NRG Energy Inc (NRG) 2019 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the NRG Energy Inc.'s First Quarter 2019 Earnings Conference Call.

(Operator Instructions) As a reminder, this call may be recorded.

I would now like to introduce your host for today's conference, Kevin Cole, Head of Investor Relations.

Please go ahead.

Thank you, Danielle.

Good morning, and welcome to NRG Energy's First Quarter 2019 Earnings Call.

This morning's call will be 45 minutes in length and is being broadcast live over the phone and via webcast, which can be located in the Investors section of our website at www.nrg.com under Presentations & Webcasts.

Please note that today's discussion may contain forward-looking statements, which are based on assumptions that we believe to be reasonable as of this date.

Actual results may differ materially.

We urge everyone to review the safe harbor in today's presentation as well as the risk factors in our SEC filings.

We undertake no obligation to update these statements as a result of future events, except as required by law.

In addition, we will refer to both GAAP and non-GAAP financial measures.

For information regarding our non-GAAP financial measures and reconciliations to the most directly comparable GAAP measures, please refer to today's presentation.

And with that, I'll now turn the call over to Mauricio Gutierrez, NRG's President and CEO.

Thank you, Kevin.

Good morning, everyone, and thank you for your interest in NRG.

I'm joined this morning by Kirk Andrews, our Chief Financial Officer.

Also on the call and available for questions, we have Elizabeth Killinger, Head of our Retail Mass business; and Chris Moser, Head of Operations.

I'd like to start the call by highlighting the key messages for the first quarter on Slide 3. First, our business performed well during the quarter and in line with expectations, demonstrating the value of our integrated platform.

We're also reaffirming our 2019 guidance ranges.

Second, our integrated business is well positioned for summer operations, and the fundamentals in our core markets are getting stronger.

Finally, we are on track to achieve our 2019 capital allocation goals.

Complete our current $1 billion share repurchase program, achieve our new credit metrics by year-end and provide you clarity on the remaining $872 million of excess cash by the third quarter earnings call.

Moving to Slide 4, I want to review the financial and operational results for the quarter.

We achieved top quartile safety performance and delivered $333 million of adjusted EBITDA.

On the right-hand side of the slide, we have provided our EBITDA on a same-store basis due to the changes we've had in our generation portfolio, either through asset divestitures, retirements or deconsolidations.

Our EBITDA increased by 15% from the same period last year, driven primarily by cost savings, higher realized power prices, partially offset by increases in retail supply costs.

It is important to note that the distribution of our earnings has also changed with the third quarter now responsible for a larger percentage of earnings.

Recognizing all of these changes, Kirk will provide additional details on the quarterly results in his section.

We continue to make progress on our cost savings and margin enhancement targets.

I am pleased to report that during the first quarter, we achieved $20 million of margin enhancement, and that all Transformation Plan targets remain on track.

We also completed $500 million of our current $1 billion share buyback program during the quarter, repurchasing over 4% of our market cap at an average price of $42.21 per share.

We remain committed to returning capital to shareholders and plan to complete the remainder of the current $1 billion share repurchase program in 2019.

Finally, we are getting ready for summer operations with an expanded spring outage program on our generation fleet and the activation of our summer readiness program across the company.

These measures are taken to ensure NRG is able to provide safe and reliable performance during the summer months.

Now turning to our market update on Slide 5. Starting with ERCOT, the supply-demand balance remain the tightest it has ever been following some plant retirements and sustained load growth.

The chart in the upper left, which we first introduced on the fourth quarter call, shows how future reserve margins are dependent on new builds, particularly wind and solar.

A closer look at this new capacity for 2020 and 2021 is in the table below.

It highlights the lack of viable new builds necessary to keep pace with ERCOT's 2% annual demand growth.

We see limited wind developed, given transmission constraints, and the few large gas projects remaining in the CDR have already been delayed by an average of 4 years.

We do, however, expect the majority of solar to be completed as purchase power agreements are executed, but remain skeptical of significant merchant development, given economics.

Both the PUCT and ERCOT understand the situation and have taken steps to improve the energy-only market to better reflect the scarcity conditions in the system.

We believe these changes will have an impact on forward prices, eventually helping justify the long-term investments necessary to increase the reliability of the system in the long run.

On the right side of the slide, we highlight our readiness for this summer and the steps we have taken to further strengthen our integrated portfolio.

Starting with Retail.

We are proactively educating our residential and business customers and providing them with options and tools to manage higher energy bills.

We're also providing energy conservation alerts and enhanced demand management options.

Moving to Generation.

As part of our summer readiness program, we are planning to return to service our Gregory plant, which has been offline since the fall of 2016 due to the bankruptcy of the steam host.

This is 385 megawatts of combined cycle capacity that provides additional reliability to the ERCOT system ahead of the summer.

Last, while our platform today is best positioned to provide more predictable results relative to pure retailers or wholesale generators, we continue to take prudent steps to further enhance our ERCOT business.

Given our scalable platform and track record of integrating new businesses, we expect that higher volatility in the market creates an opportunity to acquire small- to medium-sized customer books and platforms at value.

And as discussed last quarter, our Generation, or supply business, must grow with Retail.

We are well underway in executing our PPA strategy to complement our physical assets.

This strategy allows us to better serve our customers, improves our position management and it is capital-light.

I will provide a more comprehensive update on the next earnings call.

Now moving to the East markets on Slide 6. The focus remains on regulatory changes.

Since our fourth quarter call, FERC has directed PJM and NYISO to implement tariff changes for fast-start resources.

This allows a whole new class of assets to set price.

I mean, this is a clear positive for energy price formation in the East.

PJM has also announced its intent to run the 2022/23 capacity auction in August under the existing market rules.

The timeline for FERC action remains uncertain, but we remain confident that FERC will protect the integrity of competitive markets.

We continue to view a strong MOPR as the simplest and most effective way to reduce the harmful impact of nuclear subsidies in the market.

In ISO New England, a proposal has been put forward that would compensate generators for fuel scarcity.

We continue to believe these changes are positive for fuel security reforms overall.

However, reform is coming too slowly, and the current ISO New England fuel security proposal pending at FERC is insufficient.

We look forward to working with the ISO on this matter.

Moving to the right side of the slide.

We highlight the strength and diversification of our Northeast portfolio.

Our existing portfolio is primarily large capacity and fuel-resilient generation located in key load centers and provides a solid foundation for continued growth of our Retail business in the region.

While the regulatory activities in the region provides some uncertainty, we're optimistic about these regulatory outcomes and, more importantly, believe our integrated business is well suited to succeed in the region.

With that, I'll turn it over to Kirk for the financial review.

Thank you, Mauricio.

Starting with the summary of financial results you'll find on Slide 8, consolidated first quarter EBITDA was $333 million, with $153 million from Retail and $180 million from Generation.

The bar charts in the center of this slide provide a walk from our first quarter 2018 consolidated EBITDA to this quarter's results.

Starting on the left side of this chart, we start with first quarter 2018 consolidated adjusted EBITDA of $336 million.

Next, in order to arrive at an appropriate basis for comparison to 2019, we eliminate the impact of asset sales, retirements and deconsolidations from our first quarter 2018 results.

The total EBITDA impact of these items is $47 million and is comprised of 4 elements: one, Ivanpah and Agua Caliente, which were fully consolidated in our first quarter '18 results before circumstances required a change in accounting later in 2018 to equity method; second, BETM, which was included in our first quarter 2018 results, but was sold later in the year; third, the pro forma impact of the Cottonwood lease, which began in early 2019 following the sale of the South Central portfolio; and finally, EBITDA from the Encina facility, which was retired when the Carlsbad plant was brought online at the end of 2018 and sold to Clearway.

Deducting the $47 million impact of these items from first quarter 2018 results provides a baseline for comparison to our reported results for this quarter.

From this new baseline, we address the quarter-to-quarter changes, starting with 3 elements related to the Transformation Plan initiatives.

First, we incurred $15 million in incremental SG&A expense related to margin enhancement programs.

We expect to begin to produce results later in 2019.

Next, we realized $20 million in EBITDA from our margin enhancement programs during the first quarter.

And third, having delivered $80 million in Transformation Plan cost savings in the first quarter of 2018, we realized $130 million in savings this quarter or an incremental increase in savings of $51 million.

Turning to Retail.

Non-Transformation Plan Retail results for the quarter were $58 million lower, primarily due to increased supply costs and more favorable weather in the first quarter of 2018, which were partially offset by EBITDA from the XOOM acquisition.

Finally, Generation results for the quarter were $46 million higher, primarily due to higher realized prices during the quarter.

Both the higher Retail supply costs and higher realized prices in Generation are in part the result of intersegment power sales between Generation and Retail, which are typically based on average annual power prices.

As power prices in ERCOT have become increasingly seasonal, with lower prices during the shoulder periods, such as the first quarter, and higher prices during the summer, the resulting annual average price implies a premium to observe pricing in the shoulder periods and a discount to pricing seen in the summer.

The annual supply cost for Retail and annual revenues from Generation, which result from these intercompany sales based on average annual prices, will be no different than if those intercompany transactions were executed based on quarterly or seasonal pricing since these prices form the basis for the annual average price used.

As our consolidated results of $333 million for the quarter were in line with our expectations, we're reaffirming our 2019 guidance ranges.

Turning to Slide 9. While our capital allocation plan for 2019 is unchanged from our previous update, we have now completed the first half of our $1 billion 2019 share buyback program we announced in late February and will continue to repurchase shares to complete the balance of that program.

We continue to expect $872 million of yet-to-be-allocated excess capital in 2019, which will become available later this year as we generate the bulk of our free cash flow during the third quarter.

We expect to provide an update on the intended use of that excess capital by our third quarter earnings call.

Finally, we remain focused on our revised target investment-grade metrics in 2019, as shown on Slide 10, and are on track to achieve those metrics, including using up to $600 million in 2019 capital previously allocated to further reduce balance sheet debt.

And with that, I'll turn it back to you, Mauricio.

Thank you, Kirk.

Now turning to Slide 12, a few closing thoughts on our 2019 priorities and expectations.

I'm very excited for 2019 with another year of strong execution.

Our top priority is to further demonstrate the predictability of our integrated platform, achieve our new investment grade credit metrics and deploy the nearly $900 million of remaining excess cash, adhering to our transparent capital allocation principles.

We also remain on track on all of our Transformation Plan targets, particularly as we continue to ramp up our margin enhancement initiatives throughout 2019.

Our company today is stronger than it has ever been.

And as I look to the summer and beyond, I am confident our platform is best positioned to deliver predictable results and create significant shareholder value in the long run.

So with that, I want to thank you for your interest in NRG.

Danielle, we're now ready to open the line for questions.

(Operator Instructions) And our first question comes from Julien Dumoulin-Smith from Bank of America.

So I want to follow up on a couple of quick things here, if you don't mind.

First, perhaps this is more of a financial detail question.

On the allocation question that you just raised across the year, what does that mean for the balance of the year, specifically looking at third quarter, more from a year-over-year perspective as you think about it?

Should we expect more of a positive impact on 3Q than you would've otherwise expected for the Retail segment specifically this year?

Yes.

I mean, if you think about it now, with the changes in our portfolio, the distribution of our earnings are now peak year for the summer months.

And particularly, with the intersegment, I mean, you're going to see an average impact of the prices.

While prices have increased in Retail, I guess, power prices have increased for the entire year.

Just given the peakiness of the summer, you're going to see that impact in our result.

Kirk?

Yes.

And I think I agree with that.

In isolation, when it comes specifically to the impact of the intercompany transfer, the dynamic that Mauricio described is correct from a standpoint of year-over-year supply cost specifically related to that transfer.

Overall, certainly, as you know, one, the third quarter, on a consolidated basis, is increasingly, as Mauricio said, the strongest contributor by far to our results.

And so overall, you may see the overall comparison on Retail and Generation in that quarter overall being similar to the directions that you see on Slide 8 for the first quarter.

But within that, going back to what I said in the first place, the supply cost related to the intercompany transfer will have the opposite comparison, as you indicated.

But there's obviously a lot more than just intercompany transfer that contributes from our result.

So we certainly expect Generation to be relatively robust and just the overall EBITDA to be more significant than any other quarter of the year as it typically is in the third.

Yes.

absolutely.

Following back to more of the fundamentals of the core business, can you provide a little bit more of your thoughts on what the impact of a full FRR would be to Midwest Gen portfolio?

I appreciate that you've provided some Reg G segment-specific disclosure, but I would be curious on how you think about that and financial impact and potential other plant decisions out in the forward years?

And then separately, Mauricio, can you elaborate very quickly on your commentary about procurement and renewable procurement potentially later this year?

Sure.

Well, let me start first with the impact of full FRR.

And I'm assuming that your question is just specific about Illinois and the impact that it has on our Midwest Generation portfolio.

So before I turn it over to Chris for additional details, let me just say that, first, you have to put it in context.

I don't think the outcome is a binary outcome, where one loses and the other one wins.

We know that our Generation is needed for the ComEd zone to maintain -- or to meet the expected load.

With respect to the FRR, I mean, states have always had the right to FRR completely if they wanted to.

The specifics about how this time around it will be done is less clear.

There is a lot of speculation whether certain units can FRR, whether the entire market needs to FRR.

There is a lot of -- there are a couple of considerations there.

Remember, Illinois has Retail choice, so it will be very difficult to FRR the entire region.

But regardless of what path that they take, we feel very comfortable that, under the status quo, we are okay.

If they decide -- if FERC decides to implement some sort of RICO, Resource Carve Out with repricing, I think we're better off.

And if they decide to do an FRR, we don't have enough information to assess what the impact would be.

But it's not 0 since our units are needed.

But with that, Chris, I don't know if there's anything else that you want to add.

No.

I would -- Julien, this is Chris.

I would echo what Mauricio said, which is the details are going to matter and which path FERC ends up taking and Illinois ends up taking are going to matter.

What I will just echo here is that, hey look, in a 25,000-megawatt zone, they still need a big chunk of our units to clear that zone and to cover the load reliably.

So I know that we've outlined kind of the impact of Midwest Gen, what percent it is of their earnings in earlier calls and/or presentations.

And I would say I would expect that anything -- any impact would be a fraction of that.

Yes.

I mean, we've said that in -- approximately, it's about 5% of our total EBITDA, so let's just put it in context what the impact would be.

But again, I think the important thing, this is not a binary outcome, a zero-sum game.

With respect to your second question about the PPAs, we introduced our capital-light PPA strategy in the last earnings call.

The team has made really good progress.

We're in the middle of executing that right now, but we're not done yet.

So where I am going to be providing you more specifics around the progress on that strategy by the next earnings call because, and as I hope you can appreciate, we're in the middle of execution.

And I don't want to impair our ability to get the best value on those -- on that strategy.

And our next question comes from Greg Gordon from Evercore ISI.

Just looking at the math here on the cost savings.

It appears to me, and I just wanted to confirm this, that you had $532 million achieved in '18.

And the slide deck shows you have $51 million incremental achieved in Q1.

So the target's $590 million and your basically at $583 million, so that would corroborate your view that you're pretty much on point on getting to the cost savings, right?

Or am I not -- am I reading that correctly?

I think, overall, that's a reasonable way to interpret in terms of the uptick.

What you have mentioned that is the case with respect to certain portions of the cost savings, is they aren't realized on a levelized basis across the year because some of our costs, specifically on -- especially on the O&M side, are seasonal in nature.

So you'll see variability in the realized cost savings quarter-over-quarter.

But going back to your original observation, yes, the incremental increase is a good barometer to see, to measure that we're on track towards getting to that $590 million run rate in 2019, which is embedded in our guidance.

Great.

And it's a little bit difficult to suss out from your slides where you are on a gross margin basis for the year relative to the target because you give us -- now you're giving us 2Q '19 through 4Q '19 expectation of $1.025 billion on Page 19, but it's hard to compare that with the original guidance that was given of $1.176 billion in the Q4 deck just because you didn't give us what you actually achieved in Q1.

But is it fair to say that you haven't called anything out there, so that you're still on track to hit that gross margin target?

Overall answer to that question is yes.

As I said, the quarterly results of $333 million, as I said, were in line with our expectations.

And you're right.

I mean, the realized gross margin, which I think you'll -- we'll be filing the Q later today with the details around the MD&A what the gross margin is by segment.

So that, when combined with the outlook over the balance of the year, is decided on '19 is being the best way to confirm that.

But overall, your overarching statement is correct.

We are on track, and that's part of why we're reaffirming the guidance today.

Last question.

And this is a bit of a speculative one, so I appreciate it if your limited it in how you can answer it.

If we have a super volatile summer in Texas this year, given that your book is, for the most part, balanced, would it be your expectation that that's sort of a theoretically significant upside opportunity for the company?

Or do you think that the opportunity to generate significantly higher wholesale margins, but that the Retail performance would sort of balance that out?

And you might do a little better, but you're not really a net long in the market, right?

Is it your goal to just be able to consistently deliver operating results in all types of market environments with limited volatility rather than sort of positioned to just get a one-time benefit from a volatility event?

Yes.

Well, that is exactly what I was about to say, Greg.

Our goal in rebalancing the portfolio and integrating Generation and Retail is to be able to provide predictable earnings in a number of market conditions.

So if there is an extreme scenario in Texas, let me just, I guess, provide a little bit more specificity.

All our price load is hedged.

So by -- when we go into the summer months, you have to know that our retail exposure will be completely hedged.

On the Generation side, we always carry a little bit of excess Generation to manage operational risks.

So to the extent that our units perform well, we're going to have more that is exposed to the market.

And if you see really high prices, we'll benefit from that.

If our units operate less, we have a buffer to be able to manage that and not be exposed to high power prices.

So overall, the goal of the -- the goal for us in the summer, and for that matter on any season, is to continue providing predictable earnings with these complementary and countercyclical businesses of Generation and Retail.

Okay.

But it sounds like the way that you've hedged your book, a volatility event would allow you to run the assets that -- where you do have length at higher load factors, at higher prices.

And so they're -- and given that you're hedged on the Retail side, there actually might be a modest benefit to the overall system performance?

Yes.

Very discretely, I would say the modest benefit is probably the better way to think about that in certain -- within that bandwidth of reasonable scenarios, as Mauricio said, it depends on the load that we have not yet locked in, in price, right?

We have -- there's 2 determining factors there.

One is the price to the customer of that load, and we're obviously very sensitive to that because we're in the business of maintaining our customer base.

And two is the supply cost that you realize when you lock that in, right?

Obviously, the latter of those 2 scenarios is going to be driven by the evolution of prices in ERCOT, which, on the other side of the equation, benefit Generation, but it all depends on where we lock those prices on the Retail side.

So I'm painting a picture of a scenario where, yes, you'll realize some benefit on the length on the Generation side, but some of that may be offset by supply costs in the Retail side if we decided, just like we will because we're in it for the long run, to maintain discipline in the near term on price where Retail is concerned.

And Greg, this is Chris.

I would just throw out one thing that is slightly more medium-term than what happens this summer if it's super volatile.

I think in a super volatile summer, you may see some retailers that aren't as well capitalized or hedged as us that end up shaking loose, that we do -- Elizabeth and her team does a great job of buying and moving things into the book.

And so that may provide an opportunity for us to grow the Retail side if we do see what you described as super volatile this summer.

And super volatile will also impact next summer or the following summer, which gives us an opportunity to increase our hedges and capture higher gross margins on our Generation part of the business.

And your next question comes from Angie Storozynski from Macquarie.

On the Retail side, just wondering, given Vistra's move, are you still considering third-party M&A on the Retail side?

And could it be actually a larger transaction?

Yes.

Angie, I mean, as you know, we don't comment on M&A, but we have said that we've come a long way on rebalancing our portfolio between Generation and Retail.

I feel very good about it, but there's always an opportunity to perfect that.

I have said that before in the past.

Our focus right now is, how do we grow our Retail business in the East?

We have a really good platform.

We have been doing it organically very successfully, but the way I would characterize the M&A opportunities are probably smaller to medium-size, and they're limited.

So we're going to be very opportunistic, and we're going to be very judicious about where we deploy our capital in this space.

And this has to be -- they have to be businesses that just complement our existing platform.

We already have a platform in the -- in Texas.

We already have a platform in the East.

So this is really a tucked in transaction, for a lack of a better word.

So they're smaller and medium-sized.

Okay.

And then the second question, you mentioned the progress on your buyback plan, when can we hear about the updates for the remainder of the year?

How much more money you plan to dedicate to the buyback?

Yes.

So the remaining cash of $872 million, as you all know, we already allocated $1.6 billion.

That's mostly on returning capital to shareholders and to achieve our new credit metric -- investment type of metric ratios.

So I will be in a position to provide that by the third quarter earnings call.

As I said, this was kind of a unique year because a lot of our excess cash was front-loaded, given the asset sales.

And now that the distribution of our earnings have become even more peakier in the summertime, we really need to wait for the -- having that excess cash, I guess, coming to the door before we can allocate it.

So you should expect that from us on the third quarter earnings call.

And in terms of how we're going to allocate that, we're going to be consistent with the way we have allocated that on our capital allocation principles.

We look at growth, and we look at returning capital to shareholders.

We have a very clear and transparent way of measuring our -- the return hurdles that we have when we allocate for growth.

But that's not sufficient.

They also have to be superior to the, I guess, implied return of our own shares that we believe continue to be undervalued.

So I think we're going to be very consistent in the way that we have approached it in the past.

And our next question comes from Steve Fleishman from Wolfe Research.

Mauricio, just a clarification on buyback.

The 500 -- the $400 million that you did with a bank-accelerated repurchase, do you know if all that stock actually got bought by now in the market?

Or is some of that still to be bought?

No, we know.

At the quarter-end, and you'll see this when we file the Q later today, that program was still outstanding.

But subsequent to the quarter-end, I think sometime around mid-April, the bank completed that accelerated share repurchase program and we were delivered the balance of those shares.

So that program...

Okay.

So that's in your average price of buying and everything, that part of it?

Yes, that's correct.

It's reflected.

Even at the post-quarter end event, it's reflected in that.

And I believe on one of those pages in the press release, there's a footnote that tells you what our shares outstanding are up to the minute.

And that shares outstanding reflects the complete impact of that first $500 million of buybacks that took place.

Okay.

And just -- maybe just a little more color on Texas for this summer.

And just I know you brought this plant back, which you did not do last summer, so I assume that suggests it's even tighter in your view than last summer.

Just how -- what's your sense on the risk of major volatility events, price spikes or things like that?

Just any further color for the summer.

I mean, as you -- we'll know a lot more when we get to next week and they come out with the SARA and the CDR, which I think is coming out Wednesday or Thursday of next week on the 8th, whichever day that is.

That would give us a look.

I expect that to show probably negatives in the base case.

It doesn't -- but keep in mind that the SARA normally doesn't count the full use of DC tie.

That doesn't count all of the ERS or the private use networks.

I mean, there's a lot of things that are above and beyond the SARA.

But it's going to look pretty bad.

I mean, the 7 and change reserve margin is going to be awfully tight.

Going the other way, Gregory will be in there.

And so you'll see a slight uptick from that.

But in terms of what we're seeing so far this summer and so far what we've seen this spring, we've had some disappointing days, where the expectations were pretty high from a, hey, load is pretty good, and we've got a heck of a lot of outages.

And you do kind of a net load calculation and you're like, wow, we're up into the -- in the mid to low 70s, and prices aren't doing much.

It's been rainy down there.

The drought monitor -- people start to look at the drought monitor around this time of the year.

And we'll see what that shows, but it's been relatively wet down there.

And looking at the ENSO forward reading, it looks like were leaning towards El Niño, which isn't particularly bullish, but we'll have to see.

And like I said, we'll take a look at the SARA when it comes out, but hey, look, a 7.5% reserve margin is super tight, but a lot of the other things are going -- are kind of trending the other direction.

Your next question comes from Praful Mehta from Citigroup.

So maybe, first, a detail question on Page 33, where you have your free cash flow for the year -- or for the quarter.

There seems to be a big working capital collateral draw, which has reduced your free cash flow before growth for the quarter.

So I just want to understand why the $384 million?

What's kind of driving that?

And how does that trend down over time?

That's basically just collateral postings related- two things.

One, the components of the collateral postings related to the mark-to-market on our hedges that we've put in place.

That collateral comes back to us, obviously, as those hedges roll off and realize, as is the case over the course of the year.

And also, to some extent, working capital receivables versus payables around the context of the Retail business.

I think this is probably the 2 primary components of that.

And I mean, if you follow the company, I know that you have, the first quarter tends to be a light quarter on a free cash flow basis.

This is not unusual at all for us.

Because even though there's an EBITDA distribution here, I would say even the free cash flow is even more acutely biased towards that kind of third quarter piece of the year.

Got you.

And then maybe a little bit on Texas again.

It sounds like while the reserve margin's tight, the other conditions, especially weather, and if it's wet, clearly, it won't be that beneficial.

But as I understand your previous comments, it sounds like most of the benefit that you expect to get out of a tight Texas is more through hedging in the forward curves, and the actual event during the summer itself may not be that beneficial because you don't have that much Generation open.

Is that a fair way to understand how you look at Texas at this point?

I mean, I think that's fair.

If you look, even on our hedging disclosures for the balance of the year, we're 93%, 94% hedged.

So we really have -- our excess Generation is really going to be with an eye towards managing our operational risk.

And -- but if there is high prices this summer, it will definitely impact forward years.

And that just gives us a really good opportunity where our portfolio is more open.

I mean, if you look at 2020, we're only 50% hedged, and then -- in '21.

So it creates an opportunity for hedging in the future, and it creates -- now there is a modest upside, but again, our goal is to make sure that our platform performs under a number of market conditions.

Got you.

That's super helpful context.

And then finally, just on PJM, with this fast-track reform, it sounds like -- I just want to get your view on, has that had moves yet in terms of is it reflected in the forward curve?

Do you see some bullish impact already?

Or do you expect to see it later down the road?

How do you see this fast-start reform to actually impact prices?

I think it's been -- this is Chris.

I think it's been slightly muted by the change between what PJM was asking for and what FERC delivered.

And also, I think that there was a little bit in the forward curve to begin with.

I mean, this was sitting there.

We were expecting this to happen in September.

So this has been in the forwards for this summer for a while.

We'll -- I don't know there's going to -- I don't expect the curves to run up $3 on this would be my suggestion.

Yes.

No, that's exactly -- we didn't see that much move, so I just wanted to get the context.

So that's why...

I think it was mostly expected.

And that they're slightly disappointed that FERC didn't do exactly what PJM asked, which was the 2-hour instead of the 1-hour.

We have time for one more question.

Our final question comes from Michael Lapides from Goldman Sachs.

An ERCOT renewable question for you, which is the queue in ERCOT for solar, I think, continues to grow.

And obviously a small percentage of what's in the queue will likely get built.

But how do you think about what -- for your base case, like given how big the queue is, what you guys are assuming actually gets built when you think about what the market looks like 2, 3, 4 years from now?

So this is Chris, Mike.

I would look and say, I think we probably shared this in the past, that when we look at wind build in the CDR versus what we see wind deliver, it's been in the 30% to 40% range over the past 3 years or so.

So I would be slightly bearish even to that because I think that CREZ is pretty well supplied with 22 gigs of wind already on the system and that the CREZ was built for far less than that.

When you then talk about solar, I think that we're going to see some solar coming.

I think that Texas needs newbuild right now because, good lord, the peak load is growing at 2,000 megawatts a year.

And so we a bunch of newbuilds, and solar seems like the most likely part of it assuming they can find PPAs for that.

So that's kind of a quick -- and then there's very little gas really.

I mean, I think gas is only 10% or 15% of the interconnection queue these days.

And like Mauricio mentioned in his initial remarks, I mean, some of the gas that is expected to hit in 2021 has been postponed 3 or 4x already.

So that's a real quick snapshot on it.

Yes.

And when you think about where the utility scale of solar will come, am I right in thinking about it that it will be, unlike the wind in West Texas, the utility-scale solar has the potential to be a lot closer to the load pockets?

I'm just trying to think about what -- to get several gigawatts in the next 2 to 3 years of total new installs, how you're thinking about the impact on kind of future pricing.

I think that solar sighting is going to be sprinkled across the grid.

So -- as opposed to like a very concentrated approach out in the Panhandle that we've seen in the wind.

I think solar will be -- will speckle the landscape a lot more, so to your point maybe closer to some of the load zones.

And then impact on pricing, I'll just leave you with this thought.

There's no unit in the system that's a $9,000 cost, right?

I mean, the prices are administratively set.

So whether the unit has 0 marginal cost like solar or a $30 gas unit, it doesn't really matter when you get to scarcity.

And we need a lot to get -- just to get to a 10% reserve margin in 2021.

And I don't think a lot of that wind's probably going to be there to do that.

So I think it's going to stay tight for a while.

Thank you, Michael, and thank you for your interest in NRG.

And I look forward to talking to you in the next earnings call or in a roadshow if I see you before that.

Thank you.

Ladies and gentlemen, thank you for participating in today's conference.

This does conclude today's program.