NRG Energy, Inc. (NRG) Q3 2021 Earnings Report, Transcript and Summary

Good day, and thank you for standing by. Welcome to the NRG Energy, Inc.'s Third Quarter 2021 Earnings Call. At this time, all participants are in a listen-only mode. There will be a question-and-answer session. [Operator Instructions]. Please be advised 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 & 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 five-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 this 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 a $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 plan 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 these upcoming winter. This weatherization standard adopts best practices and addresses weather-related issues that are current during yearly. 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 our 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 commend and thank the governor, legislature, and PUCT for tirelessly working to address the issues Uri exposed and to harden the ERCOT system and protecting 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 two 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 our renewable energy initiative that allows customers to support solar energy without installing panels. Now, moving to the right-hand side of this 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 five-year 15% to 20% free cash flow per share growth plan. In 2022, we remain focused on integrating Direct Energy and achieving the plants 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 smaller 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 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 are advancing our Consumer Services five-year roadmap. 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 related additional synergies achieved in Q3, partially offset by the impact of the outage at Tower Limestone Unit 1 facility and other headwinds related to the onset of supply Country 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 through our PJM coal fleet due to supply chain constraints for chemical necessary to ran 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 priced 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 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 two 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 $135 million negative cash flow [Indiscernible]. On a year-to-date basis, our progress in terms of incremental profitability [Indiscernible] and driven by the acquisition of Direct Energy. Our expectation for the next impact for [Indiscernible] remains at $500 million to $700 million, with the $10 million increase in 1 time costs, offset by a similar increase in the range of expecting mitigants now that positive developments at the Texas legislator and increase the probability of recouping some of our Uri losses. The total negative cash impact as shift this slightly as the estimated bill credits or old to large commercial and industrial customer. Have been reduced by higher billings in 2021. As a consequence, that 2021 Uri negative cash impact has increased by 85 million with their current funding 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 farther areas for cost synergies and were able to realize certain synergies earlier than anticipated. Overall, we are on track to achieve $175 million of synergy for 2021 with 144 million realize the year-to-date. Synergy expectation, As well as one-time 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 has now extended to meet April 2022, constraints in the availability of coal are impacting both costs and volumes. In addition, our Midwest generation coal plants are impacted by 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 to $2.5 billion. We are currently near the bottom of this range, but we are working intensively to improve our results. Consequently, we 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 these lines. Plant [Indiscernible] of east and west power plants, and deactivation 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. 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 anticipated 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 a retirement of our core assets in the east, in mid-2022, EBITDA will decreased 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 after keel facilities and reducing EBITDA by further -- further $30 million. Mentionable, 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 [Indiscernible] 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 if future year. Lastly with the change in the AdCos market, we are expecting an increase in ancillary charges that were initiated after we contracted customer 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 tirelessly to mitigate these incremental costs as best as possible, including further one-time proceedings opportunity. Due to an increased volatility in these environments, we are also increasing the range of our guidance with expectation that we can identify enough mitigants. In 2022 to offset a portion of these costs. The deduction in any 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. In the past, our practice on this large, 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 the free cash flow midpoint to $1.49 billion, reducing available cash by 50 million. Moving to the Winter Storm Uri and as discussed before, that 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 assuming mitigants has increased to $535 million in 2021, and decreased by the same amount in 2022 to only $65 million. As you're aware, the much securitization builds HB4492 and SB1580 have been approved and the regulation has been finalized by our [Indiscernible] 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 gigawatt to our generation in the Easter-west regions, the net cash proceeds of $620 million will be utilized powerfully for data reduction. $500 million to maintain leverage and impact. After incremental fees of $16 million, the remaining 104 million will be available for general capital allocation. This leaves $375 million our remaining capital for allocation, and this capital is dependent on the successful conclusion of securitization process. Finally, of late after reducing our corporate debt balance for 2021, debt delivering 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 3 times net debt to adjusted EBITDA. As discussed during Investor Day, given our growth profile, our goal is to achieve investment-grade metrics or 2.5 to 2.75 net debt to adjusted EBITDA ratio. We remain committed with strong balance Sheet, and continued to target it 2.5 to 2.75 ratio, primarily through the full realization of Direct Energy land rate earnings back to you, Mauricio.

Thank Alberto. So turning to Slide 12, I want to provide an update on our progress executing our five-year growth roadmap. As I told you at Investor Day, two 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 enhance 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 NRG 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 begun 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 air-force for solar, wind, and battery storage in our core markets. Now, shifting to grow the quarter, 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 [Indiscernible] discussed. Although this staging year will not be as growth capital intensive as the later years, it is a crucial year in which we will need to develop data back 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 want to take a moment to review our capital allocation framework and capital available for allocation. Beginning on the left hand side of this slide, we expect to have over $1.6 billion in capital available for allocation, including 375 million of on allocated cash from 2021. We will apply our capital allocation principles that are outlining the right side of this slide. Beyond sake 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 2.75 times by the end of 2023, resulting in the vast majority of our excess cash to be available for allocation throughout 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 these 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 five-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 continue 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 saw consequently 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 will open the line for questions.

Thank you. [Operator Instructions] Your first question comes from the line of Julien Dumoulin-Smith from Bank of America.

Hey, good morning, team. Thanks for the time.

Hey, good morning, Julien.

Good morning.

Hey, good morning. 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 and experienced a pretty solid increase in natural gas prices. So when natural gas prices move up, where coal-generation flexes up and that caused a stress in the coal supply chain because I mean, we have been, for the past four or five years, generating at a certain level, not only us, but the entire coal-generation industry. So when you rapidly flex up, your 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 cost, 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 a very deliberate, this is a balancing act between margin and stability and retention. Now, in terms of the duration of these, I expect these 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 on realized, 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 leverage, 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, this will -- these constraints will ease, and we'll be back to a more normalized, I guess, environment. So I hope that these provides you that 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 coal gen, such that when you think about the existing commitment 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, 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 these 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 on a – in a normalized basis ‘23 and beyond.

Okay. We'll leave it there. Thank you, guys.

Thank you, Julien.

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

Hey, guys. 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 gross initiatives that generates a really high return or to use it to repurchase equity, which may generate an equally higher or 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 pay down versus the timing of other more accretive investments?

Yes, Michael, I mean, we're 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 balance approach of maintaining a strong balance sheet, returning capital to shareholders and growing the Company now. And that we have a tremendous opportunity on growing into these customer service or consumer service opportunities 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 what 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 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 that point. Identify 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 have 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 discount creates value for our shareholders. Since I took over as CEO, we have bought back close to 25% of all the shares outstanding. So this is something that we're going to continue doing, is part of our value proposition, and we're going to remain opportunistic about it.

Got it. And hey, 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 with 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. Perhaps in the short-term, there may be other things that people want to do but I'm looking at long term value creation for our shareholders here.

Got it. Thank you guys. Appreciate it Mauricio.

Thank you, Michael.

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

Hey, good morning, guys.

Good morning, Shahriar.

Well, sorry to sort of beat on this a little bit, but I just want to get a bit of a stronger sense and 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 mitigate d if this isn't a short-term headwind? I mean, why 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 their reliable Think of the system. Chris, do you want to provide a little bit more specifically around and before I go into the 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 off your coal generation, their supply chain takes a little time. I think about mining railroad sets that are allocated to call and chemicals. 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 five or six 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 refer to them as transitory. But, Chris, can you just go into detail around the ancillary service s?

Yeah. Shahriar, they moved up responsive a little bit, couple of 100 megawatts. But the big change that they made in the middle of the summer last year was then moved up the non-spend requirements and that was by a factor depending on the hour and the day between 2 and three X. So that's been the bigger of the two impacts in terms of ancillary changes that they've made so far. Now, we're still waiting to see PUCT is a hard working sessions. And we've seen a memo from Chairman Lake detailing his thoughts. There is 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 incline and whereas the cap, kind of a thing. There's a lot of moving pieces right now in terms of market designs that should be according to the schedule that I've seen nailed down by mid to late December. I think that they're planning on posting something around December 20, which will be their pick of ORDC changes, whether or not they have a winter fuel ancillary in there which is different than these 2 ancillaries I am talking about, what level that they want for the non-spend. And then also we've been advocating for an LSD obligation that would phase in over a couple of years. And Chairman Lake included that in his memo too so -- and 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.

And now, Shahriar, just to be still to be clear. Some of these ancillary costs that preceded describing a lot of them, we pass them through already, 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, just keep that in mind. That's why I call this transitory.

Right.

And over the medium to long run they all make it -- to pass it out.

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

Yes, once again, I think that's in 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 RSPs to get solar wind and we are 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 these works out and then re-engage. 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 PPA's at higher costs. We've been very disciplined in terms of where we actually execute these PPAs. So my expectation is 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 these supply chain issues ease off a little bit.

Great. Thanks, guys. I'll stop there. Appreciate it.

Thank you, Shahriar.

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

Hi, good morning.

Good morning, Steve.

Another [Indiscernible] in cost as 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 kind -- because there is some lag and things and everything like how much is that additional pressure?

So think about this in 2 markets now that we have a power and gas business. So let me start with the gas business perhaps because that's the newest for all of you on the -- 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 exist.

Less on the price of nymex 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 networks that we have. So I'm actually quite comfortable with the exposure of our 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 these 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 are addressing these here as transitory.

Okay. And then just more explicitly asking, I think what others maybe were earlier. The -- obviously when you look at debt to EBITDA targets, EBITDA is lower. It affect meaningfully where you are. 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 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 this on anticipated issue 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 read too much into the number in 2022. I think what is important is our objective in 2023.

Okay, thank you.

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

Thank you. I wanted to start with a question about buybacks. And they need to support the stock clarity. Okay. Well, I understand that the Board usually makes those decisions in the fourth quarter. Well, I'll argue that given today's updates, an earlier decision would have been badly needed. Your peer made some unique decisions on that front. You guys -- 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, 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 continued executing on this balanced approach. But like I said, we are generating tremendous excess cash in the next 13 months. We're going to be deploying that consistently with our target allocation principles. That already gives you an indication. I described 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? That's what we're going to be flexing off. 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 become the FNG, 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 2.3 to normalize 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 your pitch is an attempt to protect those retail margins when all of these charges that we're talking about should have been weighing the profitability of the retail book. And again, I understand you don't separate, but 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 feel like you are attempting to make it seem like it's on the generation side when it 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 off, we always plan to use that additional megawatts to cover our month-on-month customers. We don't have it and the market indicates that we should, but because we have these constraints, we cannot flex that off. We have to buy it as replacement cost. So I wouldn't characterize it as a retail thing. I think that's the -- I'm 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 rate call option on gas, I wouldn't be having this conversation. 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 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 than your pricing every month on a continuous basis.

So just one follow-up here because I guess if the -- I don't quite understand that 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 they economic generation from has in coal plants has 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 plans which -- okay, it's 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 low. 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 this desirable 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 stems from the fact that we cannot flex up our coal generation because of these supply constraint issues.

Okay. Thank you.

Thank you, Angie.

Next question comes from the line of Jonathan Arnold from Vertical Research.

Yeah, good morning, guys.

Hey Jonathan. Good morning.

Hi. 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 they will come back in April. And maybe quantify that what the impact in '21 has been, or is expected to be.

Sure, Jonathan, Chris?

Yes, 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 April 15, right in the middle of April.

Okay.

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

Do you have business interruption what have you insurance on that -- these assumptions?

Yes, there's property damage and business interruption, but that will take a little while to work through right. But we 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 obviously, you mentioned you're confident that these pressures are going to moderate in the second half, is that what's 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. 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 going to mitigate. We're going to be working harder. I'm not pleased with it and I don't want -- these are not realize, these are unrealized and as long as they're unrealized There is some opportunity to get back to normal number. And then if they, if it gets better, quicker than you can expect upside if it gets worse than we will try to mitigate things. I think we're getting ahead of it, we have a pretty good we believe in terms of how we can mitigate these for 2022. But yes, that's how I would characterize it.

But you're not assuming mitigation currently, right?

No.

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

Correct.

Which are -- could you remind me.

So we have about a $110 million in 2023 in addition to 2. [Indiscernible], I think that's what we -- and obviously, this is just another lever that we're working hard. 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 110 on top of the 2.32 that you would expect, and you're also hoping clearly exceed that?

Correct. And then also keep in mind that you have the remaining of the PJM assets, which is about $40 million, a unit to the [Indiscernible] in order to complete their normalization of your exercise.

I see that. Great. Thank you very much.

All right. Great. Thanks, Jon.

It 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.