NRG Energy Inc (NRG) 2017 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the NRG Energy First Quarter 2017 Earnings Conference Call.

(Operator Instructions) As a reminder, today's conference is being recorded.

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

Sir, please go ahead.

Thank you, Liz.

Good morning, and welcome to NRG Energy's First Quarter 2017 Earnings Call.

This morning's call will be 45 minutes 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.

As this is the earnings call for NRG Energy, any statements made on this call that may pertain to NRG Yield will be provided from NRG's perspective.

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 press release.

With that, I'll now turn the call over to Mauricio Gutierrez, NRG's President and Chief Executive Officer.

Thank you, Kevin, and good morning, everyone.

Joining me this morning is Kirk Andrews, our Chief Financial Officer.

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

Let's start today's call with our Q1 results on Slide 3. Today, we are reporting first quarter adjusted EBITDA of $412 million and reaffirming our full year financial guidance for 2017 of $2.7 billion to $2.9 billion.

Our operational execution remained outstanding during the quarter.

First and foremost, we achieved top-decile safety performance, which is a testament to our ability to focus on our most critical objectives.

We also maintained our focus on our key strategic priorities: reducing costs, optimizing assets and balance sheet management.

We announced the deactivation and mothball of 1,600 megawatts of generation, reinforcing our commitment to constantly optimize our portfolio given changing market conditions.

We continue our prudent approach to growth and capital recycling with the drop-down of the Utah solar and 31% of our interest in Agua Caliente assets for $130 million in total proceeds.

And today, we are announcing the offer of our remaining 25% interest in a large portfolio of wind assets from the ROFO pipeline to NRG Yield.

Finally, the Business Review Committee is well on their way in its evaluation and is making good progress.

All businesses are engaged and we're working diligently to provide an update to the market as soon as possible.

Turning to the right side of the page, I want to take a moment to identify and explain the key drivers for the quarter and touch upon our path to full year guidance.

Kirk will provide additional details later in the presentation.

Let me start with the first quarter results.

As you can see on the chart, the decrease in adjusted EBITDA year-over-year was driven almost entirely by the Generation business.

The roll-off of higher price hedges that were executed after the polar vortex of 2014, lower capacity revenues in the East and a few known one time items accounted for almost 75% of the total decrease.

These items were included in our guidance as we had identified 2017 as a trough year and have guided to a lower full year result compared to 2016.

The other 25% was the result of mild weather, weak renewable resources and advisory fees.

Taking this first quarter result and our current outlook for the year, we're now trending towards the lower half of our guidance range.

We expect to update our guidance once we have more clarity on the BRC and general processes.

Now shifting focus to our operational metrics on Slide 4. As you can see, the organization remained focused on our day-to-day operations despite ongoing internal initiatives and weak market conditions.

I am particularly proud of our safety record as we delivered another quarter of top-decile performance.

This is a testament to our strong safety culture and excellence in operations where 142 facilities out of 158 operated without a single reportable injury.

Total generation was down 9% compared to the first quarter of last year, driven primarily by lower generation in our gas and oil units and the East coal plants.

This was partially offset by increases in production from our coal units in the Gulf Coast due to higher wholesale prices.

Our traditional availability metric, EAF, was up from last year following the completion of an intense 2 years of repowering and environmental compliance outages.

Although EAF increased, it doesn't tell the full story of NRG's ability to capture value when economics justify, so we introduced our in-the-money-availability metric last quarter.

We believe this is an improved measure of our ability to manage and balance operational performance, margin at risk and spend while in this low commodity price environment.

Our results demonstrate our ability to have units available to capture value when it matters.

In our Retail business, we continued our growth.

Our sales were up in both our Retail Mass and C&I segments where we acquired an additional 14,000 Retail Mass customers over the quarter, bringing us up nearly 87,000 customers year-over-year.

Although margins were down slightly due to mild weather and changing customer mix, our growth in customers and customer count helped us maintain volumes.

We now turn our attention to the important summer months, and I remain confident in how we have positioned both our Generation and Retail businesses in each of their respective markets.

Turning to Slide 5, we outlined the key trends and how we have positioned our portfolio in each of our core markets.

As I've described in the past, we have come a long way in diversifying our earnings, both in terms of business lines and our portfolio composition.

Today, almost 3/4 of our estimated 2017 gross margin comes from sources that are not directly correlated to the price of natural gas.

This diversified base of earnings drives our platform and is enhanced by the regional strategies we take in each of our markets.

So let me start with the Gulf Coast.

We continued to see strong growth across the region and are encouraged by the fundamental dynamics, particularly in ERCOT.

Given the energy-only market structure, an integrated platform of Generation and Retail is necessary to mitigate price volatility and deliver sustained value.

From a market perspective, given the persistent low commodity prices in ERCOT for almost 5 years, we do see a heightened risk of both new generation being delayed and accelerated retirements that could tighten the markets sooner than expected.

In the East, the market continues to be centered around capacity and providing reliability at the lowest cost.

Over the years, we have pivoted our fleet to focus on reliability and benefit from capacity prices while maintaining a cheap option on energy.

We continue to seek opportunities to balance our Generation portfolio with more Retail and enjoy the benefits of an integrated platform.

But we will only do that at value while recognizing the limitations of the East Retail markets today.

We're also encouraged by the full implementation of the capacity performance construct in the upcoming PJM auction, which creates a natural market tightening through more stringent reliability requirements.

But while we believe the market construct itself can be effective, we are concerned about the recent out-of-market payments that keep uneconomic generation from leaving the system, and I will be speaking more on this in a few minutes.

Finally, in California, regulatory policy continues to support the decarbonization of the state's economy with a focus on renewables, quick-start gas, controllable demand and increasing the energy storage.

In this market, our assets are well positioned inside low pockets and have benefited from repowering opportunities.

In California, we have brought online or developed over 2 gigawatts of renewables and 2.5 gigawatts of quick-start gas over the past 5 years.

This past quarter, our Carlsbad project PPA became final and nonappealable and construction started in February.

Moving on to Slide 6. The fundamentals of the ERCOT market remained strong.

Load growth continues to outpace the rest of the country.

On a weather-normalized basis, it has averaged over 2% over the past 12 months.

And as you can see on the left-hand chart, ERCOT has achieved higher peak loads with lower temperatures over the past few years.

The new forecast by ERCOT for 2017 puts peak demand 2.5% higher than last year and a high demand case close to 8%, that is 5,000 megawatts higher.

At the same time, we have experienced energy prices for the past 5 years with little to no scarcity premium.

This market dynamic is putting significant pressure on both new builds and retirements.

As you can see on the right side of the page, there have been a number of delays or cancellation of projects as developers failed to justify new investment at current prices.

For example, the 3 thermal projects slated to come online for the summer of 2018 have not yet indicated that they have begun construction and are unlikely to achieve commercial operations prior to next summer.

Now turning to retirements.

ERCOT has historically understated the actual number of megawatts leaving the system, as you can see from the period between 2009 and 2016.

Looking forward, we see the same anemic estimate for the retirements in their reports, assuming only 840 megawatts between 2017 and 2022.

In April, we announced that Greens Bayou 5 will go into mothball status, that's 371 megawatts alone leaving the market.

And we believe that there are close to 5 to 6 gigawatts of already identified generation at risk today in the market.

As we look at the future reserve margins in the high teens, we cannot help but think about the higher loads, less new builds and more retirements quickly tightening the market and creating scarcity conditions.

In our view, ERCOT remains the most attractive market in terms of market fundamentals, but we need to see significantly better price signals before we can start deploying additional capital.

Now turning to the East on the Slide 7. Energy margins remained challenged given low natural gas prices and new efficient generation, but we maintain our positive outlook on capacity markets, particularly in PJM, which implements the first 100% capacity performance auction later this month.

In this construct, the higher reliability requirement will create challenges for the megawatts that cleared in previous auctions as base capacity including less reliable generation and demand response.

These resources will have to make a decision between taking themselves out of the market or pricing in a higher reliability premium.

While we see positive changes like the capacity performance construct in PJM and other East markets, we are concerned about the increasing activity by the states to undermine the integrity of competitive markets.

Out-of-market subsidies and contracts distort price signals needed to attract new capital investment, but often raising prices for the end users.

We, and a number of other parties, have filed legal challenges to the nuclear subsidies in both New York and Illinois because we believe they're not legal and because regulators should focus on crafting competitive solutions for public policy objectives.

We are encouraged by the support from PJM, its market monitor, other generators and consumer groups.

You can expect NRG to continue to be a leader in these efforts to protect the well functioning of competitive markets.

So with that, I will turn it to Kirk to talk about the financial results for the quarter.

Thank you, Mauricio, and good morning, everyone.

Turning to financial summary on Slide 9, NRG delivered $412 million adjusted EBITDA for the first quarter.

Generation and Renewables delivered $95 million in adjusted EBITDA during the quarter while Retail and Yield contributed $133 million and $184 million.

As Mauricio discussed earlier, our first quarter results relative to 2016 were impacted by a combination of expected changes as well as other unexpected variances.

As shown in the chart on the bottom half of the page, approximately 75% of the quarter-over-quarter change in EBITDA was anticipated and occurred in our Generation segment.

The majority of this anticipated variance was a result of the impact of lower realized energy margins including the roll-off of higher-priced hedges in 2016 combined with the onetime impact of the sale of emissions credits.

The remainder of this expected change in the Generation segment was due to a combination of lower year-over-year capacity prices as well as the shift of hedge revenues from 2017 to 2016 as a result of the early monetization of hedges at GenOn.

The remaining quarter-over-quarter variance was primarily due to the impact of milder weather, which affected all 4 of our major segments during the quarter.

Our Retail business was primarily impacted by lower margins resulted from a combination of milder weather and higher supply costs.

While both NRG Yield and Renewables saw below-normal solar insulation and wind speeds, primarily in California.

The milder-than-normal weather for the quarter also impacted the Generation segment, particularly in the East.

And finally, we saw additional G&A expenses due to advisory fees largely associated with the newly formed Business Review Committee we established late in the quarter.

Turning to the outlook for full year 2017.

We are reaffirming our guidance ranges for the year of $2.7 billion to $2.9 billion in adjusted EBITDA and $800 million to $1 billion in free cash flow before growth.

However, taking into account the first quarter results and our current outlook for the balance of the year, we are currently tracking toward the lower half of these ranges.

Importantly, as Mauricio noted, this outlook does not yet reflect the impact of the BRC and GenOn processes.

We anticipate having clarity on these processes and their resulting impact on guidance in the near term.

Turning to Slide 10 for a brief update on 2017 NRG-level capital allocation.

Having now closed on a drop-down of the Utah assets and the partial interest in Agua Caliente to NRG Yield during the quarter, our capital goal for allocation stands at approximately $1 billion.

And having now offered our remaining 25% stake in the TE Wind portfolio to NRG Yield, we are focused on completing this transaction later in the year to further augment available capital at the NRG-level.

Our planned capital allocation for the year also remains unchanged including approximately 70% allocated to debt reduction to further strengthen the balance sheet.

We expect to execute on the bulk of this delevering in late 2017 as we approach the maturity date of our 2018 notes as well as more attractive pricing on callable debt.

With growth investments and shareholder dividends unchanged since our previous update, we continue to anticipate approximately $75 million of excess capital yet to be allocated and we will address the expected use of this excess later in the year.

Finally, Slide 11 provides an update on 2017 corporate credit metrics.

There are 2 changes to highlight since our last update.

First, during the quarter, GenOn drew $125 million under the secured intercompany credit facility with NRG.

NRG, in turn, funded this via a draw on our corporate credit facility in the same amount.

The draw under the intercompany GenOn revolver was a result of a drawdown on the $125 million letter of credit posted by GenOn in support of GenMa.

Although this drawdown was a result of the claim of default by the owner lessors, GenMa disagrees with the default claim and the associated drawdown on the letters of credit and is in the process of pursuing its rights and remedies.

Although we view this drawdown on the NRG revolving credit facility as temporary pending the resolution of this dispute, we have updated our corporate debt balance as well as the GenOn level total debt to reflect the $125 million increase.

As to the second change, turning to the right side of the slide, given the lower-than-expected first quarter results primarily at the GenMa and REMA subsidiaries within GenOn as well as additional costs associated with the ongoing restructuring process, we are reducing the GenOn midpoint of the adjustments to our midpoint EBITDA guidance used to arrive at corporate level EBITDA.

The net impact of these changes on corporate credit ratios, however, is very minor as our result in 2017 gross corporate debt-to-corporate EBITDA ratio is now 4.17 versus 4.13 in our prior quarter update.

As we began last quarter, we've also shown this ratio on a net debt-to-EBITDA basis, which remains under 4x.

With that, I'll turn it back to Mauricio for his closing remarks.

Thank you, Kirk.

And in closing, you can see on Slide 13 that we have made good progress against our key priority this quarter.

With respect to GenOn, we continue to evaluate all options available in advance of the upcoming bond maturities on June 15 of this year with our primary goal of negotiating a comprehensive solution to satisfy our stated core principles.

We, along with GenOn, remain in active dialogue with GenOn's creditors while we continue to evaluate and pursue a broader range of possible outcomes.

To that end, GenOn recently appointed a new dedicated CEO to assist in these ongoing efforts.

I expect to update the market in the near term.

As I look into the summer and beyond, I am confident in our ability to deliver strong results across our well-diversified and integrated platform with our philosophy of continuous improvement.

Thank you.

And with that, operator, we're ready to open the lines for questions.

(Operator Instructions) Our first question comes from the line of Greg Gordon with Evercore ISI.

So when I look at the Slide 3, and also I look at Slide -- Page 9, you haven't given specific -- you haven't called out specific numbers, but it looks like weather and advisory fees could have been numbers approaching $75 million to $100 million of variance in the quarter.

Is that within the realm of reasonableness or not because if it is, it looks like, all things equal, you probably would have had a decent quarter had you not had those things that were out of your control?

Yes, Greg.

I mean, it was actually around the $100 million.

1/4 of that was advisory fees.

And if you look at the 2 drivers of the remaining was really the mild weather that affected Retail and Generation and it was the lower wind speeds and solar insulation that impacted Yield and Renewables.

Right.

And so on Page 11, again, just to -- I think you were pretty clear the slightly higher growth in net debt-to-EBITDA is purely a function of where the quarter came in and where you are on the guidance range?

Greg, it's Kirk.

Yes, I would -- that's true with respect to the denominator because we basically adjusted out less with respect to GenOn.

It's really the numerator component of that, as I indicated earlier, that we did increase the corporate debt just associated with that drawdown under the intercompany revolver, which NRG, in turn, funded by the drawing its own revolver.

Okay.

Sorry, I had to hop off the call for a second, so I missed that.

What is the -- can you give us -- this is my last question, sort of a specific expectation for a time line on when the business review will be complete?

Should we expect that update to come in conjunction with the Q2 earnings call?

Or if it comes to resolution prior to the earnings call, with a significant enough margin of time, would you do a separate disclosure?

Yes, Greg.

I mean, I think we're making really good progress inside the BRC.

As I mentioned, the entire company is engaged, all the businesses are engaged.

As you all know, we have a now date of August 15, but we're working as diligent as we can to be able to communicate to the market as soon as possible.

So if that merits -- if we come to a conclusion and if that merits a stand-alone call before the earnings call, we will do that.

I mean, my objective is to communicate that as soon as we have resolution and really not waiting for a quarterly earnings call.

So if we have something to say, we're going to say it as soon as we can.

Actually I do have one more question, sorry, on Retail since you have your Retail guru on the call with you.

There's obviously been a significant move by your competitors to enhance their retail sales channel capabilities.

We're also in an environment with very low volatility and very low pricing.

Your customer count was up in the quarter, but your EBITDA results were lower.

Are we starting to experience a significant amount of competition for certain types of customers?

And how should we -- if that is a reason, should we factor that?

Yes.

So that's a good question, Greg, and I mean before I pass it onto Elizabeth, just to make sure, I mean, on the quarter, I mean, if you can see, we actually have milder weather and wholesale prices quarter-over-quarter were higher, so that really -- naturally, that compresses our gross margin.

But in terms of the competitive landscape on Retail, Elizabeth, can you answer the question?

Sure.

Thank you.

Appreciate the question.

So I would say right now we are not seeing any more competition than we have historically seen and NRG's retail engine is very strong.

We have great momentum in both customer acquisition and retention, demonstrated really by our customer growth.

Once again, we grew 14,000 in the quarter.

Mauricio mentioned, last year in Texas alone, we grew by 87,000 customers.

Every one of our competitors is looking at declines of some level and that customer growth actually mitigated the impact that we would have seen otherwise.

On your question around margins, we do see some margin compression when we look at customer growth because if we decide to grow in a particular pocket, we will be willing to accept customers at lower margins if they deliver strong EBITDA.

And because of our scalable platform, we're able to take on those customers and grow from there.

So we do make trade-offs.

I don't think that anything that's going on in the competitive dynamics is driving material compression in margin.

And while we did see some compression largely associated with weather and a little bit associated with customer mix, we're still strong in our momentum at maintaining our margins and only when we take deliberate action to -- where we see some compression, but it's going in eyes wide open.

Our next question comes from Julien Dumoulin-Smith with UBS.

So quick question, to the extent possible, can you give us a little bit more of a sense on how to think about the puts and takes in your 2017 EBITDA guidance as you reflect the GenOn and BRC update?

I suppose obviously being at the lower end, should we be thinking about GenOn as a net degradation and then the BRC to the extent which had some of the cost-cutting initiatives can have an effect in the back half of the year that could be an offset to GenOn and keep you at least at the low end, if not push you up?

I'm just trying to get a sense of what the factors you would be updating here are as you think about it?

Yes, well, I think you mentioned the 2 big events that we have coming up, which is the BRC process and GenOn.

GenOn clearly could have a significant shift in the composition of our portfolio.

And the BRC, as we said before, I mean, their focus is -- or our focus right now is on cost initiatives, asset optimization and capital allocation, so -- which is very consistent with how we approach our priorities last year in 2016.

I think what you should expect is additional cost savings or cost reductions, just like we did in 2016 over $0.5 billion, most of it recurring, you should expect a continuation of that in 2017.

But as I said before, I think we need to let the process work, I don't want to front-run it.

We're all working very diligently and we're making really good progress, but I think the way you should think about it is additional cost initiatives and all the other decisions that we make will be towards creating shareholder value, maximizing shareholder value.

Kirk, I mean, is there something else that you want to add?

Well, I just want to add, Julien, is that, obviously, GenOn is an outcome-dependent situation, but there are significant processes here with the provision of shared services.

And inclusive of that change, combined with any reasonable anticipation of any costs coming out of the BRC process, as you implied, which I'd agree with, that would be certainly a net positive relative to the outlook because we haven't embedded any of that into our current outlook that underpins our guidance.

Great.

Said differently, the loss or the dis-synergies of the GenOn breakup, if that is, indeed, what ultimately happens, you have confidence that the back half of the year the BRC could offset that?

I think that's fair that the total -- the combination of those 2 outcomes, assuming any reasonable amount of cost-cutting above and beyond GenOn, should be a net positive vis-a-vis our outlook today.

Excellent.

Second quick question, development related on the Renewables side.

You added 1.3 gigs to utility scale in the DG pipeline in the quarter, which seems pretty meaningful, especially given some of the, I suppose, wider conversations around what you intend to do with your development renewable activities under the BRC.

Can you comment what those additions were and then just talk about your commitment to this specific aspects of the business?

Yes.

I mean the increase in the pipeline, as I mentioned to you, after we integrated post agreement proposals that we integrated with our Renewables business and have stabilized that group, I think you can see the results here not only with the acquisition of SunEdison, but really increasing our pipeline of projects.

I mean, keep in mind that this pipeline of projects are in various stages of development.

I would say that most of them are really in an early-stage development and this is an important driver for Yield.

We are a significant owner of Yield.

And as we can provide more clarity on assets that we can drop down, it just enhances the value of Yield, which enhances the value of NRG.

So I think that's the objective that we have and the mandate that we -- that I've given to the Renewables business.

I mean, we need to continue growing that pipeline.

Got it.

So it would seem as if, if you're talking about early-stage projects and expanding capital deployment into early stage, that would actually suggest furthering your efforts on this front, as you just said, enhancing...

Well, I think when you talk about capital deployment, keep in mind that most of the capital deployment around Renewables is transitory because we have said before we have set it up as quick capital replenishment.

So we developed and then we very quickly turned it to Yield or sell it down to Yield to replenish capital and redeploy that at NRG, so just keep that in mind.

This is not permanent capital.

Our next question comes from Steve Fleishman with Wolfe Research.

Just a couple quick questions.

Any sense of the -- how much of the advisory fees are expected to be for the year when you've kind of updated to lower half?

Yes, I mean, as I mentioned, I mean, the first quarter was about $25 million and what I will tell you is that it's hard to pinpoint right now the exact fees that we're going to have because it's going to depend on the outcome of all the BRC process and ultimately the path that we get to GenOn, but what we have embedded right now in our guidance is under $50 million.

Okay.

And that, I mean, by itself, that pretty much gets you into the lower half per the numbers, I guess?

Secondly, do you have -- a lot of the hit that you were expecting this year occurred here in the Q1 even without the weather and the like.

Is there -- what kind of helps you -- the hit later in the year is just a lot less than it was in Q1, is that just that the hedge roll-off is not as dramatic?

Capacity payments get better?

I guess, is there any other kind of key items that limit the hit later in the year, again before the BRC?

Yes, I mean keep in mind -- as I said, I mean, the big driver here were the roll-off of high price hedges that we actually put post the polar vortex of 2014.

So if you remember, after the polar vortex, all the winter strips repriced right after that.

The '16 and '17 winter strip completely -- or the '15 and '16 repriced.

And most of that, the uptick that we saw post polar vortex, were exactly in the winter months.

So that's why the largest impact was in this quarter.

I think as you progress in the year, that's going to subside.

And the other thing that I will say is we've always identified 2017 as a trough year.

So I think as you move in the outer years, at current market prices, I think it's fair to assume that the outlook for commodity prices improved.

And that's without any BRC benefits and the whole thing?

That is correct.

Our next question comes from Angie Storozynski with Macquarie.

So I wanted -- I know you are not giving us the specific date when you're going to announce the other results of the pending review, but given that it looks like Texas is going to be particularly tight this year and maybe next and you will be potentially making decisions regarding asset optimization in the market, how do you think about it, that you would have to make those decisions before you see any type of summer-driven volatility in power prices in Texas?

Yes, well, I mean, I think first of all, as I said, I mean, the BRC -- well, good morning, Angie, first of all.

And I think when you look at the focus of the BRC, one is cost initiatives.

And given the low commodity price environment, I think it's fair to assume that we will continue our focus on reducing costs and that's somewhat independent of a particular season or a particular summer.

Of course, in every decision that we make including the valuation of all of our businesses inside the BRC, we're looking prospectively at the markets.

We're looking at the current curve, we're looking at the sensitivity around it and that's what is going to inform the decisions that we make at the BRC and ultimately the recommendations that we give to the board.

So I don't think -- we are looking prospectively, and I think that's my -- that's the point that I want to make, Angie.

I mean, this is not just a single point and marking a special decision against a curve, we are actually stressing different scenarios to understand the total composition of the portfolio and the sensitivity of the portfolio.

Okay.

And then on the GenOn, so GenOn has a new CEO who's appointed before the upcoming PJM capacity auction.

How should we think about it?

Does -- should we think that this appointment somehow changes GenOn's bidding strategies?

How do you think about the way these assets should be bid into the auction, given the fact that you might not operate them or own them?

Yes, well, Angie, I will say that the appointment of the new CEO, I think, in his responsibilities is to review and be responsible for ultimately the bidding of these assets.

Now, we continue to provide shared services agreement including asset management, commercial, I mean the wide range of shared services agreement that we give to GenOn.

And -- but we're, as we have done in the past, we provide a recommendation and we -- the commercial team gives them their perspective, but ultimately, it's going to be the new CEO's responsibility to determine how that portfolio is going to be dealing to the market.

Okay.

And my last question, I promise.

The DOE study about the important as of base load's assets, how does it play into your business review, if at all?

Well, I mean, I think everything is taken into consideration in the Business Review Committee.

I mean we have said in the best that one of the strength of our portfolio is a diversity of our merit order: base load, mid-merit, and peaking.

So clearly, if there is something that focuses on recognizing the value of base load, then we welcome that.

But I want to be crystal clear: it has to be in a way that doesn't jeopardize the integrity of competitive markets.

And we have to find ways to find the right competitive pricing to ensure the reliability of the system and that every single one of the resources is fairly compensated for the services that it provides to the grid.

And I think that's -- that has been our approach.

And we have time for one last question.

This question comes from the line of Stephen Byrd with Morgan Stanley.

Just wanted to follow up on Angie's question on asset rationalization.

And just at a high level, when you look at your fleet and you look at the market outlook today, is it your sense that there are opportunities to -- or maybe not opportunities, but sort of that it makes sense to think about some shutdowns of assets, just given that they're not really economically viable?

Or is this something we should be waiting for as part of the broader BRC update you'll provide later in the year?

Well, I mean, let me just start with our retirements because I've been very clear in the past.

I mean, we're -- our business is not to keep uneconomic generation running.

We have retired significant amount of generation that we felt was unprofitable and didn't have good prospects.

Just last month, we retired Greens Bayou 5, 370 megawatts of capacity in Texas.

And earlier in the year, we retired Pittsburg in California.

So I think combination was close to 1,500 megawatts of generation.

So we're not -- when we have an uneconomic plant, we will move quickly and swiftly to take it out of the market.

And of course, I mean, as part of the BRC, we're running -- we're doing a holistic review of the portfolio.

There are opportunities and I think we demonstrated that last year.

We sold 3 plants, we monetized over $0.5 billion of asset -- of sales proceeds.

I think there is an opportunity where perhaps another counterparty has a different view on commodity markets or can create a -- or looks at value differently than us and we will execute on that.

But as I said, I mean, I think as part of a -- with that respect, I don't want to front-run the BRC process.

When it comes to asset divestitures, I think we need to let that play out.

We are having good -- very constructive conversations inside the BRC, and as I said before, I mean, we're moving as fast as we can because I am the first one who wants to communicate this to the market.

So you have my commitment that as soon as we have something to communicate, we will tell you.

Great.

Thank you, Steve, and thank you all for your interest at NRG.

Thank you, and good morning.

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

This concludes the program and you may now disconnect.

Everyone, have a great day.