NRG Energy Inc (NRG) 2021 Q3 法說會逐字稿

Good day, and thank you for standing by. Welcome to the NRG Energy, Inc.'s Third Quarter 2021 Earnings Call. (Operator Instructions) Please note that today's conference is being recorded. (Operator Instructions)

I would now like to hand the conference over to your host today, Kevin Cole, Head of Investor Relations, to read the safe harbor and introduce the call.

Thank you, Benjamin. Good morning, and welcome to NRG Energy's Third Quarter 2021 Earnings Call. This morning's call 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 and 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 Alberto Fornaro, Chief Financial Officer. Also on the call and available for questions, we have Elizabeth Killinger, Head of Home Retail; and Chris Moser, Head of Operations.

I'd like to start on Slide 4 of today's presentation. Our consumer services platform performed well through this summer and delivered stable results. We are narrowing our 2021 financial guidance at the low end of the range and initiating 2022 financial guidance. Our platform is navigating the unprecedented supply chain constraints, and we are actively working to mitigate the financial impact. Finally, we continue to make progress on our 5-year growth plan. In the near term, we are focused on the Direct Energy integration, organic growth in power and gas, and expanding our customer base with dual product options.

Moving to the financial and operational results for the third quarter on Slide 5. Beginning on the left-hand side of the slide, I want to start with safety. We delivered another quarter of top decile safety performance. This marks 10 straight quarters at this level of performance, a testament towards our strong safety culture. As we continue our return to the office, the safety and well-being of our employees remains our top priority. During the third quarter, we delivered $767 million of adjusted EBITDA, which brings our year-to-date results to $1.99 billion, or 19% higher than the previous year, driven primarily by the acquisition of Direct Energy. We are, however, narrowing our 2021 guidance to the lower half of the range, primarily as a result of unanticipated supply chain constraints impacting fourth quarter results. This will also impact 2022 guidance, which I will address shortly.

During the quarter, we made good progress on our key strategic initiatives. First, Direct Energy integration is well ahead of pace, achieving $144 million year-to-date or 107% of the original full year plan. We are increasing our 2021 target to $175 million, which reflects the early realization of synergy targets in 2021. We are maintaining the full planned target of $300 million run rate in 2023.

Next, in ERCOT, the PUCT continues to advance necessary actions to improve market reliability. In October, the PUCT implemented Phase 1 of the winter weatherization standards, which will be in effect for this upcoming winter. This weatherization standard adopts best practices and addresses weather-related issues that occurred during Uri. We are making the necessary investments in our fleet to be in compliance and ready for winter operations.

On market design, the PUCT remains focused on a comprehensive solution to improve reliability and incentivize dispatchable resources. At NRG, we support this direction and have taken a leading role in offering ideas for the PUCT's consideration. We have proposed a comprehensive solution to prioritize reliability and achieve it through competitive solutions. The PUCT also approved the final orders for securitization to ensure a healthy and competitive market. I want to comment and thank the governor, legislature and PUCT for tirelessly working to address the issues Uri exposed and to harden the ERCOT system and protect the integrity of the competitive markets that have benefited consumers over the years.

Now turning to Home Retail. We continue to advance our best-in-class customer experience during the quarter. Our Reliant brand was recognized with 2 awards during the quarter. The North American Customer Centricity Award in the Crisis Management category and the 2021 Innovation Leader Impact Award for the Make It Solar offering, which is a renewable energy initiative that allows customers to support solar energy without installing panels.

Now moving to the right-hand side of the slide to discuss 2022. First, as we detailed during our June Investor Day, 2022 is a staging year for high-grading our business and achieving our 5-year 15% to 20% free cash flow per share growth plan. In 2022, we remain focused on integrating Direct Energy and achieving the plant's high-quality synergies, removing or streamlining our East generation business that continues to weigh on our valuation given earnings and terminal value concerns that otherwise would have masked our retail growth, deploying small amounts of capital to prepare the platform for growth and returning a significant amount of capital to shareholders.

With that, we're introducing 2022 financial guidance of $1.95 billion to $2.25 billion of adjusted EBITDA and free cash flow before growth of $1.14 billion to $1.44 billion. This guidance reflects our plan to fully realize our planned synergies and to streamline our East generation business. Also impacting this guidance are temporary impacts from unforeseen supply chain constraints, ancillary services charges in ERCOT and our previously announced Limestone Unit 1 outage through April 2022. But leave no doubt, now that we have identified these near-term headwinds, we are focused on mitigating these impacts into 2022.

Finally, we are also announcing an 8% increase in our 2022 dividend, in line with our stated dividend growth rate of 7% to 9%.

Now let me turn the call over to Alberto for a more detailed financial review. And after, I will discuss how we're advancing our consumer services' 5-year road map. Alberto?

Thank you, Mauricio. Moving to the quarterly results. I will now turn to Slide 7 for a brief review of our financials. For the quarter, NRG delivered $767 million in adjusted EBITDA, or $15 million higher than the third quarter of last year. The increase in consolidated earnings was driven by the acquisition of Direct Energy and the related additional synergies achieved in Q3, partially offset by the impact of the outage at our Limestone Unit 1 facility and other headwinds related to the onset of supply chain constraints.

Specifically by region, the East benefited by $89 million, driven by the expected contribution from the Direct Energy acquisition and some incremental synergies and cost savings. This benefit was partially offset by reduced volume in our sale of power as well as lower profitability from our PJM core fleet due to supply chain constraints for chemical necessary to run the environmental controls.

Next, our Texas region decreased by $68 million due to the higher supplier cost to serve our retail load. With the outage of Limestone Unit 1, we had to purchase higher price supply to supplement this lost generation. This increase in supply cost was partially offset by the contribution from the Direct Energy acquisition. As a reminder, we benefited the last year from exceptionally low market power prices realized during the COVID-driven economic shutdown and a favorable mix in usage between home and business customers.

The free cash flow before growth in the quarter was $395 million, a reduction of $230 million year-over-year, driven primarily by 2 factors, a $75 million increase in cash interest due to the $3 billion in Direct Energy financing in late 2020 and second is the movement in inventory. During Q3 2020, we reduced inventory by $60 million, driven by seasonal trends and coal utilization. While during Q3 2021, we built up inventories by $75 million, mostly for the seasonal needs of the gas business. This overall resulted in a $135 million negative cash flow balance.

On a year-to-date basis, our progress in terms of incremental profitability is significant and driven by the acquisition of Direct Energy. Our expectation for the net impact from Winter Storm Uri remains at $500 million to $700 million with a $10 million increase in onetime costs, offset by a similar increase in the range of expected mitigants now that positive development and the Texas legislator have increased the probability of recouping some of our Uri losses.

The total negative cash impact has shifted slightly as the estimated bill credits owed to large commercial and industrial customers have been reduced by higher billings in 2021. As a consequence, the 2021 Uri negative cash impact has increased by $85 million with a corresponding movement in 2022. We expect to receive the majority of the securitization proceeds during the first quarter of 2022 with a possible first tranche later this year.

Now turning to the Direct Energy integration. We are confirming our goal to achieve a run rate of $300 million synergies by 2023. During 2021, we have identified further areas for cost synergies, and we're able to realize certain synergies earlier than anticipated.

Overall, we are on track to achieve $175 million of synergy for 2021, with $144 million realized year-to-date. Synergy expectation as well as onetime cost savings achieved so far are fully embedded, respectively, in our 2021 guidance and year-to-date actuals.

As you are all familiar, supply chain constraints are affecting many industry across the country, and they are affecting our operation as well. In addition to our Limestone Unit 1 outage, which is now extended to mid-April 2022, constraint in the availability of coal are impacting both costs and volumes. In addition, our Midwest Generation coal plants are impacted by a shortfall in necessary chemicals to run the environmental controls of the fleet.

Due to these constraints, we are now narrowing our guidance to the lower end of our original guidance to $2.4 billion to $2.5 billion. We are currently near the bottom of this range, but we are working intensely to improve our results. Consequently, we have also narrowed our free cash flow before growth guidance to $1.44 billion to $1.54 billion.

Moving to Slide 8. We are initiating guidance for 2022 to $1.95 billion to $2.25 billion. This is a significant decrease from our current 2021 results, driven by 3 elements as laid out on this slide, planned divestiture of East and West power plants and the activation of our Midwest Generation, already highlighted in the Investor Day, the reduction in the New York City capacity revenues and the impact from the transitory costs that are related to 2022 only.

As mentioned above, the contribution from Direct Energy would increase in 2022 by $130 million, driven by the anticipated increase in synergies. We have already realized more synergy benefits in 2021, accelerating some action, and therefore, we believe that we can achieve our target for 2022 of $225 million.

Next, we anticipate the sale of our East and West assets to close next month for a net of $620 million in sales proceeds, reducing EBITDA by $100 million going forward. With the retirement of our coal assets in the East in mid-2022, EBITDA will decrease by $90 million in the year.

In addition, due to change in New York capacity market parameters, capacity prices have decreased on a more permanent basis, affecting our Astoria and Arthur Kill facilities, and reducing EBITDA by a further $30 million. As mentioned above, we are experiencing a onetime extended forced outage at our Limestone Unit 1 facility and what we believe to be transitory supply chain constraints that are negatively impacting 2022 results. And we expect to correct them in 2023. With increased power prices, the extended outage at our Limestone facility is increasing our supply cost by $50 million to April 2022.

With the advent of constraints on coal and chemical deliveries and commodity price, we expect fuel and supply cost to increase by $100 million in 2022, while returning to normal levels in future years.

Lastly, with the change in the ERCOT market, we are expecting an increase in ancillary charges that were initiated after we contracted the customers and were not included in our margin price. In the future, these costs will be included in future contract prices. But during 2022, we will incur an incremental $70 million of ancillary costs. This outcome is negative to us, and our management team is working tireless to mitigate these incremental costs as best as possible, including further onetime cost savings opportunity.

Given increased volatility in this environment, we are also increasing the range of our guidance with the expectation that we can identify enough mitigants in 2022 to offset the portion for these costs. The reduction in EBITDA is the primary driver for the lower free cash flow before growth.

I will now turn to Slide 9, where we are updating our plan 2021 capital allocation. As in the past, our practice on this slide is to highlight changes from last quarter in blue. Starting from the left-most column, we have updated the 2021 excess cash with the latest free cash flow midpoint to $1.49 billion, reducing available cash by $50 million. Moving to the Winter Storm Uri, and as discussed before, the midpoint for the net estimated cash impact for Winter Storm Uri remains at $600 million. But given the increased utilization of customer credit in 2021, the net cash impact after assumed mitigants has increased to $535 million in 2021 and decreased by the same amount in 2022 to only $65 million. As you are aware, the much anticipated securitization builds HB4492 and SB1580 have been approved and the regulation has been finalized by ERCOT and the PUCT. We anticipate that the main portion of the financing and release of funds will occur during the first quarter of 2022.

Moving to the next column, to pursue our targeted net debt-to-adjusted EBITDA ratio, we completed the delivering of $250 million, plus early redemption fees of $64 million in Q3, totaling $319 million. Finally, we have added the anticipated sale of 4.8 gigawatts of generation in the East and West regions. The net cash proceeds of $620 million will be utilized partly for debt reduction, $500 million to maintain leverage neutrality. After incremental fees of $16 million, the remaining $104 million will be available for general capital allocation. This leaves $375 million of remaining capital for allocation, and this capital is dependent on the successful conclusion of the securitization process.

Finally, on Slide 10, after reducing our corporate debt balance for 2021, debt delevering and for the minimum cash, our 2021 net debt balance will be approximately $7.9 billion, which, when based at the midpoint of adjusted EBITDA, implies a ratio slightly above 3x net debt to adjusted EBITDA.

As discussed during Investor Day, given our growth profile, our goal is to achieve investment-grade metrics of 2.5 to 2.75x net debt-to-adjusted EBITDA ratio. We remain committed to a strong balance sheet and continue to target the 2.5 to 2.75 ratio, primarily through the full realization of Direct Energy run rate earnings.

Back to you, Mauricio.

Thank you, Alberto. So turning to Slide 12. I want to provide an update on our progress executing our 5-year growth road map. As I told you at Investor Day, 2 of our strategic priorities are to optimize the core and to grow the core. Optimizing the core will focus on strengthening our power and gas businesses, completing the Direct Energy integration and continuing the decarbonization of our generation fleet. The Direct Energy transaction significantly increased our scale and materially enhanced our natural gas capabilities. This created 2 near-term opportunities, increasing our number of pure natural gas customers and expanding our dual product capabilities within our existing network of customers. Efforts in both of these areas are well underway, and we will leverage the collective experience of NRG and Direct Energy teams to execute on our growth in these targeted areas.

In addition to natural gas and dual product customer growth, we will continue to invest in our core power business to extend our market-leading position in competitive retail electricity by continuing to meet the customers, where they are and to deliver the innovation that customers have come to expect from NRG and its family of brands.

The Direct Energy integration is well on track. And today, we are reiterating our full synergy plan targets. Upon closing Direct Energy, we immediately began rationalizing offices in areas with significant employee geographic overlap and completed a number of critical system consolidations without any meaningful impact to the operations of the company. Given that the integration is being led by the same team responsible for executing the transformation plan, we are highly confident in our ability to achieve the synergy targets that we have shared with you.

Our portfolio decarbonization efforts remain ongoing. The 4.8 gigawatt asset sale to ArcLight remains on track to close by year-end with only New York PSC approval outstanding. We have 1.6 gigawatts of coal assets in PJM slated to retire in mid-2022, with the remainder of our PJM fleet under strategic review. We continue to execute on our renewable PPA strategy, having signed 2.7 gigawatts nationally and expect to procure more renewable power through additional RFOs for solar, wind and battery storage in our core markets.

Now shifting to grow the core. Our objectives are centered around distinct customer experiences in both power services and home services. As we work to shape these distinct customer experiences, we will break them down into discrete pieces and apply a test-and-learn discipline in order to refine our customer value proposition, optimal business model and go-to-market strategy. By starting small, it allows us to stay nimble and deploy limited capital while gathering critical market intelligence to inform how we approach these new customer offerings for sustained long-term growth. 2022 will serve as a staging year, where we will be focused on the test-and-learn environment I just discussed. Although this staging year will not be as a growth capital intensive as the later years, it is a crucial year in which we will need to develop data backed conviction in our initiatives in order to have the confidence to deploy more significant capital in 2023 and 2024. We will be sure to share more on our 2022 efforts as the year progresses.

Now as we're turning our attention to 2022 with limited cost on our capital, I wanted to take a moment to review our capital allocation framework and capital available for allocation. Beginning on the left-hand side of the slide, we expect to have over $1.6 billion in capital available for allocation, including $375 million of unallocated cash from 2021. We will apply our capital allocation principles that are outlined in the right side of the slide. Beyond safety and operational excellence, our first use of capital for allocation is to achieve and maintain a strong balance sheet. Our focus is to grow into our target metrics of 2.5 to 2.75x by the end of 2023, resulting in the vast majority of our excess cash to be available for allocation through our 50% return of capital and 50% opportunistic frameworks.

I look forward to providing you a comprehensive capital allocation update on our next earnings call, but this should give you a good idea of our financial flexibility. I am proud of the strength of our platform that, despite near-term supply chain constraints, continues to provide our customers differentiated products and services and, for our shareholders, the financial flexibility to both execute our ambitious 5-year growth plan, while returning significant cash to our investors.

Now turning to Slide 14. I want to provide a few closing thoughts on today's presentation. During the third quarter, we continued to make significant progress on our strategic priorities, but we still have work to do this year. Over the remainder of the year, we expect to close on our announced asset sales and subsequently execute on our capital allocation priorities. As we move into 2022, I am confident our platform is well positioned to deliver strong and predictable results and create significant shareholder value.

So with that, Benjamin, we'll open the line for questions.

(Operator Instructions) Your first question comes from the line of Julien Dumoulin-Smith from Bank of America.

So just to kick things off real quickly. I understand the markets are dynamic and turbulent here. Can you just walk through a little bit more on the coal supply chain basically? And when are you expecting this to resolve itself? And more specifically, how much of this is realized versus unrealized? I just want to understand really the level of further exposure that could exist here as you think about your level of confidence in getting the supplies that you are anticipating to get, if you will?

Yes, Julien. So let me start by -- we've all seen now and experienced a pretty solid increase in natural gas prices. So when natural gas prices move up, our coal generation flexes up and that caused a stress in the coal supply chain because, I mean, we have been, for the past 4, 5 years, generating at a certain level, not only us, but the entire coal generation industry. So when you rapidly flex up, our coal supply chain doesn't flex up as quickly as you would like it to be; whether it's the commodity; the delivery, which is rail; or chemicals, which is to control the emissions. Now when that happens, in a normal circumstance, we will use that incremental generation to serve our month-to-month customers that are on their variable pricing.

Now when we are constrained, when we cannot flex up because of the supply constraints, then we have to go to market and procure at higher prices, which means then we have to make a decision, how much of these higher cost we pass through our customers. Keep in mind that we are balancing here margin stability and retention. So -- and one of the objectives that we have when we see these sudden increases -- short-term sudden increases, we don't want to cause a bill shock to our customers. We want to make sure that we maintain -- that we pass some of the costs, but not all of the cost.

Obviously, in the mid and the long term, you can pass all the costs. But in the short term, you really want to avoid bill shocks because if you lose the customer, you're also going to spend money in acquiring back the customer. So that's why, this is very deliberate. This is a balancing act between margin stability and retention.

Now in terms of the duration of this, I expect this to be primarily in the first half of the year. I think this will ease off in the second half because supply chain and the coal supply chain will respond to increasing pricing levels.

Now to your question around realized and unrealized. Most of these right now is unrealized, but -- because these are month-to-month customers. So we have some levers to mitigate the impact. I mean the first one is, obviously, how do we optimize our coal generation? Should we be looking only at running when you have really high-margin hours and then backing down in low-margin hours? We are in constant communication and testing the market in terms of our retail pricing strategy and priorities. I mean the other lever is Direct Energy synergies, and we're going to continue looking at if we can expand those Direct Energy synergies.

And then finally, as you mentioned, I mean, this is a very evolving story. So things can change fairly quickly, just like the entire system moved up in the back of natural gas. It can come back down to more normal levels, and therefore, these will -- these constraints will ease and we'll be back to a more normalized, I guess, environment.

So I hope that this provides you that, I guess, that framework and that explanation on what we're seeing today.

Excellent. And just to be clear about this, basically, it was more about the gas price increasing and you wanting to ramp per coal to gas switching, your cold gen, such that when you think about the existing commitments that you had on rail, et cetera, those remain intact here, if you will, coming into this fall season and into next year.

And also, if I can throw out just the third question super quickly. Can you just reaffirm here your expectations on '23? And otherwise, I think I heard that already in the commentary. I just want to make sure we're crystal clear on the transient nature of these factors here, especially against your '23.

Absolutely. And I think that's what -- that's how we wanted to lay it out for all of you. I mean there -- we think of this as transitory, specifically for 2022. Both -- some of the supply chain plus the outage in Limestone, I expect that to normalize in 2023. And that's why we wanted to provide you the earnings power of our platform in a normalized basis, '23 and beyond.

Your next question comes from the line of Michael Lapides from Goldman Sachs.

Just curious, you talked about a lot of these things being kind of abnormal or one-off items. As you think about the opportunity set for investing capital, would you be willing to push out the date you get to the 2.25 to 2.75 net debt to EBITDA to use capital for either a growth initiative that generates a really high return or to use it to repurchase equity, which may generate an equally higher, even higher return? How do you evaluate when the market gives you opportunities that may be transient in nature about the timing of wanting to do debt paydown versus the timing of other more accretive investments?

Yes, Michael. I mean we always have to be flexible and aware of the opportunities that we have, right? I mean we cannot be tone-deaf to what is happening around the organization, around our markets. I believe that the value proposition of NRG, it is this balanced approach of maintaining a strong balance sheet, returning capital to shareholders and growing the company now, and that we have a tremendous opportunity of growing into this customer service or consumer service opportunity that we see in the market. So we're very, very excited about that.

Now having said that, I expect 2022 to perhaps be a little bit lighter on the investing in growth as opposed to '23, '24 and '25. What that means is the business -- our business that is generating tremendous excess cash, over $1.6 billion, we're going to be using our capital allocation principles, which is going to be returning capital to shareholders and growing. But since we're going to be only deploying, I would say, a smaller part in 2022, I think you should expect our share of returning capital to be bigger than the 50% that we have indicated in the past. So that's how I would think about it.

Now we continue -- we remain committed to our 2.5 to 2.75 by 2023, and we expect to achieve that through growing our EBITDA. And we grow the EBITDA by executing on the Direct Energy synergies and now with the incremental growth EBITDA that we can generate.

So that's how I would frame it, Michael. Obviously, we'll remain flexible. We'll remain opportunistic, and we are not going to be tone-deaf to what we -- the opportunities that we will see in the market.

Got it. How do you think about for the 2022 cash available for allocation? About when you would make the decisions on the other 50%?

Well, I mean, our plan would be to provide you a lot more clarity in the next earnings call. We would have, at that point, identified what goes to growth investments and what we're going to do to return capital to shareholders. But I think -- I hope that the number that we provided you today gives you a pretty good idea in terms of the magnitude of the excess cash that we have and where are we leaning and where do we see the opportunities to create value. I have said in the past, I believe that buying back our shares at these discounts creates value for our shareholders. Since I took over as CEO, we have bought back close to 25% of all the shares outstanding. So I mean, this is something that we're going to continue doing. It's part of our value proposition, and we're going to remain opportunistic about it.

Got it. And last question, I'll be quick here. Just curious, when the Board -- and we can look at the various financial metrics in the proxy that outline kind of the goals of the company. But just curious, when you have conversations with the Board, what tends to be most important: EBITDA growth, free cash flow per share growth, or is there another metric we should think about?

Well, Michael, I will tell you, it's always free cash flow per share growth because that's what matters to our shareholders, the per share metrics. And we've outlined a 15% to 20% free cash flow per share growth in our 5-year plan. I think that's very, very compelling. We have the excess cash to execute on that, both in terms of growing the numerator and then reducing the denominator while maintaining a strong balance sheet. So I think this balanced approach serves us well in the long run. I mean perhaps in the short term may -- there may be other things that people want to do. But I'm looking at long-term value creation for our shareholders here.

Your next question comes from the line of Shar Pourreza from Guggenheim.

We started to sort of beat on this a little bit, but I just want to get a bit of a stronger sense, I'm still getting questions here on it. The '22 guidance walk. is the normalized '22 EBITDA before transitory cost, kind of a fair run rate target as we're thinking about future years? And sort of the significant coal supply chain cost, can they be mitigated if this isn't a short-term headwind? I mean why I assume this is transitory, especially if the gas curve has longevity? And then the Texas ancillary service charges in bucket 2, what are those exactly again?

The ancillary service was ERCOT instituted a short term -- increasing ancillaries to maintain the reliability of the system. Chris, do you want to provide a little bit more specificity around it? Before I go into the -- but before I pass it on to you, I just want to make sure that everybody understands. Our run rate, we actually have it on Slide 8. We have normalized that to around $2.32 billion.

And we say they're transitory because the transitory supply chain is when you're flexing up your coal generation, the supply chain takes a little time. I think about mining, railroads sets that are allocated to coal and chemicals. So you can -- when the plant can flex up fairly quickly, a supply chain that has been sized for the type of generation that we have experienced for the past 5 or 6 years, it doesn't flex up that quickly. So that's why I said it's going to take a little bit of time. I expect this to be in the first half of the year. I think this is going to ease off in the second half of the year. So that's why I referred to them as transitory.

But Chris, can you just go into detail around the ancillary services?

Yes. Shar, they moved up responsive, a little bit, a couple hundred megawatts, but the big change that they made in the middle of the summer last year was they moved up the nonspin requirements, and that was by a factor depending on the hour and the day kind of between 2 and 3x. So that's been the bigger of the 2 impacts in terms of ancillary changes that they've made so far.

Now we're still waiting to see, right, PUCT has -- had working sessions, and we've seen a memo from Chairman Lake detailing his thoughts. There's plenty of debate about, hey, what do we want to do on ancillaries going forward and certainly on the ORDC parameters, too. Brattle Group is coming in. They're going to study various combinations of at what part of reserves should you start ORDC to kick in, at what slope should it climb and where is the cap kind of a thing.

So there's a lot of moving pieces right now in terms of market design. That should be according to the schedule that I've seen nailed down by mid- to late December. I think that there planning on posting something around December 20, which will be kind of their pick of ORDC changes, whether or not they have a winter fuel ancillary in there, which is different than these 2 ancillaries I'm talking about, what level do they want for the nonspin.

And then also, we've been advocating for an LSE obligation that would phase in over a couple of years, and Chairman Lake included that in his memo too. So there's a bunch of market design stuff that's moving that we'll be getting to here as we get to the end of the year.

Now Shar, just to be clear, I mean, some of these ancillary costs that Chris is describing, a lot of them we passed them through already to our customers. Some of them we -- like I said, we don't want to create a bill shock. So in the medium to long run, all of these ancillaries will be passed through to customers. But in the short term, we're managing these bill shock versus stability of margin and our retention numbers. So just keep that in mind. That's why I call this transitory. And over the medium to long run, they all make it to -- we pass it out.

And then just lastly, you added 500 megawatts of PPAs and ERCOT last quarter. Can you maybe just unpack this a little bit -- what's behind us? What are you seeing in the market right now? And more importantly that some of these input cost pressures and specifically the renewable space, could that potentially impact your future PPA opportunities?

Yes. I mean -- once again, I mean, I think that's a short term. We are seeing some supply chain issues in the solar -- particularly in solar. We are going to be constantly in the market running RFPs to get solar, wind, and we're actually now looking at batteries. They continue to be very attractive from an economic standpoint.

We are probably taking off our feet from the pedal just because it's -- we are aware of the supply chain. So we are slowing down a little bit on these PPAs. We want to see how this works out and then reengage. I think that's the prudent thing to do. I'm very pleased with where we are today in terms of the PPAs that we have been able to sign and the economics that we have been able to achieve. But I also recognize that there is a transitory issue right now with supply chain that I don't want to be signing PPAs at higher cost. We've been very disciplined in terms of where we actually execute these PPAs.

So my expectation is that it has slowed down over the past couple of months. I think it's going to continue like that. And we're going to start picking up when we start seeing the supply chain issues ease off a little bit.

Your next question comes from the line of Steve Fleishman from Wolfe Research.

So just another rising cost is gas prices, which is also lifting up power prices. And you don't mention that as a pressure in '22. Is that something that you feel like you're able to pass along to customers essentially? Or is that also -- because there's some lag in things and everything, like how much is that additional pressure?

Yes. I mean, so think about this in 2 buckets. Now that we have a power and a gas business -- so let me start with the gas business perhaps because that's the newest for all of you under our ownership. Our gas business, think of it as a logistics business. We don't take commodity price risk. Every time we sign a customer, we back-to-back it with natural gas. And as part of that, we get a tremendous amount of, call it, assets pipeline, storage, LDC relationships.

So that infrastructure gives us the ability to manage some of the volatility that exists, less on the price of NYNEX and more on the basis. So I feel very confident that our team has the ability to manage because of that very large infrastructure network, natural gas network that we have. So I'm actually quite comfortable with the exposure of higher natural gas prices on our natural gas business.

And then on the power side, I think we -- I already described it, Steve, in terms of higher gas prices, you have this issue on the coal constraints. But in general, think of this almost as inflationary pressure. We can pass it through, and we actually choose to pass some of that in the long term -- in the medium to long term, you pass everything. And it's going to be a balancing act between -- you don't want to cause a bill shock to our customers. At the same time, you want to manage stable margins and good retention numbers, which are very, very compelling on our business.

So that's how I'm thinking about it. And that's why -- I mean, if it's a structurally higher gas prices, I don't have a big issue with that. I mean the issue, it always comes when gas prices move up very, very quickly. And then you have these constraints on the coal supply chain, and that's what we're addressing this here as transitory.

Okay. And then just more explicitly asking, I think, what others maybe were earlier. The -- so obviously, when you look at debt-to-EBITDA targets, if EBITDA is lower, it can affect meaningfully where you are. So just this '22 EBITDA guidance, are you going to be targeting off of that? Or are you just going to say this is not normal, and we're just going to ignore it?

I mean, I think you need to recognize that '22 is a transition year, and our commitment is achieving this in 2023, which we expect to go back to our normalized earnings. So when you're thinking about our trajectory from where we are today to how we get to 2023, you always have to take into consideration these unanticipated issues that we're seeing on the supply chain. So we remain committed for 2023. We believe that we can get to those credit metrics by growing into them, now not only Direct Energy synergies, but also additional growth EBITDA that we can execute on. And that's how I think about it. So I wouldn't be -- I wouldn't read too much into the number in 2022. I think what is important is our objective in 2023.

Your next question comes from the line of Angie Storozynski from Seaport.

So I wanted to start with a question about buybacks and the need to support the stock, clearly. Okay, well, I understand that the Board usually makes those decisions in the fourth quarter. Well, I'd argue that given today's update, an earlier decision would have been badly needed. Your peer made some unique decisions on that front. You guys, it seems like most of the money that would go to buybacks is not going to materialize anytime soon. And again, there is a need to support the stock. So would you be open to some unorthodox solutions here to again accelerate the buybacks, either, I don't know, either use revolver or something else to just support the stock now?

Well, I mean, as I said, Angie, the first thing is, I think the value proposition of NRG has always been this balanced approach between a strong balance sheet, returning capital and growing. So what you're describing is basically levering up to buy back stock. And at this point, that's not our focus. Our focus is on continue executing on this balanced approach. But like I said, I mean, we are generating tremendous excess cash in the next 13 months. We're going to be deploying that consistently with our capital allocation principles. That already gives you an indication. I describe it as the floor on share buybacks because you can clearly see the $1.6 billion of excess cash. You can look at -- if that's a 50-50, then you know what the dividend number is. You can be confident that the share buybacks that gets us to the 50%, that's -- you should think of that as the floor.

And then on the opportunistic deployment of the other 50%, that's what we're talking about, right? I mean that's what we're going to be flexing up. We want to be opportunistic about it. But I also want to -- I want to stay true to the value proposition that we have indicated to our shareholders. We're not going to be tone-deaf, Angie, and we're going to evaluate all the options that are available to us. And I think our record of execution should tell you that if there is a deep discount on our shares, we will react accordingly, and we have done that in the past.

Okay. And then the second question. So my initial take when I read the press release was that all of these issues that are weighing on that [2.32] normalized EBITDA are related to generation. But really, if you listen to the discussion so far on this call, it seems like all of them are retail-related. And again, I know that you're no longer differentiating between generation and retail, but it seems like you are -- your pitch is an attempt to protect those retail margins, when -- where all of these charges that we're talking about should have been weighing on the profitability of the retail book.

And again, I understand you don't separate, but I mean, again, to me, it just seems like there is a weakening of the profitability of that large retail book for various reasons, some of which you do not control. But I just feel like you are attempting to make it seem like it's on the generation side when that seems like it's more on the retail side.

Well, Angie, it stems from the generation side because when you actually -- if we actually, in a normal circumstance, if our coal generation was able to flex up, we always plan to use that additional megawatts to cover our month-to-month customers. We don't have it, and the market indicates that we should. But because we have these constraints, we cannot flex that up. We have to buy it as we pay in the cost.

So I wouldn't characterize it as a retail thing. I mean I think that's the -- I am trying to connect the two, so you understand the reason why this is happening. It stems from the generation side, but if I actually had a heat (inaudible) on gas, I wouldn't be having this conversation, right? I mean we would be able to flex up those megawatts and serve our month-to-month customers.

So I just want to be careful that I wouldn't -- I actually wouldn't characterize it as a retail concern. This is basically starts with an issue on coal supply that impacts our coal generation economics, which then impacts how we were thinking about managing those month-to-month customers that you're pricing every month on a continuous basis.

Okay. So just one follow-up here because I guess I don't quite understand the hedging strategy here because I would have thought your -- you had your retail book using economic generation at the time of the hedge. And so in light of the higher power prices, the economic generation from coal plants have increased. You don't really have many gas plants, so there's not much of a detriment. So there should be potential excess generation from the coal plants, which, okay, is not materializing because you don't have access to incremental coal supplies, but why would it be a drag versus the initial hedge?

Well, because the month-to-month, you don't have an initial hedge on the month-to-month. You hedge against your fixed price load. And like I said, we are passing some of that cost, but not all of the cost. So on the month-to-month, because you have variable pricing, you have some, but the extent that we have seen in terms of the increase in gas prices that impact power prices really has put us in a position where we need to make a decision. Do we want to pass through all of these at the expense of retention or not, but it all stands from the fact that we cannot flex up our coal generation because of these supply constrain issues.

Your next question comes from the line of Jonathan Arnold from Vertical Research.

A couple of things. Could you just give us a little more on what exactly happened at Limestone? What caused the extension? And how confident are you that it will come back in April? And maybe quantify what the impact in '21 has been or is expected to be?

Sure, Jonathan. Chris?

Yes. So Jonathan, this is Chris. In terms of what happened at Limestone, the duct that connects the back-end controls to the stack collapsed. And so we've gone through the demolition part of that, still finalizing root cause, but very close on that. And we are well underway on the restoration plan, which is expected to be done in 4/15, right, in the middle of April.

It will be -- the plant will be available ahead of summer.

Do you have any business interruption or have the insurance on that (inaudible) assumption?

Yes. There's property damage and business interruption, but that will take a little while to work through, right? But we've notified them. They've been working through it with -- on the process as we've been going in terms of demolition and the reconstruction of it.

Okay. And then just -- Mauricio, you mentioned you're confident that these pressures are going to moderate in the second half. Is that work assumed in the $100 million on Slide 8? Or could that number increase if you don't see that moderation in the back half of the year?

Yes. No. So our number incorporates our expectation. What we're right now seeing and hearing from our railroad partners and coal suppliers -- so this is reflected in this number. Obviously, we're working hard to mitigate this, and I already listed a few of the things that we're doing to mitigate it. I mean we're going to be working hard at -- I'm not pleased with it. And I don't want to -- these are not realized. These are unrealized. And as long as they are unrealized, there is an opportunity to get back to the normal number. And then if they -- if it gets better, quicker than you can expect upside. If it gets worse, then we will try to mitigate things. I think we're getting ahead of it. We have a pretty good visibility in terms of how we can mitigate this for 2022. But yes, I mean, that's how I would characterize it.

But you're not assuming mitigation currently, right?

No.

Okay. And then just finally, on this normalized '22 number, so we're trying to think about what that looks like beyond '22, we'd add the incremental direct synergies, right?

Correct.

Which are, could you remind me?

So we have about $110 million in 2023 in addition to the $2.32 billion. So I think that's what we -- and obviously, this is another lever that we're working hard. I mean, I'm very pleased to see where we are on synergies year-to-date. But we're always going to be looking at additional opportunities to make our platform more efficient.

Okay. So there's about $110 million on top of the $2.32 billion that you would expect, and you're also hoping to exceed that?

Correct. And then also keep in mind that you have the remaining of the PJM assets, which is about $40 million. So you need to deduct that in order to complete the normalization of your exercise.

That is all the time we have for questions. That concludes the Q&A portion of today's conference. I'll now pass it to Mauricio Gutierrez for closing remarks.

Thank you, Benjamin. Well, thank you, everybody, for your interest in NRG, and I look forward to talking to you soon.

Thank you.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the program.