $4.5 billion of nonrecourse, asset-specific debt. Approximately 75% of our financings are comprised of nonrecourse, project-level debt.

As a result of the factors previously discussed, funds from operations or FFO in the quarter was also strong at $170 million as compared to $119 million in the first quarter of 2011 on a pro forma basis.

During the quarter, we issued $400 million of 10-year corporate notes bearing interest at 4.79%. Proceeds from the offering were used to reduce existing indebtedness and reduce our overall cost of capital.

We also expanded our corporate credit facility from $600 million to $900 million, while extending maturities to October 2016. In expanding our credit facility, we welcomed several new global financial institutions into the facility, which should further enhance our access to capital over time.

At quarter end, total liquidity was approximately $945 million, consisting of $249 million of cash and equivalents and almost $700 million of undrawn amounts on our corporate credit facility.

Our subsidiary borrowings maturing in 2012 include $260 million of debt on our Eastern Canadian wind assets and $200 million of debt related to our hydro facilities in New York. We expect to be able to refinance all of these maturities in the normal course during the year.

And subsequent to the quarter end, we refinanced $115 million of indebtedness associated with the pumped storage facility we own in New England on a 5-year term. The asset is also owned 50% with a partner.

We have no corporate borrowings maturing until 2016.

Net asset value of our partnership at quarter end was $8.6 billion, slightly higher than the value at the end of 2011, reflecting appreciation in the Canadian dollar and the Brazilian reais relative to the U.S. dollar.

As Richard indicated, the business has been performing very well and is well positioned to achieved its operating and financial objectives for 2012.

Thank you for joining us this morning. We look forward to reporting on our progress next quarter and will be pleased to take your questions at this time.

Operator?

Richard, you mentioned in your introductory comments that you see California as an attractive market for further expansion. Can you comment on your strategy with respect to the California market in the context of whether you'd be more inclined towards acquisitions or if greenfield opportunities appear more attractive to you?

And maybe what you're seeing in terms of current opportunities in that market?

Well, I think that I would say, the opportunities are, I think, on both fronts, acquisitions and developments. I would say on the acquisition front, there are several financial players that actually are commissioning large wind farms in the same area.

We don't think they are long-term strategic players, and we intend to be opportunistic in trying to acquire and increase the critical mass of facilities that we have in this same area, which is the Tehachapi area. I would say other projects that are being developed today are having a harder time finding capital to develop these projects.

I think that we're the perfect partner. We've shown that in the projects such as Coram.

We continue to look for those opportunities, and we feel confident that others will surface over time. We also want to mention that because of the content of wind in this particular market, several opportunities that we've looked at include also pumped storage opportunities going forward.

Now that is clearly a much longer term development opportunity, but it's something that we feel that will be required by the California market to balance the grid itself, meaning balance load and supply in certain periods of the day. And we feel that this is an opportunity for us considering that we already own one on the East Coast.

So to answer your question, we feel pretty strongly this is a critical area. We have now critical mass.

We can integrate assets very effectively in the assets that we own. And whether that is an acquisition, a development or a different technology such as pumped storage, we feel we can do a lot of those things very effectively.

Can you comment on where your reservoir levels were in Canada and the U.S. going into the second quarter?

Well, as always, we try to caution everybody. We know that this has been a very strong quarter from a hydrological standpoint.

As we said over and above the LTA, I think we're about 6% higher. Our reservoirs are in really good shape, so we're above long-term average in most of our reservoirs for this time of year, keeping in mind that because, as we like to say, spring came early, a lot of our reservoirs are being stocked up early in the process.

So for this period of -- this time of the year, we are typically very much above the rule curve or long-term average for this period. So we're in a strong position for the remainder of the year because our reservoirs are really, I think, in good shape.

But again, I caution everybody, our expectation is LTA for the rest of the year and that is what we hope everyone has as an expectation. So -- but we're in a strong position to make sure we achieve it.

Just going back on the reservoir levels. I guess, due to the warm winter and I guess likely lower snowpack levels, like, how will that impact -- or do you feel that, that will negatively impact the reservoir levels or hydrology going forward for the rest of the year?

Actually, it doesn't, Nelson. It actually has helped.

The conditions have been mild and, therefore, we've had more rain combined with an early call it snowpack melt, so our reservoirs are full. So typically, you would look to probably mid-May, mid-June to have reservoirs full after all of the actual water has come out of -- basically come in to our reservoirs.

That has occurred early this year, so we're in really good shape. And snowpack, just like -- for the record, snowpack helps, but it really isn't the determining factor.

Water content of snow can vary year-to-year. And typically, rainfall during the spring is a much bigger driver as to whether we fill our ponds or not.

Okay. And then just in terms of the Kokish facility, you mentioned that you'll be starting construction later this year.

Can you comment on the, I guess, the First Nations, their economic ownership in the facility and how that's structured? I was just wondering whether they're contributing, like, real equity or whether Brookfield is investing 100% of the project costs?

Well, we have -- first of all, let me comment on the First Nations. The Namgis have been really a great partner for us.

They've been a strong supporter of the project. They've been doing a lot of work on the environmental front to assist us.

So when we look at the partnership itself, we're extremely pleased with the partnership and with our partner. In terms of equity contribution, the actual equity contribution from the First Nation is 25% of the total equity.

And we will -- we are facilitating that equity, meaning Brookfield, but at the same time, it is real equity that they are investing. And over time, they will actually pay down the loan to actually finance that equity to us, and it is real equity going forward.

Okay, that's great. And then just on California.

Like, are those transactions, do they have, like -- is it structured such that there's a tax equity piece in, like, in terms of part of the financing?

We have not done tax equity in the case of all of these California projects. Tax equity, if you sort of go back a few years, tax equity costs have actually increased substantially.

We just don't -- didn't feel that it was a worthy sort of way to source capital for the projects and the acquisitions. At this time, they stand on their own, and there is no tax equity that we put in place.

Okay. And just one last housekeeping question.

What was the maintenance CapEx for the quarter roughly?

The maintenance CapEx for the quarter was approximately $12 million.

Rick, just on Kokish, is there a PPA in place underpinning that at the moment?

There is. The PPA was basically put in place a while back.

But again, this is a fully-contracted asset for, I believe, 40 years.

40 years, okay. Have you got a rate that you can share with us?

At this stage, we haven't shared the rates on the PPA, and again, there's lots of complexity to doing that. But I would say it is in line with what you've seen for this type of facility in BC over the last few years, and somewhat -- and just to be clear, somewhat higher because of the fact that Kokish is a very special project.

I guess, every promoter will tell you that their project is special. So when you look at Kokish, it is actually because British Columbia gets a lot of their power during the summer as a lot of the mountains and the snowmelt melts and comes down the rivers.

Kokish is actually the reverse. You get more of its power during the winter months, which really is counter to what BC requires.

So they get a lot more value out of Kokish than they would other projects of similar nature.

Interesting, okay. And sorry if I missed it, what's the target in-service date for Kokish?

I would say that, again, it's about 24 months construction period once we start, so we expect to start in the next couple of months. We've been preparing -- I think now that we've secured the permits, we can accelerate a lot of the planning for it.

But we feel that it's about 24 months. So call it -- we start this summer 2 years from that point.

And, Rick, I had a question, just on the wind LTA -- and excuse me if you've discussed this before. But just curious how much of the LTA is based on actual production data versus using met tower data or something along those lines?

I would say, listen, the typical North American projects would have 2 to 4 years of data that really come from met towers before projects are actually built and you get actual data. I would say the one exception to that is where wind actually has a longer history.

Tehachapi is one of those areas. So you have as much as 20 to 25 years of data on sort of capturing wind in this particular area.

So we were quite confident with the production output that we underwrote on the acquisitions we've made or the projects we've developed. Where you'll have a more challenging time to actually do that will be on the East Coast, where there's been a lot fewer wind farms that have existed over time and that you actually have to rely on a couple of years.

So I would say Comber, for example, that we just built, we've been developing Comber for almost 7 years, so almost 8. So we've been collecting data for a long time before we built it.

So again, it varies, but I would say typically 2, and then extrapolate based on other sources of data.

How well does the, typically, has the data you've collected from the towers lined up with the productions that you've seen once that -- once you've actually gone to using the turbines to generate the power?

Well, I know that you -- some of you have heard me say this in the past. We've been very slow getting into the wind business because -- call it before Prince, which was in 2006 or 2007, and we kind of held that position for a long time.

We didn't really get into wind in a big way. We just were concerned about the science of predicting output and knowing that the industry has clearly fallen short in expectations.

So I think we've been more conservative. I think we've been pretty pleased -- obviously, Prince and others have probably been less than what I expect -- that was the first one 5 years ago.

But we're quite confident right now with sort of the other projects that we've built that we've built in another conservative underwriting assumptions that the numbers that we're seeing are more in line with what our expectation would've been.

Okay, great. And just last question, the 700 gigawatts of annual production, which is not contracted.

And you sort of indicate that you're looking to be opportunistic with this. My assumption is most of that relates to Brazil?

It does. When you look at sort of going forward longer term, our position in Brazil has been very clearly that prices will actually increase over the next 2 years, and there's a couple of factors that are driving that.

Today, Brazil is very heavily sort of supplied by hydroelectric facilities. It's been a very wet period, so there's been excess production, at the same time as demand has not increased as fast as people expected.

So prices have softened a little bit, and that, I would say, we expected. I think we also expect that a lot of significant projects are essentially going to be late in Brazil.

And again, we don't wish that on all of the promoters, but I would say that, that is our expectation based on what we know. In addition, that -- as in all things, water will go back to long-term average in Brazil, and the markets will tighten up.

So what we're doing now is any position that we have coming due, we're looking at the market, monitoring it very closely, but you probably won't see us lock into longer term contracts before at least 12 to 24 months.

What's been the biggest driver of the imbalance? Has it been the hydrology or has it been the demand?

I think both. Growth in Brazil has been, over the year, about 2.8%, I think.

But if looking at the overall economy, 2.8% growth, when unemployment is really shrinking in that country, we read that as being the country's really sort of operating on all cylinders. And clearly, people are engaged in growing the economy, but it has slowed down.

We think that at 2.8%, growth expectations next year should be 4% to 4.5%. When we look at going forward, that triggers higher demand in electricity.

And again, when we do all of that math, we think that the market is going to tighten up in 12 to 24 months.

I'm wondering if you could provide an update on Lake Superior plants and your outlook, I guess, for the gas-fired market in Ontario and whether there's any discussions going on with the OPA on recontracting.

Well, let me just comment briefly. LSP is a great facility in Northern Ontario.

We have a contract that basically comes due in 2014. Clearly, today, with gas prices being what they are, it's great that we can actually buy gas and produce based on our long-term contract that was in place starting in 1991.

So obviously, this is a great facility for us. We're, as much as everyone else in the province, looking at NUG contracts, which is what they were called at that time, so that -- to be able to renew them and continue to ensure that they are productive assets in the province of Ontario.

So those discussions are happening, I think, as an industry. And we expect that, again, this asset will be part of any settlement that occurs within all of the NUG producers.

Okay. I guess a bigger picture question.

There's been a lot of noise around expropriation, government intervention on some of the South and Central American countries: Argentina, Bolivia, Belize. I know Brazil is very different, but I'm just wondering how you guys feel about the political risk in the country at this time?

I can tell you that we're not investing any time soon in Argentina, Bolivia or Venezuela, so that's good news. I think at the same time, we feel very confident, like, Brazil is a place we've been in for a long, long time.

We're quite confident that Brazil isn't going to nationalize industries such as you've seen so far in some of these countries. We see no signs in Chile, Peru, Colombia and also Brazil of any of the things that are occurring in Argentina, trickling into those countries.

We see a lot more openness to investing. And clearly, capital markets are improving in all of these jurisdictions.

So I think in the end, it's a matter of making sure that we keep making progress in terms of reducing poverty in most of these markets, and I think they won't change what works.

I guess, my first question is just on the refi on the pumped storage facility in New England. Just looking at LIBOR, in the term structure LIBOR, you've got to tilt upwards on that over a period of time.

So just sort of curious on what you're thinking on what happens with LIBOR rates over the next 5 years, and if there's an option, really, to term that out at some point in the next 5 if we saw a ramp up in rates?

Andrew, it's Sachin. So you're absolutely right.

In fact, as much as it's a LIBOR plus 225 spread financing, which I think we disclosed in our supplemental, the covenant package really requires us to lock that in -- lock in most of the exposure. And we have a little bit of floating exposure on 25% remaining, which is at our discretion.

And I think currently, we benefit from a very low LIBOR, but if we see that start to change very quickly, we can lock in the final piece. But we don't really have any exposure here.

This is all locked in.

What would compel you to really lock in all of it? What kind of ramp would we be talking about on LIBOR?

Just looking at the 5-year forward, if the world was to play out that way, I think we're very comfortable keeping the exposure. But that being said, it's not a material amount, and we'd likely just lock it in, Andrew.

I'm not sure we're in the business of taking on risk on interest rates. So that would be our preference.

Okay. And then a bigger broader question and really just turning to California, given the commentary and the supplemental package and the letter about California and really your increased exposure in that state, I guess, just on a bigger, longer term basis, what's your view on the nuclear facilities that exist in California, San Onofre and Diablo, and how that fits into the generation mix as the state tries to push up its generation 1/3 of the power coming from renewable sources?

Listen, when you look at sort of renewables in the state of California, I believe about 20% or so is being provided by renewables. The target is 33% before 2020.

So this has been a state that's been highly successful in increasing its commitment to renewables. Across North America, I would say across the U.S.

in particular, basically, nuclear and coal are not really sort of in favor today. Will that change over time, Andrew?

I don't know. I would say that typically there are periods where this is more attractive than others.

The nuclear fleets, I think, will be something that will stay into production as long as they possibly can. But when they actually have to invest in the nuclear fleet, it becomes a really sort of big investment decision.

And that's when I think renewables are competitive against that decision. So it comes back to the same thing that coal may be, which is what do you have to invest in order to achieve another 20 or 40 million -- or 40 years of productive assets?

And I think that decision then has to be compared to investing in new resources that are renewable. I think that renewables are going to compare very favorably against that decision going forward.

So my view is that nuclear programs in California, no different than others, will try to sort of outlast everybody by sort of keep the asset producing. But there will be a time where you need to make a decision to invest capital.

That time will be -- there's a comparison to make with other choices, and I think we compare favorably.

And given that dynamic in California, do you see further opportunities in the desert Southwest from a power market perspective in particular in, say, solar? And then also in the Pac Northwest, in wind and hydro, if possible, but more likely just on the wind side?

Yes, there is -- there are several -- Tehachapi isn't the only attractive area to be basically positioned in that particular market if you want to go more broadly than California, just the Western market. Northwest, we just feel that there is a lot of traffic and there's lots of capacity, and the constraint becomes more transmission to get it down to load, which is all located in California.

So if you go east from California, there may be more attractive areas in that particular jurisdiction where constraints on transmission can be addressed more effectively. But I would say there's lots of areas that we are looking at today.

Tehachapi is where we've now been able to secure scale, which I do think it's important. We don't want to spread ourselves across too many sort of jurisdictions and not have the scale to operate effectively.

That's really been more the driver than anything else.

First question, how easy is it to get existing data at Tehachapi in California? Is it available to anyone?

Or is it available once those sign a CA, go into a data room, et cetera?

You mean in terms of buying an asset in Tehachapi?

It could be buying an asset. It could just be looking at assets.

Is it publicly-available data like oil and gas in Western Canada?

No. I would say that a lot of the data comes from operating wind farms that again we have had access to through the actual partnership with Coram.

They have a 22-megawatt facility that has been operating for a long time and has -- we have -- and this is the same area, like this is really, again, it's not necessarily completely correlated, but I would say very closely correlated with what we've bought or built in that area. So again, access is really private in nature.

I don't think there's a public record of that that's available for anybody that wants to check. It's not like water and river flows.

River flows are public data. Wind is not, particularly not in this case.

Okay. Could you comment on the progress on the 99-megawatt wind development project in the Northeastern U.S.

and the early-stage wind development asset in Western Canada that you purchased last year?

Yes. So number one, the wind assets in the Northeast is granite reliable.

It's been commissioned. It's producing exactly as expected.

This is really near Gorham in New Hampshire, and this is kind of in the, I believe, it's kind of a mountainous area. So we built there, I think, with a lot sort of, again, a strong history of data points on wind.

It's contracted. So we're pretty confident about this asset.

In British Columbia, that is really, I think, a project that is almost fully permitted, so it's very well advanced in terms of its development, the one that we actually partnered with and acquired the actual project. That project today, I think, is -- we're looking for a contract.

And should we be able to secure a contract, I think we'd be in a pretty strong position to quickly turn to a construction of that project.

So the situation in BC is contracting more on a one-off basis, not waiting for a call for power?

Well, we'd love to be able to get a BC Hydro contract. We wouldn't build on a merchant basis, to be very clear, so that means we need a contract.

Likely, counterparty to that contract will be BC Hydro. So I think whether it happens sooner or later -- we're just saying the Aeolis acquisition that took place, I think, a year and change ago, clearly is a strong area of -- for wind development -- it had sort of a lot of good things where a lot of engineering and work had been on the project.

So we could potentially start construction on that project very quickly should we secure a contract. That is where we are on that project.

So just focusing on California, once again, in the state, you've got a lot of installed geothermal capacity. And, Richard, you've talked about it in the past.

So I wonder if you can give your thoughts on geothermal in the states, both, I guess, Southern California, Northern California in terms of opportunity?

Well, again, you're absolutely correct that there is a fairly-strong geothermal industry in that area that we would love to be able to participate in. I think this has been something that we've identified would be of great interest to us.

We've also been very clear that we do not have the expertise to just walk in, buy a facility and start a business. We're looking for a platform that essentially can be either a partner of ours or a platform that has those skill sets, which is to find resource, prove the resource and have the expertise to extract the resource in order to have a strong geothermal platform.

So again, although it is very interesting, at this stage, I would say we would have the same handicap or the same problems we have elsewhere in the world, which is we don't truly have that expertise in-house.

Okay, okay, a fair comment. And then in the past, we have talked about international opportunities.

You talked about South America. So are there other regions as well that you are continuing to look for acquisition opportunities or growth opportunities in?

Yes, listen, we continue to look at Australia. I think Australia continues to be a dynamic in terms of renewables and -- that's quite positive, strong growth in terms of its economy, strong currency.

There's lots of things that we find is very positive about Australia. And particularly, our position within Brookfield Asset Management that already exists there allows us to lever that position.

So today, is there something clearly in our sights? I would say not, but clearly, we're trying very hard to find opportunities in that jurisdiction.

Europe, I will just caution everybody that Europe is very complicated. However, we are not turning our backs on any opportunities that are coming from Europe these days.

We would certainly like to invest in countries that have some relative stability in terms of its economy and growth, but either through European companies trying to divest investments that they have elsewhere in the world or through European countries that are stronger and better-positioned than some of the other ones such as Portugal, Spain and Greece. So we are looking at everything because we think this is a very fertile time for opportunities to buy for value.

Interesting. And then finally, Sachin, a question for you on the DRIP.

So you talked about instituting it in the quarter. I wonder if you can talk about what your uptake on the DRIP has been so far?

It's been extremely small to date. And it's only in Canada at this point in time, so we don't offer it yet to U.S.

investors. But our intention is to do so as we file the New York Stock Exchange listing.

Okay. So not a material level at this point?

No. No.

You've only had it for a short period?

Yes.

So just a quick follow-up on acquisitions. So I think in the recent California wind acquisitions, Brookfield Renewable had roughly a 25% economic interest.

And I guess going forward, will BAM and the other partners continue to co-invest and, like, will the economic interest, like, how will the economic interest in the various partners be determined?

Well, just to -- right now, you're absolutely correct that in the investments we've made in California, we've done that with institutional partners. And those are essentially funds that are managed by BAM.

So our interest is about 25%, but I would say that going forward, those funds have finite terms and also finite investment periods. And clearly, Brookfield Americas Infrastructure Fund is certainly, I think, on a very sort of -- its investment in various sectors of the infrastructure space is going extremely well.

So at this stage, we think that this is a model that we'd like to promote. It's served us extremely well because it provides us access to capital and ultimately committed capital on many different fronts.

And when we look at institutional investors, we may sort of continue this model, but at the same time we may take a bigger piece of future funds in order to actually increase from 25% to something greater in the future.

Just one question, Richard. Following up on the previous question, just with respect to the percentage of contracted generation, you touched on everything rolling off in Brazil, and the path you give sort of takes us from 99% to 90% contracted in aggregate.

Do you guys have thoughts on -- I guess, overall, is there a number at which you wouldn't want to go below for the entire portfolio?

Well, thank you for asking that clarification because just to be very clear, is that the likelihood today on the basis of what we own, particularly for the Brazil component, which is coming due. So to get to 90%, I would say 99% of what's coming due is in Brazil.

So to be very clear, is that Brazil will not go uncontracted, it's just a question of when do we put contracts in place. And I've said this in the past, it's a very unique market where almost 4 to 5 years before your contract comes due, you can actually put a new one in place with counterparties either on a -- in the free market or with utilities.

And all we're doing is making a choice that we think pricing will be better in 12 to 24 months to put those contracts in place. But there is no dispatch risk in Brazil, meaning that the requirement for this power is absolute.

If it's not in the market, the lights go out. So there's a great need, the question is just at what price are we going to negotiate the contracts.

So as we roll forward closer to these maturities, you should see that 1,500 or so in 4 years from now, having been contracted up either on the prompt year so we can put a 1 year contract in place, it is unlikely we would put anything shorter, or we could put a longer term contract in place if we like the pricing. So it's a bit of a long explanation, but all I'm saying is that we will not be uncontracted in Brazil, not based on the current market structure and the current market dynamics that we have in front of us.

Well, again, thank you very much for joining us for this first quarter conference call of BRPI, and we look forward to the second quarter. And again, thank you for joining us this morning.