TerraForm Power (TERP) Q2 2019 Earnings Call Transcript

TerraForm Power (TERP)
Q2 2019 Earnings Call
Aug 09, 2019, 9:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

Good morning, ladies and gentlemen, and welcome to the TerraForm Power 2019 second-quarter results webcast and conference call for investors and analysts. [Operator instructions] As a reminder, this conference call is being recorded. I would now like to turn the conference over to your host, Chad Reed, head of investor relations. Please go ahead.

Chad Reed -- Head of Investor Relations

Thank you, operator. Good morning, everyone, and thank you for joining us for our 2019 second-quarter results conference call. I'm joined today by John Stinebaugh, our chief executive officer; Michael Tebbutt, chief financial officer; and Valerie Hannah, our chief operating officer. Before we begin, I'd like to remind you that a copy of our earnings release, supplemental information and letter to shareholders can be found on our website.

Note also that we may make forward-looking statements on this call. These forward-looking statements are subject to known and unknown risks, and our actual results may differ materially. For more information, you're encouraged to review the Risk Factors section in our SEC filings, which can be found on our website. In addition, we will refer to non-GAAP financial measures.

For more information on the reconciliation of these non-GAAP measures to comparable GAAP measures, please refer to our earnings release and supplemental information. With that, I'll now turn the call over to John.

John Stinebaugh -- Chief Executive Officer

Thanks, Chad. Earlier this year, we provided a road map for our growth plan to achieve a 5% to 8% annual dividend increase through 2022 with a payout ratio of 80% to 85% of CAFD. During the quarter, we're pleased to report that we continued to deliver upon this growth plan, including the following highlights. First, we generated CAFD of $47 million or $0.22 per share for the quarter and $91 million or $0.44 per share for the first half of the year, reflecting per share growth of 16% and 29%, respectively.

These results were primarily driven by the accretion from the acquisition of our European platform and our margin enhancement initiatives. We also entered into a definitive agreement to acquire a high quality, unlevered distributed generation platform with approximately 320 megawatts of capacity in the United States, which nearly doubles our DG business and provides significant opportunities for future cash flow growth through operational and commercial synergies. In addition, we completed the transition to long-term service agreements with GE at all but one of our North American wind projects. We're also in advanced stage negotiations to finalize a 10-year agreement to provide outsourced O&M for our North American solar fleet, with the goal of reducing annual operating costs by approximately $5 million through a full-wrap contract that includes resource-adjusted production guarantees that are consistent with our long-term average generation.

We also generated approximately $5 million of CAFD from margin enhancement activities in accordance with expectations. For the full year, we project that we will generate over $30 million of CAFD from margin enhancement initiatives relative to 2018, compared to approximately $53 million from these initiatives at full run rate. Turning to growth initiatives, in July, we entered into an agreement to acquire a high quality, unlevered DG portfolio with approximately 320 megawatts of capacity in the United States from AltaGas for a purchase price of $720 million. We planned to initially fund the acquisition with a $475 million bridge facility and draws on our corporate revolver.

As the portfolio is unlevered, our permanent financing is expected to be comprised of approximately $475 million of project-level debt that is sized to investment grade metrics and proceeds of approximately $245 million from the sale of minority interests in identified North American wind assets. The transaction is subject to customary closing conditions and is expected to close in the third quarter of 2019. We're excited about this transaction as it will nearly double the size of our existing DG platform, increase our average contract duration to 14 years and enhance our resource diversity. In addition, this transaction highlights our strategy to recycle capital from stabilized assets with limited opportunities for further value creation into newly acquired assets that meet our target returns and have commercial and operational upside that we can extract through our integrated operating platform.

The transaction was driven by some key considerations. First, this portfolio features a high-quality asset base in attractive markets. The portfolio represents one of the largest DG platforms in the United States comprised of 291 megawatts of commercial and industrial solar assets, 21 megawatts of residential solar assets and 10 megawatts of fuel cells. Diversified across 20 states and the District of Columbia, with over 100 commercial and industrial customers, the portfolio is comprised of assets with an average age of three and a half years that have power purchase agreements with an average investment grade credit rating of A+/A2 and an average remaining term of over 17 years.

Finally, we expect to generate returns on this investment within our targeted range of 9% to 11%, and we expect the acquisition to be modestly accretive to CAFD in 2020 in over the next five years. Now I'll turn the call over to Michael to discuss financial results and provide a liquidity update.

Michael Tebbutt -- Chief Financial Officer

Thanks, John, and good morning, everyone. In the second quarter of 2019, TerraForm Power delivered net loss, adjusted EBITDA and CAFD of $17 million, $196 million and $47 million, respectively. This represents a decrease in net loss of $11 million, an increase in adjusted EBITDA of $68 million and an increase in CAFD of $17 million compared to the same period in 2018. The improvement in our results relative to last year primarily reflects accretion from the acquisition of our European platform for full quarter and our margin enhancement initiatives.

Consistent with the results reported by certain other renewable power asset owners, TerraForm Power's generation this quarter was 8% below LTA, which reduced CAFD by $15 million, assuming our average realized price for the quarter. Of the $15 million total, $9 million was due to below-average North American wind, primarily in Hawaii, $4 million was due to below-average North American solar irradiance and $2 million was due to a downtime associated with blade repair and other maintenance in our North American wind fleet. These factors were partially offset by strong performance across our European operations and higher-than-expected prices SREC prices in the U.S., which together contributed an incremental $7 million in CAFD. Primarily due to weather, we were not able to complete blade repair work and other maintenance required on certain assets in order to fully phase-in GE performance guarantees.

As a result, we expect modest additional negative impact on our availability in Quarter 3, and we expect to operate at the availability level that underpins our LTA by the end of the third quarter for our North American wind fleet. With regard to our liquidity, in May, we closed the nonrecourse financing of three DG portfolios comprising of 138 megawatts and raising net proceeds of $101 million, which was used to pay down our corporate credit facility. We executed the financing in the bank market with an initial spread of LIBOR plus 200 and a final maturity of 15 years. In addition, we released $8 million of restricted cash by replacing cash-funded debt service reserves with letters of credit across our European platform.

Overall, we finished the quarter with $840 million of corporate liquidity. Now I'll turn the call back over to John.

John Stinebaugh -- Chief Executive Officer

Thanks, Michael. Now I'll provide an update on operations. Over the past few months, we've made significant progress executing an outsourcing agreement for all of our North American solar fleet. We're currently in advanced negotiations on a full wrap LTSA.

The scope of the LTSA would include comprehensive O&M, as well as other balance of plant services for a term of 10 years, with flexibility to terminate early. The agreement would also lock in pricing that is approximately $5 million less than our 2018 cost base and provide availability guarantees that are consistent with our LTA. We anticipate finalizing the agreement within the coming weeks. With respect to implementation of the LTSAs for our North American wind fleet, we've turned over operations of 15 of 16 wind farms to GE.

The final wind farm is expected to be turned over to GE later this summer, at which point we will realize the full cost savings of the GE LTSA. In our Spanish wind fleet, we transitioned operations to new service providers at the beginning of the year under letters of intent. We then executed LTSAs with Vestas in May and GE in July. We anticipate that we will execute LTSAs for the remainder of our Spanish wind fleet with Siemens Gamesa in the coming weeks.

During the quarter, we continue to make progress on our repowerings. We're currently working through a streamlined permitting process with local authorities in upstate New York for our Cohocton and Steel Winds projects. We've had constructive meetings with local stakeholders and hope that we will be able to obtain permits by the end of the year. Given our recent progress, we remain on track to complete the repowerings of both of these New York facilities before the end of 2021.

With respect to our repowering in Hawaii, we continue to negotiate with Hawaiian Electric regarding a blend and extent of our existing contract. In recent procurements of renewable power, Hawaii has shifted to a dispatchable contract structure whereby the project receives a demand charge to cover the fixed costs, including cost of capital, and the utility has flexibility to dispatch the projects within its system. As this framework lowers the risk to the power project, and our project will generate incremental megawatt hours in a discounted greenfield, we believe there is an opportunity to provide savings to ratepayers while the project earns an acceptable return on its capital. Moving on to legal and regulatory updates, in June, we received a favorable ruling from the panel overseeing the arbitration in our Chile project.

The dispute with the project's offtaker had been ongoing since 2016 and concluded with a unanimous ruling in our favor and a comprehensive rejection of the claims of the plaintiff. Now that this issue has been resolved, we can focus on working with our project lenders to release $15 million of cash that is currently trapped within this project. In Spain, current Prime Minister and leader of center-left Socialist Worker's Party, Pedro Sanchez, has been unable to assemble the majority he needs to form a new government, despite having recently won an increased number of seats in congress. Prime Minister Sanchez and the PSOE are expected to negotiate in a second round with potential governing parties in an attempt to form a new government before the September 23 deadline.

If they're unable to do so, the King of Spain will likely call for new elections in November. According to recent polls, public sentiment suggests that the PSOE will lead the new government even if elections are held. We continue to believe that the political environment in Spain is positive for the regulated rate of return for renewable assets as renewables enjoy broad support across the political spectrum. As we look forward, amid slowing economic growth in the specter of a prolonged trade war, the U.S.

Federal Reserve announced its first interest rate cut in more than a decade, while the 10-year U.S. Treasury Bond yield has declined to below 2%. Similarly, in Europe, the ECB is considering new measures, including forms of quantitative easing to stimulate growth as industrial production decelerates rapidly. In light of this, we anticipate a low interest rate environment in our target markets of North America and Western Europe for the foreseeable future.

With investor appetite for yield, we believe renewable power assets with long-term contracts will continue to be bid at high valuations. TerraForm Power uses a number of strategies to counteract these dynamics and acquire companies and assets for value. First and foremost, we leverage Brookfield's global business development team to originate off-market transactions. We also focus on finding multifaceted transactions such as Brookfield's initial investment in TerraForm Power that lend themselves to bilateral negotiations in which we can structure a transaction to meet the needs of various stakeholders.

Finally, we look for contrarian investment opportunities such as the acquisition of our European platform, in which a particular asset class or geography is out of favor. Over the past year, we've been focusing on the DG sector because we can earn a premium -- a written premium of up to a couple hundred basis points relative to utility scale projects with similar contract durations due to smaller individual project size, greater number of customer relationships that must be managed and less familiarity with recontracting dynamics. In the case of our pending acquisition of the AltaGas DG portfolio, the seller ran a process whereby bidders had to submit binding offers on an accelerated time line. We leveraged significant resources within Brookfield and TerraForm Power to complete our due diligence within this time period.

As other participants in the process were not able to do so, we faced limited competition. We underwrote the transaction to earn returns within our targeted range based upon conservative cash flows. Our returns are anchored by the 17-year average remaining term of existing contracts. With 35 years of asset life, the portfolio is well-positioned to capture value beyond the initial contract term.

As roughly half of the portfolio is behind the meter, we should be able to renew contracts at levels that offer significant savings to customers relative to retail tariffs or the new-build cost of distributed generation. Remainder of the portfolio primarily consists of ground-mount structures located within the distribution system where land is scarce and our assets are somewhat insulated from potential overbuild of renewals. Going forward, our business plan is to reduce cost by leveraging the scale of our combined 750-megawatt distributed generation portfolio. We will also seek opportunities to extend the life of our existing contracts at rates that exceed our underwriting assumptions and to extract incremental value from the portfolio by cross-selling products such as storage and back-up generation to commercial and industrial customers.

This concludes our formal remarks. Thank you for joining us this morning. We'd be pleased to take questions at this time.

Questions & Answers:

Operator

[Operator instructions] Our first question comes from the line of Moses Sutton with Barclays. Your line is now open.

Moses Sutton -- Barclays -- Analyst

Good morning. Hey, how's it going? Can you provide a range of the yield you expect on selling minority stakes in the North American wind assets, just thinking about how much accretion in CAFD you can get? And I'm not sure, but can you identify which regions you're targeting for the minority stakes or have you not actually picked the region yet?

John Stinebaugh -- Chief Executive Officer

In terms of the assets that we're looking to sell, we haven't publicly disclosed which ones, but we're looking to sell minority stakes where TerraForm would continue to operate the assets. And I'd say that it's a portfolio of wind farms that have got average remaining contract life of around 14 years. So we think the combination of that with the GE contract, the performance guarantees and the full wraps that it provides, the cash flow profile should be pretty attractive to institutional investors. So in terms of the target yield or price that these assets should go at, I'd say that in the market today, we're generally seeing that these types of projects are probably going for IRRs that are between 7%, 8%, somewhere thereabouts and then the CAFD yields are probably a little bit higher than that.

Moses Sutton -- Barclays -- Analyst

That's very helpful. And as a percent of CAFD over time, how comfortable are you or maybe it's even better going as higher in DG? It's definitely an attractive market after this deal. Maybe the total percent of CAFD is around 25%. Would you go to 30% or higher just thinking of your thoughts as you view that market here in the U.S.?

John Stinebaugh -- Chief Executive Officer

We do like the market for the reasons that I've talked about. We think that, generally speaking, you can get up to a couple hundred basis points premium written for DG versus our utility scale. And we also think that there are synergies with the scale of the portfolio that we've got. Brookfield recently hired a DG development team.

And what we're looking to do is basically come through the 750-megawatt portfolio of DG that we've got and identify opportunities to deploy storage, potentially back-up generation, potentially expansions or repowerings of existing solar rays. Over the next six months, we're going to try to scope out the opportunity and prioritize what we think the magnitude of that opportunity is. So we'll be providing more color as we go through and get a better handle on what we think the potential upside is with that process. But in terms of overall concentration of the portfolio, I'd be interested in acquiring more DG.

I think the one challenge though with DG is to find portfolios of the size of the AltaGas portfolio is pretty rare. So DG acquisitions tend to be in smaller bite size. So I think that kind of sort of limit the size of concentration or contribution that DG will have to the overall portfolio.

Moses Sutton -- Barclays -- Analyst

Got it. That's very helpful. And last one for me and I'll jump in the queue. Investors are starting to give good recognition of your initiatives.

Might it be the right time to consider an equity issuance or at least think about the timing of one, even a modest one? The thought being you'd be able to bring down leverage even faster and/or you'd have more dry powder for Brookfield-sourced M&A. Just wondering your thoughts on the broader -- how you work with the equity markets.

John Stinebaugh -- Chief Executive Officer

That's a good question. In terms of achieving our business plan through 2022, we've been pretty clear that we can achieve the growth targets that we've got through the margin enhancements, a modest amount of organic growth and add-on acquisitions, and we don't need to issue equity in order to accomplish that. I think that where you would potentially consider us or see us issuing equity is if we have an attractive use of proceeds where we can issue equity and do a larger size transaction that is going to be accretive to unitholders or, alternatively, potentially, if we have got significant enough of a backlog of opportunities where we're confident, we will be able to deploy that capital. So I think it's going to be more to issue equity if we have opportunities to grow beyond what we've got in the existing business plan on an accretive basis.

Moses Sutton -- Barclays -- Analyst

That makes sense. Thanks.

Operator

Your next question comes from the line of Nelson Ng with RBC Capital Markets. Your line is now open.

Nelson Ng -- RBC Capital Markets -- Analyst

Thanks. Good morning, everyone. Sounds good. Thanks.

Just a quick question on your -- on the minority -- sale of minority interests. How far along are you on that process? Like, should we expect to hear something in Q4?

John Stinebaugh -- Chief Executive Officer

I think Q4 is probably premature. What I would say is that we have identified assets. We're in the process of kicking off a sales process for those minority interests in the projects, but these things do take time to prepare to go to market, go to market and then execute. So I would say that an announcement of a sale in Q4 is probably a little bit sooner than we would anticipate.

I would think it would be probably at the beginning of next year.

Nelson Ng -- RBC Capital Markets -- Analyst

OK. Got it. And then is the ideal scenario where you sell, let's say, 49% of some projects and then you kind of manage -- you had managed the asset and earned some sort of a management fee? Or are you looking at a smaller minority, I'd say, like, 20% to 30%? Or is that -- are you fully flexible in terms of those options?

John Stinebaugh -- Chief Executive Officer

I think it could be anywhere within that range, but the key thing you mentioned is these are assets that we would be interested in continuing to operate. We would earn modest operating and maintenance fees and asset management fees for doing it, but it would enable us to continue leveraging our operating platform. So I'd say that it would be in that range. In order to sort of match-fund the acquisition of the AltaGas DG portfolio, it's probably at the higher end of that range.

Nelson Ng -- RBC Capital Markets -- Analyst

OK. Got it. And then just on asset recycling, I was just wondering -- you've mentioned a minority interest, specifically in North American wind. But I was wondering whether you're considering the sale of other kind of noncore assets, whether it's solar assets in Chile or elsewhere or whether it's like a minority interest of some utility scale solar.

Could you just comment on why wind in North America versus other technologies in various regions?

John Stinebaugh -- Chief Executive Officer

Sure. The overriding strategy that we've got is to sell assets that are stabilized where we've extracted pretty much all of the operational upside in terms of being able to reduce costs, in terms of being able to improve performance. And we have got a stable cash flow stream going forward that is in high demand by the institutional market. We think that by selling those kinds of assets, we can get good execution.

It represents a low cost of capital for us, and we can then reinvest that capital in investments where we can earn higher returns and we can leverage our operating platform for further upside. So that sort of what we're looking to do. What I would say is, in terms of noncore assets, the asset in Chile is potentially one that it's noncore from a geographic standpoint. As we've gotten through the arbitration, we have eliminated sort of what, I guess, was a major question mark for that asset.

So that's something that we would consider if we can get the right price for it. Cost of capital in Chile right now is still pretty strong.

Nelson Ng -- RBC Capital Markets -- Analyst

OK. And then just a quick follow-up on the Chilean asset. Could you give a bit more color in terms of what the dispute was about? And if it was with the offer, as you mentioned, does that make the asset less attractive given that there is -- given that the project is in dispute with the -- or was in dispute with the offtaker?

John Stinebaugh -- Chief Executive Officer

So the dispute was regarding how the asset was maintained and whether it was being operated in compliance with prudent operating standards for renewable power plants. We won, as we mentioned, a unanimous decision with the panel, and they rejected all the claims of the offtaker. So I think with that, it did send a strong signal regarding our position in that instance and, I think, because of that -- I wouldn't really see that there would be any sort of overhang, but by the same token, that's why we felt it important to resolve that because we felt we did have a strong case before looking to potentially do anything with that asset.

Nelson Ng -- RBC Capital Markets -- Analyst

OK. Got it. OK.

Operator

Our next question comes from the line of Mark Strouse with JP Morgan. Your line is now open.

Mark Strouse -- J.P. Morgan -- Analyst

Yeah. Good morning. Thank you very much for taking our questions. So just with respect to the share buyback authorization, can you just talk about how you intend to weigh buybacks versus potentially repaying debt? And does the buyback potentially impact your expected timing of achieving investment grade rating?

John Stinebaugh -- Chief Executive Officer

So first of all, that was basically just a renewal of the buyback that we previously had in place. And we think it's just good practice to always have a buyback in place if there are events similar to December of last year that happened where acquiring our stock is a very good use of proceeds. The way we generally think of buybacks is it's part of capital allocation. It's an opportunity to invest capital.

And if we think that that's a better opportunity than investment opportunities we see in the marketplace, it's something that we would consider. So I wouldn't take this as any more of a signal than we had a buyback authorization in place, we renewed it, and we think it's just something prudent that we should have in place in case conditions merit. This doesn't really impact our view of the delevering of our balance sheet. I think what we've said in the past is that by 2022, 2023, we want to be strong BB.

We've articulated a goal of getting down to between four to five times holding company debt to CFADS. And we think that with a full year of our European platform and margin enhancements, we should be under five times. And then over the remaining years, we look to strengthen that to between four to five times. So anything with respect to this renewal of the buyback would not impact our plans or objectives with respect to deleveraging.

Operator

Our next question comes from the line of Colin Rusch with Oppenheimer. Your line is now open.

Colin Rusch -- Oppenheimer and Company -- Analyst

Thanks so much, guys. Can you talk a little bit about the uncontracted capacity and what your plans are for that? How should we think about your tolerance for repurchases in the emerging markets going forward?

John Stinebaugh -- Chief Executive Officer

Sure. In terms of uncontracted capacity, we don't have very much in the portfolio. Right now, we are 96% contracted. And if you look at what is uncontracted, it's largely associated with some of the projects that have hedges where you can't really hedge 100% of the output.

Our objective is to basically have a portfolio that is largely contracted and to the extent that we do have contracted -- or projects that come off contract to recontract those. I wouldn't see us materially changing the contract profile that we've got by acquiring significant amounts of merchant capacity. To the extent there's merchant capacity in a portfolio that we acquire potentially, we would do that, but I wouldn't see us significantly changing our strategy in terms of the types of assets we're looking to buy.

Operator

Our next question comes from the line of Ben Pham with BMO. Your line is now open.

Ben Pham -- BMO Capital Markets -- Analyst

OK. Thanks. Good morning. First question is on operational numbers that you've provided.

Resource condition is a bit weak during the quarter. You had about a $15 million CAFD impact, which seems pretty significant. So I'm curious more if you've seen this LTSA and the wrap. I mean, is there a the way we should think about it? Is there any -- like how much of that CAFD could you mitigate, if at all? Or is that all variability you're still going to take even with these full-wrap programs you have?

John Stinebaugh -- Chief Executive Officer

The best way to think about it is the LTSA with GE on the wind side, as well as what we're negotiating on the solar side. They don't address resource risk. What they do, do though is they guarantee for a level of resource that we will have a production that is consistent with the availabilities that underpin our LTAs. So if we had in a particular period P50 resource, what these contracts would do is provide guarantees that we would produce our LTA.

So in other words, they're sort of guaranteeing the power curve, but they are not guaranteeing the resource.

Operator

Our next question comes from the line of Praful Mehta with Citigroup. Your line is now open.

Praful Mehta -- Citi -- Analyst

Thanks so much. Hi, guys. All right. So maybe just trying to understand in terms of the financing, was there a tax equity structures or tax equity financing that you would also consider around how you would finance this acquisition? And why not if you're not kind of going in that direction?

John Stinebaugh -- Chief Executive Officer

The portfolio basically has some assets where there was tax equity for the remainder of it. The seller was basically utilizing the tax benefits. So given the vintage of the portfolio, we're buying assets with roughly three and a half years of age, there's not really an ability for us to put tax equity on at this point, which is why what we're looking to do is to basically utilize nonrecourse debt with investment grade metrics.

Praful Mehta -- Citi -- Analyst

All right. I gotcha. That's helpful. And then in terms of tracking through your guidance --[Technical Difficulty]

John Stinebaugh -- Chief Executive Officer

We lost you. Operator, I think he --

Operator

I think Mr. Mehta is now again on the phone.

John Stinebaugh -- Chief Executive Officer

OK.

Praful Mehta -- Citi -- Analyst

Sorry, should I repeat the question?

John Stinebaugh -- Chief Executive Officer

Yes. I did not hear you.

Praful Mehta -- Citi -- Analyst

Sorry. So I was just asking about the impact of all the blade repair work and weather and all of that. I just want to understand how does that flow through to EBITDA and CAFD for the year? How are you tracking for EBITDA and CAFD for the year?

John Stinebaugh -- Chief Executive Officer

In terms of the way work and other maintenance that were accelerating, we are anticipating getting done with all of that by end of August, might be a little bit into September depending on weather. As a result, we think in Q3, there should be some modest impact on availability as we're finishing up that maintenance work. But as we said in the shareholders letter, we anticipate roughly about $30 million of the margin enhancement activities for the year. So that, I think, gives you sense in terms of the contribution from the margin enhancement activities.

In terms of the impact on availability, there was a modest impact on availability because of the O&M work on blade and other in Q2 roughly about $2 million. And I would expect a modest impact in Q3, but that then would be complemented by the $30 million of benefit from the margin enhancements we anticipate for 2019.

Operator

Our next question comes from the line of Angie Storozynski with Macquarie. Your line is now open.

Angie Storozynski -- Macquarie Research -- Analyst

Thank you. Let's have a bigger -- bigger-picture question. So I'm mostly interested in your Northeast wind assets. So we've seen a step change in conventional power prices in the Northeast.

We are seeing lots of new contracts underpinning offshore wind capacity that's going to hit the Northeast both from the, like, the energy and capacity perspective. So how do you see, especially those Northeast wind assets, onshore wind assets that you currently have, the value of these assets going forward? How do you think about the renewing some of the energy hedges? What are your views about REC prices in Northeast? And if this very portfolio would be largely slated for divestitures because of all of these reasons I mentioned earlier?

John Stinebaugh -- Chief Executive Officer

Sure. So in terms of the Northeast assets, we do think that the region is going to see favorable RPS regimes, and you've seen increases in RPS regimes in a number of the states within the Northeast. And if you think about the procurement that the states will have to do to satisfy those RPSs, it may well have to -- and you're starting to see that offshore winds is going to be a pretty important part of the mix. We do think that's positive in the sense that -- to the extent that you have offshore, which has required higher power prices that's required for the mix and presumably that should benefit the repowerings that we have where we can produce megawatt hours at a discounted greenfield.

We should be able to benefit from the demand that RPS is creating. So one thing that I do think is, as we've talked about in the past, with our repowerings, we have gone forward on the basis that we just get power prices that are based upon hedges that don't include any premium for the renewable power. It does reflect that we get a NYSERDA REC split under the current regime. So if there's any positives with respect to either a more favorable NYSERDA REC regime or what has been passed in the senate, as well as house in New York that would provide incremental benefits for existing generation or, alternatively, if the RPSs lead to greater demand for renewable power, all of that, we think, will benefit our repowerings and could well benefit the other assets we've got in the portfolio.

So we look at that generally as a positive. And I think you were asking about would we consider selling those assets. I'd say, we certainly want to extract all the value that we can before looking to recycle. So we certainly want to get through any repowerings of the New York assets, as well as any other assets that we think in the portfolio could lend themselves to repowering the Northeast before looking to recycle them.

Operator

We have no further question at this time. I will now turn the call back to the presenters.

Chad Reed -- Head of Investor Relations

Thank you, operator. Thank you, everyone, for joining us. This ends our call.

Operator

[Operator signoff]

Duration: 41 minutes

Call participants:

Chad Reed -- Head of Investor Relations

John Stinebaugh -- Chief Executive Officer

Michael Tebbutt -- Chief Financial Officer

Moses Sutton -- Barclays -- Analyst

Nelson Ng -- RBC Capital Markets -- Analyst

Mark Strouse -- J.P. Morgan -- Analyst

Colin Rusch -- Oppenheimer and Company -- Analyst

Ben Pham -- BMO Capital Markets -- Analyst

Praful Mehta -- Citi -- Analyst

Angie Storozynski -- Macquarie Research -- Analyst

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