NRG Energy Inc (NRG) 2018 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to NRG Energy, Inc.'s Second Quarter 2018 Earnings Conference Call.

(Operator Instructions) And as a reminder, this conference is being recorded for replay purposes.

I'd now like to turn the conference over to Kevin Cole, Head of Investor Relations.

Please go ahead.

Great.

Thank you, James.

Good morning, and welcome to NRG Energy's Second Quarter 2018 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.

As this is an earnings call for NRG Energy, any statement 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 risk factors in our SEC filings.

We undertake no obligations 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 now with that, I'll 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.

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

And 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 with the key messages for the second quarter on Slide 3. Our business performed exceptionally well during the quarter with earnings up 23% from the same period last year.

We are making excellent progress on our Transformation Plan initiatives, and we are on track to hit all targets.

Finally, our portfolio is demonstrating, once again, the value of integration between Retail and Generation during the volatile summer months, particularly in Texas.

I am very pleased with our results so far, and I am confident we are well positioned for the rest of the summer and beyond.

So now moving on to the highlights of the quarter on Slide 4. As you can see on the left-hand side of the slide, we delivered $843 million of EBITDA during the second quarter, driven primarily by higher realized prices in Texas, higher retail loads and the impact of accretive cost savings.

Kirk will provide additional color on our results and the impact on our credit metrics.

For the first half of the year, our business has performed exceptionally well.

But with the warmest and historically most volatile months still ahead of us, we are maintaining our 2018 EBITDA guidance range of $2.8 billion to $3 billion.

And as has been our practice, we will update our 2018 guidance and initiate 2019 guidance on the third quarter call.

During the quarter, we also completed our first $500 million share buyback, in which we repurchased almost 16 million shares at an average price of $31.80 per share.

Our commitment to returning shareholder capital continues, and we are on track to execute on our second $500 million share buyback, following the close of either NRG Yield and Renewables or our South Central portfolio.

I also want to highlight the progress we have made on GenOn, which continues to move forward towards final resolution.

In July, we executed a settlement in which we received associated releases from GenOn.

And on August 15, we will terminate shared services.

GenOn is planning to exit bankruptcy on October 1 of this year.

We are also making significant progress on our Transformation Plan, which you can see by our scorecard on Slide 5. During the quarter, we removed an additional $145 million of costs, bringing our savings through the end of June to $225 million and placing us well on the path to achieving our 2018 target.

We also continue to make progress on our margin enhancement program.

You will begin to see the results of this program on our scorecard during the second half of 2018, with the results really ramping up in 2019 and 2020.

Both of our cost savings and our margin enhancement efforts remain on track for the current year and full plan targets.

As you know, asset sales remain a key focus for the organization.

We closed on the sale of Boston Energy Trading and Marketing, or BETM, and our Spanish Town asset, while reaching an agreement to sell our interest in 2 additional assets, Keystone and Conemaugh.

We actually had anticipated selling these assets in 2019, but we were able to accelerate this time line and execute on the opportunity to monetize these assets ahead of schedule.

Our NRG Yield sales process is moving along very well.

We have received all necessary regulatory approvals and are finalizing the consents.

We are making every attempt to bring this to conclusion as swiftly as possible and are working hard to make this a third quarter close.

The sale of our South Central portfolio is also making good progress, and we continue to expect that this transaction will close in the second half of this year.

Although we are in the middle of the summer in Texas, I wanted to provide you a brief update on the positioning of our integrated model on Slide 6. And as you all know, ERCOT supply-demand balance is the tightest it has been in many, many years, following the retirement of nearly 5 gigawatts in the past 12 months and steady low growth.

This market tightening led to an increase probability of scarcity conditions this summer, which was reflected in higher forward prices.

So far, demand has not disappointed, setting a new record peak of over 73 gigawatts in July.

However, this record load was met with equally impressive reliability across the grid, which tamper real-time pricing as you can see on the left-hand side of the slide.

In other words, it took nearly perfect systemwide reliability to meet the summer peak demand.

Now our Generation fleet performed exceedingly well during this period, driven by the extensive planning and preparation we put going into the summer.

I would like to commend our operational teams for achieving excellent results and having no recordable injuries during this recent heat wave.

We also took measures to ensure the stability of our Retail business.

This included leveraging our integrated approach with Generation to help manage supply cost and proactively helping our customers manage their bills.

These tight market conditions in Texas also created longer-term opportunities to incur the predictability of our earnings.

We took advantage of higher prices and executed power hedges at attractive levels for the summers of 2019 and 2020.

This is exactly the period that saw the majority of price increases.

We also took the opportunity to hedge our shoulder months and offpeak periods with natural gas as a proxy for power in those same years.

I mean, this summer so far has showcased the strength of our integrated model with complementary businesses that increased the predictability of our earnings.

As I said before, we're only halfway through the summer.

And historically, the more volatile months are still ahead of us.

So we all at NRG remain focused across the organization on ensuring a successful summer.

Now moving to our market outlook and starting with ERCOT on Slide 7. Much like this summer, the longer term outlook for ERCOT fundamentals remain very strong.

As you can see on the left-hand charts, on a weather normalized basis, total loads remain very robust and growing -- and continues to grow at 2% per year.

This is a dynamic we don't expect to change anytime soon.

We also continue to see project delays of Generation -- of new Generation anywhere between 3 to 5 years.

And given that forward prices remain below new build economics, we also don't anticipate this dynamic to change in the near term.

So bottom line and for the foreseeable future, we expect tight reserve margins in ERCOT with higher probability of scarcity pricing and greater volatility as the system works to stay in balance.

These conditions create an opportunity for both sides of our business and highlight the longer-term value of our integrated approach, as you can see on the right-hand side of the slide.

Our Retail business is in a stronger position relative to other players in the market due to the integration with Generation and a scalable customer acquisition and retention engine.

Increasing loads means an increased opportunity for new customers, while potential volatility creates opportunities to take market share from other competitors.

And our Generation business benefits from higher prices with greater opportunities to hedge the portfolio at attractive levels.

Also higher hedge prices allows us to invest in our fleet to achieve higher reliability, increase the predictability of our earnings and mitigate the impact of volatility on our Retail business.

Now onto the East on Slide 8. PJM held its capacity auction for the planning year 2021/2022 this past May.

The results reflected less new builds and significant amounts of uncleared capacity, signaling more disciplined development and bidding behavior.

As you can see on the left-hand side of the slide, on a same-store basis, NRG cleared more megawatts at higher prices than the previous auction.

As we continue to optimize the fleet, we will focus on maintaining our assets in premium locations.

We now have 85% of our PJM fleet in the premium COMED zone, which once again separated to clear at a price of $196 per megawatt-day.

Throughout the East, we are encouraged by the multiple regulatory avenues for market reform that could benefit both our Generation and Retail businesses.

For example, FERC recently committed to protecting PJM's capacity market against the impact of state-driven subsidized generation.

It's clear to us that FERC wants to see the true cost of all resources reflected into the market by putting a price floor on subsidized generation.

This is a strong and clear procompetitive position coming out of FERC.

As part of this process, FERC also requested additional comments on the possibility of carving out low and subsidized generation from the market.

This is referred to as the fixed resource requirement, or FRR.

We believe this request for comments and the idea of taking single units out of the market is counter to the spirit of first rule.

We remain confident that FERC will act consistent with the pro-market principles communicated in its recent orders and either fix the FRR to ensure that it does not negatively impact price formation or perhaps rejected in its entirety.

That said, details matter, and we're looking forward to actively engaging on this issue, both with PJM and FERC.

So with that, I will turn it over to Kirk for our financial summary.

Thank you, Mauricio.

Turning first to the financial summary you'll find on Slide 10.

For the second quarter, NRG delivered $843 million in adjusted EBITDA, which is a 23% increase over the prior year.

Our strong second quarter results were driven primarily by higher power prices in Retail load in Texas and further enhanced by the impact of cost reductions across the organization as we continue our progress on the Transformation Plan.

And for the first half of the year, NRG has delivered nearly $1.4 billion in adjusted EBITDA, and our cost improvement program is only now beginning to hit its stride.

Although we're very pleased with these year-to-date results and the summer prices in ERCOT continue to show strength, we are nonetheless maintaining our 2018 guidance ranges of $2.8 billion to $3 billion in EBITDA and $1.55 billion to $1.75 billion in free cash flow.

I will note, however, that our first half results combined with our outlook for the balance of the year currently place our expectations for '18 well above the midpoint of our guidance range, and we will update and narrow these changes on our third quarter call.

At that time, we'll also provide guidance for 2019, which will include the impact of more robust targets for cost savings and margin enhancement, with nearly $200 million in additional EBITDA expected from these initiatives in 2019 versus our 2018 targets.

As Mauricio mentioned earlier, we've also completed Phase 1 of our $1 billion share buyback program, with 15.7 million shares repurchased at a price -- average price of $31.80.

We remain highly focused on closing our 2 large asset sale transactions, and we'll launch the second half of that $1 billion share repurchase program following the first of these 2 transactions to close, which is likely to be the sale of NRG Yield and Renewables later this quarter.

During the second quarter, we also completed the issuance of $575 million in new convertible notes with a coupon of 2.75%.

By repurchasing an equivalent amount of NRG senior unsecured notes, NRG's aggregate debt balance will be unchanged, and we expect approximately $20 million in annual interest savings, further augmenting free cash flow as we retire shorter-dated and higher-coupon maturities.

To this end, we've already repurchased $89 million of senior unsecured notes of varying maturities to date and have recently provided notice to repurchase $486 million of the 2022 notes, our nearest maturities, which will mark the completion of the senior note refinancing associated with the convertible issuance.

As a reminder, we've also targeted $640 million of debt reduction, which we expect to complete later this year in order to achieve our 3x net debt-to-EBITDA target ratio.

And finally this quarter, we successfully closed on the settlement with GenOn, which accelerated a significant portion of the items set put forth in the original restructuring support agreement, including the $261 million settlement payment by NRG and the repayment by GenOn of the intercompany revolver, which were previously expected to take place at emergence.

With the financial commitments associated with the GenOn bankruptcy now largely behind us and GenOn well advanced in its asset sale efforts, GenOn is targeting an emergence from bankruptcy early in the fourth quarter.

Next I'd like to take a few moments to update our pro forma financial summary, which you'll find on Slide 11.

As a reminder, this summer is based on the midpoint of our consolidated 2018 guidance and provides a view of 2018 EBITDA and free cash flow from retained businesses, net of any contribution for businesses and assets we are selling as a part of the Transformation Plan.

On the left side of the slide, under the heading Prior Pro Forma, we start with the pro forma 2018 summary we provided on our last earnings call.

Next, 2 second quarter events gave rise to the need to adjust our pro forma view.

First, the restructuring of the Ivanpah nonrecourse project debt and the amendment of some of the projects governing documents during the second quarter resulted in a change in the accounting treatment for Ivanpah.

As a result, as of the second quarter, Ivanpah is no longer consolidated in NRG's financial statements, but will appear as an equity investment.

On a fully consolidated basis, Ivanpah's contribution to the midpoint of our EBITDA range was approximately $100 million.

The impact of deconsolidation is the elimination of our partners' 45% share of Ivanpah EBITDA, leaving approximately $55 million of EBITDA from Ivanpah reflecting only NRG's 55% stake in our revised pro forma.

Importantly, aside from the impact of the income statement and adjusted EBITDA, Ivanpah's total nonrecourse debt of approximately $1.1 billion will no longer appear on NRG's consolidated balance sheet.

Turning to the second adjustment to our pro forma view.

With the closing of the XOOM acquisition, we are adding the annualized expected EBITDA of $45 million from XOOM to the Retail portion of our pro forma EBITDA.

Of note, this is an annualized number for XOOM on a pro forma basis, while the actual contribution for XOOM towards 2018 results will be a partial year reflecting EBITDA only for the second half of the year.

The EBITDA adjustment for deconsolidation of Ivanpah is offset by the addition of the annualized EBITDA for XOOM.

And as a result, our total pro forma adjusted EBITDA remains $1.6 billion.

The impact of Ivanpah's deconsolidation is limited to EBITDA.

And as a result, the $45 million increase from EBITDA from XOOM is reflected in our revised pro forma consolidated free cash flow before growth, which is now approximately $1.05 billion.

And finally, as I've noted previously, our pro forma EBITDA and free cash flow are based on the midpoint of 2018 guidance, which includes the impact of the 2018 Transformation Plan targets.

Beyond 2018, we expect an additional $275 million of annual adjusted EBITDA and free cash flow by 2020 as the Transformation Plan reaches its final targets.

Turning to Slide 12 for a very brief update on 2018 capital allocation.

Our 2018 capital available as well as our committed capital items are largely unchanged from the previous update.

The only exception on the allocation front is having now settled most of the financial aspects of the GenOn bankruptcy, our capital outlay for GenOn has been reduced by $18 million to $160 million.

As shown in the dotted box below the chart, the only capital allocation item associated with the GenOn settlement, which remains to be paid, is our annual pension contribution of approximately $14 million, which will take place in the second half of this year.

As a result of both the reduction and committed capital towards GenOn as well as the receipt of $12 million in proceeds from smaller asset sales, previously not expected to occur until 2019, our remaining 2018 unallocated capital, shown on the far right, has increased by approximately $30 million, resulting in approximately $700 million in 2018 capital remaining to be allocated.

Finally, on Slide 13.

We've again provided the 2018 pro forma net debt-to-EBITDA calculation as well as the walk to our 2020 ratio, all based on our 2018 pro forma EBITDA.

This calculation is based on revised pro forma EBITDA, which I reviewed earlier, and is largely unchanged from our previous disclosure.

The adjustment for Ivanpah is now smaller due to the impact of deconsolidation.

As a reminder, in 2018, we are temporarily reserving just over $1 billion in cash in order to achieve our 3x net debt-to-EBITDA, and we expect this cash will be made available for capital allocation beyond '18 as the additional EBITDA from the Transformation Plan initiatives, again beyond 2018, allows us to free up this cash by 2020, while still maintaining that important 3x net debt-to-EBITDA ratio.

Having previously focused exclusively on the 3x net debt-to-EBITDA ratio established with the Transformation Plan and these updates, this quarter we are also providing 2 additional key credit metrics, adjusted cash from operations from net debt as well as the cash interest coverage ratio to provide you a more complete picture of the strength of our balance sheet credit profile.

Although we remain a BB rated company, this rating does not fully reflect the strength of these credit metrics.

With consistent execution continuing to demonstrate the strength and resiliency of our integrated platform, supported by our proved and simplified balance sheet, I believe we have the opportunity to earn an improved credit rating.

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

Thank you, Kirk.

Turning to Slide 16, I want to provide you with a few closing thoughts on our 2018 priorities and expectations.

We continue to deliver solid financial and operational results, while remaining on track with all of our cost and margin targets under our Transformation Plan.

Our integrated platform is working as designed through the volatile summer months and remains well positioned for tight market conditions in the future.

As I said, winning the summer and closing on our announced asset sales is our most immediate focus.

I look forward to updating you on our progress and providing you more clarity on our capital allocation as we move into the second half of the year.

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

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

(Operator Instructions) Our first question will come from the line of Julien Dumoulin-Smith with Bank of America Merrill Lynch.

So I wanted to follow up here on the asset sale progress.

Just wanted to get a little bit of clarity.

First, with respect to the next round of buybacks and capital allocation, are you -- would you expect to potentially provide that prior to the next third quarter call, seeing a time line potentially on an expedited basis to close some of these larger transactions?

And then separately with respect to the asset sales, how do you think about the execution of the balance, the smaller sets that have yet to be announced?

Obviously, you announced the Keystone, Conemaugh stuff today, but what's the commitment level?

Have you, again, reviewed the balance of the portfolio?

And are you opting to hold on to some of the smaller stuff?

Yes.

Julien, so let me start with the first one.

I mean, we're going to launch the next round of -- the next $500 million of share buyback once we close on either Yield Renewables or South Central portfolio.

So if that happens before our third quarter call, you will know and all the investors will know.

With respect to your second question about the balance of the remaining asset sales, we're going to be providing you another update as we go through this evaluation towards the end of the year.

But just keep in mind, I mean, right now our focus is to close on these 2 transactions.

And as we move into the year, the team is now shifting gears and evaluating the other assets that will be down for closing.

Now as you can tell, where -- if we see an opportunity like we did with some of the asset sales that we accelerated from 2019 to '18, we're going to do it.

But I just want to make sure, I mean, all the resources that we have right now are completely focused in closing Yield Renewables and South Central.

Got it.

Understood.

And then secondly on Retail, can you talk a little bit more about what you did in the quarter?

You, obviously, alluded to in the prepared remarks, but where does attrition stand today through kind of the spirit in August?

And how do you think about the resiliency kind of going forward?

Are you actually adding customers at this point?

I mean, I'm sort of curious.

Yes.

So let me start by saying that Retail had a phenomenal quarter, the second quarter.

We had warmer than normal temperatures, that basically pushed our loads and load usage.

Keep in mind that we also added XOOM for one month and Business Solutions also performed well.

So it was a good quarter all around for Retail.

But, Elizabeth, I mean, with respect to some of the attrition and questions.

Sure.

Thank you, Julien.

We actually saw, as you can tell by our results, customer counts up over 10%, largely driven by XOOM.

We have, what I would call, pretty steady attrition and retention performance.

There is a little bit of pressure, but nothing that, I would say, is out of the ordinary or unexpected.

We're really pleased with the performance of both the acquisition and the retention engine through second quarter, and are looking forward to a strong third and fourth quarter as well.

Bottom line, on track with the targets that you'd alluded previously on the Retail side?

Yes, sir.

Our next question comes from Greg Gordon with Evercore.

So there is a bit of a debate in the market, Mauricio, that I'd like to hear your perspective on.

On the one hand, the lack of really, really high levels of volatility this summer despite the strong load has been disconcerting to some investors, who thought that those high level of volatility would validate the thesis on the Texas market and your long-term view on power market there.

And on the other hand, the lack of massive volatility has allowed you to continue to print stable profit margins and actually do some really solid hedging that may or may not have been -- actually maybe upside relative to what you promulgated in your outlook.

So from a business perspective, what would you rather see the conditions you have now or massive levels of volatility that put more stress on the business and potentially bring faster new entry cycle?

Yes.

Well, first is -- I think that you need to look at the fundamentals in Texas.

And what I was very pleased to see this summer is that demand is real.

I mean, setting a new record peak of 73.3 gigawatts in July, which is not normally the -- even the month that you see, the most extreme weather was very encouraging.

So when you think about the fundamental picture of ERCOT the supply-demand and the tightness that exists, it hasn't changed.

And actually this summer has validated that is here for the foreseeable future.

I think what you saw this summer is just a combination of a few things.

One was a very strong demand, but that strong demand was met with, like I said, perfect performance by degree.

I mean, when I say perfect performance, you have to just look at the forced outages that we had in that peak.

They -- and I mean, they were quite remarkable.

And also wind performed as expected, very close to normal.

So obviously, when you have this type of situation, yes, I mean, real-time prices were below what people were expecting.

They are not necessarily low, but they were below what people were expecting.

And from my perspective, we want a market that has very strong fundamentals and that has a really good market structure on both Generation and Retail, like the one we have in Texas.

So that is the perfect combination.

We don't want to see a market that is clearing too low, that necessarily doesn't reflect the fundamentals of the market, and that's why we have been so, I guess, frustrated over the past couple of years in ERCOT.

But also we don't want to see a situation where you'll see -- where you have scarcity pricing that leads to perhaps shaving low.

And none of those 2 extremes are good for our franchise.

Our integrated franchise of Generation and Retail is somewhere in the middle.

So the most important thing is that prices reflect the fundamentals of the market.

And from where I see, the fundamentals in Texas are incredibly strong, and they're going to be very strong for the foreseeable future.

I mean, even if you look at the forward prices, I mean, they have been rising, but they are not at the point that incentivize newbuild economics.

So supply continues to be delayed on new Generation.

Demand, we just saw that it was very strong.

So I mean, I want to see a market that is well-functioning, not that is balancing on each -- either side of extremes.

Great.

Are you in a position now to tell us where inside the guidance range you're trending year-to-date?

Or is the rest of the summer just too much of a wildcard and you rather wait till Q3 to tighten the outlook?

Greg, it's Kirk.

I actually gave you a little bit of that in my remarks.

I anticipated that question.

And what I said, just to repeat is, the performance year-to-date combined with our current outlook for the balance of the year places us well above the midpoint of our current guidance range.

I agree.

It's okay.

I missed that, apologies.

And then I also saw there were couple of small Retail transactions in the quarter that I just -- can you give us some more details on customer accounts or multiples to EBITDA in those?

Were they just too small to call out?

Greg, I mean, this is our -- this is just the normal course of business.

We actually buy books.

I mean, we have an engine in Elizabeth and she is very effective in terms of identifying these opportunities.

So I wouldn't think -- I mean, I wouldn't even think of they are representative of a transaction like XOOM.

This is just a normal course of business.

We're always looking for books that we can add to our Retail business and that's what they were.

Our next question comes from Abe Azar with Deutsche Bank.

Based on the forward curves and your hedging to date, could that be more cash available over the next couple of years above the $4.3 billion?

And then, have your thoughts on capital allocation changed at all?

And do you remain confident that share buybacks are the best way to get the stock higher closer to fair value?

Yes.

Well, let me just start by saying that we're not going to front run our third quarter earnings call, which we're going to be providing guidance for 2019.

My thoughts on share buybacks continue to be the same, and for that matter all capital deployment.

We're going to adhere strictly to our capital allocation principles.

And as I see today, given where price of our stock is, I don't think that there is any other more compelling and attractive investment than our own stock.

So until that changes, I think it's fair to assume that that's where we're going to be focusing on.

Great.

And then shifting gears a little bit to Texas.

Can you discuss how you balance your hedging strategy with your fundamental view of the reserve margin and prices, particularly in 2020?

Sure.

Chris Moser?

Abe, this is Chris.

So as we're looking at '19 and '20, obviously, we get a view on where things should be compared to the clears that we're seeing.

But make no mistake, as we did in '19 and '20 when prices get to be a good level and a good level above where it was 6, 8, 12 months ago, there is a certain amount of sense that comes from kind of sweeping some of that profit off the table, and that's kind of the balance and the approach that we take.

And just to make sure, I mean, most of the hedging happens in the summer of '19 and summer of 2020.

Right, Chris?

Yes.

The hedges that were put on Q2, the power hedges were mainly summer on peak hedges, too.

Our next question comes from Steve Fleishman with Wolfe Research.

So on the NYLD sell, you mentioned you're just finishing up getting consents.

Could you be a little more specific on what consents you still need?

Yes, Steve.

I mean, in the Yield Renewables, like I said, all regulatory approvals are done.

Consents, we're well on our way to have all of them.

At this point, we're not providing any specific details, which ones are remaining, but what I can tell you is that, I have confidence that we're going to be in a position to close on the third quarter.

That's what I will share on that, Steve, but I -- we're making just great progress on the consents.

That's great.

And then just -- this is just, Kirk, to make it clear of the market.

So should we expect that this buyback will be now -- assuming that closes in Q3 and that's the first one, the buyback $500 million will be announced that time?

Yes.

Not only will it be announced, it will be launched as soon as we close on that transaction.

Great.

Okay.

And then just in terms of the additional hedges, how meaningful were they to your kind of '19, '20 portfolio?

How much more hedged are you...?

Yes, Steve, if you look back in the appendix, I don't -- what is the page, Page 21, you will see the move there.

We layered on a big chunk of natural gas equivalent hedges.

Think of that as covering kind of the shoulder months and offpeak time frame and the assets up in Chicago.

And then you'll see that we did power hedging of 10% or 11% on an annual basis, but the hedge we're putting on we're really more focused specifically in the summer.

Steve, I mean, from a percentage standpoint, while it appears on that disclosure on an annualized basis, think of it as they were all put in the summer.

So the summer percentage was much higher than what is showing in the slide.

Yes, I mean, it was the meaty part of the curve, right.

It was the thick part of the curve that we were trying to sell and use the liquidity that was out there.

And very happy with the hedge that we put out on for '19 and '20.

Okay.

And then just in that light, your 3-year guidance goes all the way back to last fall.

Obviously, Texas prices are meaningfully higher since then, natural gas might be a little lower.

In the totality, though, are these hedges being put on at premiums too, what your plan has been?

Yes.

I mean, Steve, just to be perfectly clear, I mean, what we provided was a pro forma with -- based on 2017 -- by grand 2017 with the impact of Transformation Plan.

And yes, I mean, if you look at the curve, all else equal.

I mean, it's been a positive move.

Kirk?

Steve, it's Kirk.

Firstly, overall, the answer is, yes.

And the reason I say that is you can look no further to the fact is when we first established guidance for '18, for example, that would be in the third quarter of the previous year, the third quarter '17.

Generally speaking, our guidance is centered around the midpoint of our expectations, and those expectations are informed by what the summer prices are, in this case in '18 at that time.

And I think since our pro forma view is all anchored on that '18, the degree to which '19 and '20 summer prices today, for example, are higher than were '18 summer was at the time we established our guidance.

And I can tell you the answer to that question is, yes.

And you can quantify it by looking back.

That would give rise to the fact that all things being equal, that would give rise to an increase in that pro forma view since '18 would be higher than it would have been expected at that time.

And as I said, I confirm that our expectations are well above the midpoint of our range currently for '18.

That's great.

And one last, just quick thing on the Texas market.

You mentioned very strong plant performance and also wind, I think, being decent.

Just how about demand response?

And how much of that is impacting this and your thinking?

Sure.

Chris?

Yes.

When I go back and if we look on the slide that Mauricio was talking about, I mean, load was about 500 megawatts or just talking about the peak hour on the 19th there, load was around 500 megawatts higher or worse compared to the CERA expectation.

You had Generation around 1,000 megawatts better, which was just really flawless execution across the grid.

And I'm happy to say we put in some extra spring outages to be ready and that really payed off for us.

We had fantastic performance from the operations group.

So in the -- so that -- so those 2 net out to be give or take 500 megawatts better than the CERA and the CERA had around 1,000 megawatts of space in it.

So we really didn't get into the position where we needed a ton of other things to come to bear to save the market.

I will say that the market -- it was an interesting setup because Thursday wasn't supposed to be the high day.

This is the 19th, that was supposed to be that following Monday, the 23rd, which was actually forecasted over 76,000 megawatts for the better part of that week.

And so I think a lot of the DR was not -- was being prepared to be brought to bear on that Monday, and they may have missed the party a little bit because it turned out to be that Thursday was the high day.

Our next question comes from Praful Mehta with Citigroup.

So just to clarify on the EBITDA guidance well above the midpoint, is that for the retained assets?

Or is there a split between what was retained and what is being sold in terms of what's kind of driving that uptick?

Well, I'm not going to get specific about breaking beyond what our official guidance is, which is consolidated guidance.

But if you take a step back, the big portion of the adjustment, if you will, to get to a pro forma view is a portfolio that consists of 2 things primarily, one being LaGen which is kind of an integrated type of business, not to say it doesn't have upside and downside.

And the bulk of what remains is Yield, which is largely contracted, relatively low volatility, right.

And you can look at because Yield provides point estimates on their own guidance, which is largely unchanged.

So I think you can infer from that to a large degree that outlook is anchored off of our expectations for the balance of the portfolio.

But I wouldn't go so far to give you specifics other than I think it's reasonable to infer on the basis of what I've just described.

Got you.

That's super helpful color.

All right and secondly just following up on the ERCOT and PJM questions.

So firstly on ERCOT, Mauricio, do you worry that if there is no spike in ERCOT and price signal in '18 that you reach that point whereby '19 and '20 you have these unsustainable reserve margins, which are so low that it's actually not suitable for your business?

Is there a concern of that?

And how do you think that gets mitigated?

Yes.

I mean, my concern is always that prices do not reflect the fundamental view of the market.

I mean, that to me is what keeps me up all night because if the prices don't reflect then developers, generators, we can't -- perhaps we have -- we're making decisions with not the best information.

Now obviously, real-time prices are just one aspect of it.

I mean, you have to look at the day ahead, you have to look at forwards.

And most of the decisions are made on forward pricing.

The day ahead market is also an indication on how people get set up, and then real-time prices is what happens.

I mean, so far we have been talking about real-time prices, which basically was the result of perfect performance of the grid and a very strong demand.

But as I think about 2019 and 2020, obviously, I want to make sure that the prices are reflecting the fundamental situation in Texas.

And to the extent that, that does, rational developers, rational market participants are going to react in the right way.

So that to me is the most important thing, strong fundamentals and a very strong market structure.

That's what I -- that's what we are striving to.

Got you.

And then finally on PJM, as you said, I think, it's clear that FERC wants to do the right thing here and create the competitive market or the right competitive market and signals, but there is a pretty big gap between that and what the proposals are right now?

Do you think there is enough time between now and January to get this done?

Or do you think this gets pushed out to next year maybe?

I mean, it's really hard to handicap the timing when it comes to FERC and when they're going to act.

And so I'm not going to venture into that.

What I will tell you is just, we have been very encouraged now for -- now a couple of orders on the position that FERC has taken in terms of protecting the integrity of competitive markets.

If you go back to Mystic, the PJM and capacity, I mean, there has been a lot of consistency coming out of FERC.

So that's the data point that we have.

Everything else we don't have the details, then it's a speculation.

So I don't think it's a -- we will be venturing into something that we don't have enough information to even quantify.

So that's what I will say.

Our next question comes from Angie Storozynski with Macquarie.

So I'm going to go back to the share buybacks question.

So Kirk, you're saying that now you expect excess cash flow of almost $700 million.

It seems like you do have a line of sight for the NRG Yield transaction closing and yet you are not launching the next batch of buybacks.

What am I missing here?

Well, everything you just described is correct.

The one thing you keep in mind is outside of the asset sales proceeds, which we've given to indication about timing, our organic free cash flow generation is relatively back-end loaded, right.

We need to get through the summer in order to start to build that cash.

So as we come into the fall, our cash balances begin to appreciate.

In the interim, during the summer months, while still waiting on that cash, that also tends to be the more significant draw on liquidity, which we have ample supply of, but we have to be prepared that if we do see scarcity price events or the anticipation thereof in the forward market, that then entails a need for posting additional collateral.

So we have to balance the liquidity, the reality that the organic cash flow is back-end loaded, supplemented by the receipt of the asset sale proceeds, which is, obviously, determined on closing.

So all of those factor into that timing in terms of the -- the expectations in terms of launching Phase 2.

Okay.

But just one more follow-up here.

As you seem to be indicating that you will be waiting for the transaction to actually close, NRG Yield, I am talking, I thought in the past, we were just talking about a line of sight of that transaction.

And I know that it might be coupled with the just small difference as far as time is concerned.

But I mean, are you basically depending on that cash entering your bank accounts, so that's strictly before the buyback can takeoff?

Angie, this is Mauricio.

I mean, well, first, we launched the first $500 million because we felt comfortable that the transactions have been announced and we were making good progress.

And I was very pleased with how we performed on this first $500 million.

The second $500 million is going to be launched when we -- at close.

We feel comfortable with that.

And as Kirk is saying, we have to balance when those proceeds are coming and the back-end loaded of our cash flows coming in Q3 and Q4, particularly with the type of volatility that we're seeing in the market, it is important that we take extra precaution.

And then once we do that, then on the third quarter call, what I said is, any remaining capital that is available for allocation, we will be providing there clarity.

So I think that's the sequence that you should be expecting, Angie.

Okay.

And my last quick question, So you showed us the performance of your Retail and Generation portfolio in the second quarter.

Can you say what happened in July in Texas.

Did that strength especially in Retail earnings continued?

Yes.

I mean, what I will tell you is that we actually -- with the benefit of the pricing that we receive in the forward markets, we got ready both on our Generation and our Retail business to perform the way we have described we performed in July.

I mean, aside from that information, I don't want to front-run the earnings -- the third quarter earnings, where we're going to be talking specifically about the summer months.

But I felt it was important that many of you, our investors, wanted to know just what happened in this first month.

And I think what I can tell you is that we're very pleased with the performance of the fleet.

I'm very pleased with how Generation -- our integrated platform performed as a whole Generation and Retail in first summer months.

And I think, that's what I am comfortable right now sharing with.

I mean, like I said, we are just in the middle of the summer.

I mean, the most volatile months are still ahead of us.

Historically, August and September, that's where you'll see lot of high -- consecutive high temperature days.

So I want to make sure that the entire organization remains focused, and there's still a lot that can happen in the next 2 months.

And I will be providing you an update on the third quarter call on what happened this summer.

But so far I feel very good.

Our final question comes from the line of Michael Lapides with Goldman Sachs.

I want to come back to the hedging slide a little bit, Slide 22.

But I'm just kind of comparing it to the same slide in the prior quarter deck.

And I'm just looking at the total forward hedged revenue number, and I'm only looking at 2019 and 2020.

So '19 it's $1.2 billion, and '20 it's $828 million.

If I look at that same slide for the first quarter, cumulatively, if I just take the differences between what you had hedged then and what you have hedged now, it's $1 billion, $600 million in one year, $400 million in 2020.

Does that all just drop to the bottom line, meaning that $600 million -- and that's $1 billion of the incremental cash flow that will likely flow into NRG relative to what you may have thought or had hedged or had locked in 3 or 4 months ago?

Yes.

Well, Michael, thank you, and -- I mean, keep in mind that this is just the top line.

This is revenue.

This is not gross margin.

So you have -- first, you have another leg -- I mean, you have to take into consideration what happened on the fuel side.

We haven't provided that here.

So -- and then secondly, I think, as we have said, I mean, this is a -- this reflects the hedging that we did -- incremental hedging that we did on both, natural gas equivalents and power.

So I don't think you should -- this is an indication.

This is a direction, but it's not one-to-one drop to the bottom line.

I mean, there are other things that are not captured completely in that line.

Right.

But if I just think about the fuel side, we haven't seen PRB coal move a lot or lignite move a lot, and I think you had probably already procured your uranium.

So it's really just -- and gas prices haven't exactly spiked a ton in the last couple of months.

So unless it's just something dealing with the retail offset and maybe having retail contract that don't just pass through the fuel clause, I would assume that, at least, a large portion of this incremental $1 billion would flow to you, if not all of it?

Well, I mean, with respect to Retail, keep in mind that in 2019 and 2020, I mean, any price changes affect every single retailer.

So I think the dynamic that we have seen when prices increase and benefits wholesale and Generation and perhaps put some pressure on Retail, that doesn't happen in '19 and '20 because all retailers are exposed to the same price of electricity.

So I think that addresses your concern around Retail.

And then with respect to -- that's why we provide the sensitivities.

I mean, I think, the sensitivities give you a sense on how our portfolio behaves depending on the different market conditions.

And I would actually -- I think, that's perhaps a more comprehensive way to look at how our portfolio will -- how the changes in the prices will impact our portfolio.

So I would direct you more to the sensitivities as opposed to this one line that is very specific on revenue.

Thank you.

With that, we'll turn the conference back over to Mr. Gutierrez for closing remarks.

Well, thank you.

It was great talking to you, and I look forward to continuing our conversation in the third quarter call.

Thank you, all.

Thank you.

Ladies and gentlemen, that concludes today's conference.

Thank you very much for your participation.

You may all disconnect.

Have a wonderful day.