NRG Energy Inc (NRG) — Q3 2021 Earnings Call Transcript

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; 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 to 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 this upcoming winter. This weatherization standard adopts best practices and addresses weather-related issues that are current during the year. 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 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 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 planned high-quality synergies, removing or streamlining our East generation business that continues to weigh on our valuation, given earnings and terminal value concerns, 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.

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 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 through our PJM coal fleet due to supply chain constraints for chemicals 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-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 a $135 million negative cash flow. On a year-to-date basis, our progress in terms of incremental profitability is driven by the acquisition of Direct Energy. Our expectation for the next impact remains at $500 million to $700 million, with the $10 million increase in one-time costs, offset by a similar increase in the range of expecting mitigants now that positive developments at the Texas legislature increase the probability of recouping some of our Uri losses. The total negative cash impact has shifted slightly as the estimated bill credits for 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 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 further 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 realized 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 industries across the country, and they are affecting our operation as well. In addition to our Limestone Unit 1 outage, which has now extended to April 2022, constraints 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 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 three elements: the plant closure 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. 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 core 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 Keel facilities and reducing EBITDA by a further $30 million. Additionally, we are experiencing a one-time extended forced outage at our Limestone Unit 1 facility. We believe these are 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. Due to constraints on coal and chemical deliveries and commodity prices, 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 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 opportunities. Due to increased volatility in these environments, we are also increasing the range of our guidance with the expectation that we can identify enough mitigants in 2022 to offset a portion of these costs. The reduction 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 planned 2021 capital allocation. In the past, our practice on this large, is to highlight changes from the 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, 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 securitizations HB4492 and SB1580 have been approved, and the regulation has been finalized by our regulatory bodies 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 delivering $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 to our generation in the east-west regions. The net cash proceeds of $620 million will be utilized primarily for debt reduction. $500 million to maintain leverage impact. After incremental fees of $16 million, the remaining $104 million will be available for general capital allocation. This leaves $375 million as our remaining capital for allocation, and this capital is dependent on the successful conclusion of the securitization process. Finally, of late after reducing our corporate debt balance for 2021, our 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 to a strong balance sheet and continued to target it 2.5 to 2.75 ratio, primarily through the full realization of Direct Energy integration.

Thank you, 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 enhanced our natural gas capabilities. This created two 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 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 projects 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. 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-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 costs 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 unallocated cash from 2021. We will apply our capital allocation principles that are outlined on the right side of this 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 2.75 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 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 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.

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. Let me start by saying we've observed a significant increase in natural gas prices. When natural gas prices rise, coal generation increases as well, which puts pressure on the coal supply chain. This is because we, along with the entire coal generation industry, have been generating at a consistent level for the past four or five years. When there's a sudden increase in demand, the coal supply chain cannot adjust as quickly as we would like, whether it's in terms of the commodity, delivery via rail, or the necessary chemicals for controlling emissions. In normal circumstances, we would use the additional generation to serve our month-to-month customers on variable pricing. However, when we face supply constraints and cannot increase our output, we have to source additional supply at higher prices, which forces us to decide how much of these increased costs to pass onto our customers. It’s important to balance margin stability and customer retention. One goal during sudden short-term price increases is to prevent bill shock for our customers. We aim to pass on some of the costs without transferring the full burden. In the mid to long term, we can pass on all costs, but in the short term, avoiding bill shocks is crucial because losing customers can be costly when trying to win them back. This creates a careful balance between margin stability and retention. Regarding the duration of these issues, I anticipate they will primarily affect us in the first half of the year, with conditions easing in the second half as the coal supply chain adjusts to higher prices. As for realized versus unrealized costs, most of these are currently unrealized due to our month-to-month customer base. We have strategies to mitigate the impacts, such as optimizing our coal generation to operate mostly during high-margin hours and reducing output during low-margin hours. We're also in ongoing communication about our retail pricing strategy. Additionally, we’re exploring opportunities to expand synergies with Direct Energy. Lastly, this situation is fluid, and conditions can change quickly, similar to how the entire system reacted to the rise in natural gas prices; it can return to more typical levels, easing constraints and normalizing the environment. I hope this gives you a better understanding of our current situation.

Excellent. And just to be clear about this, basically, it was more about the gas price increasing and you wanting to ramp your coal-to-gas switching, your coal generation, such that when you think about the existing commitment that you had on rail, et cetera, those remain intact here, 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 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 how we wanted to lay it out for all of you. I mean, we think of these as transitory, specifically for 2022, both some of these supply chain issues plus the outage at 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 normalized basis in '23 and beyond.

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

Thank you, Julien.

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 growth initiatives that generate 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, we need to remain flexible and aware of the opportunities available to us. It’s important not to ignore what’s happening in our markets. I believe NRG's value lies in our balanced approach of maintaining a strong balance sheet, returning capital to shareholders, and growing the company. We have significant opportunities in customer service and consumer service that we’re excited about. However, I anticipate that 2022 might see lighter investments in growth compared to 2023, 2024, and 2025. Our business is generating a substantial amount of excess cash, over $1.6 billion, and we will focus on our capital allocation principles, which prioritize returning capital to shareholders and growth. Given that we will deploy a smaller portion in 2022, I expect our capital return to exceed the previous 50% we indicated. We remain committed to achieving a net debt to EBITDA ratio of 2.5 to 2.75 by 2023, which we plan to reach by growing our EBITDA through Direct Energy synergies and other incremental growth. We will stay flexible, opportunistic, and responsive to market opportunities.

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 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 we are leaning in terms of opportunities to create value. I have said in the past, I believe that buying back our shares at a discount creates value for our shareholders. Since I took over as CEO, we have bought back close to 25% of all the shares outstanding. This is something that we're going to continue doing, as 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 five-year plan. I think that’s 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.

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 costs 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 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 function of the system. Chris, do you want to provide a little bit more specific details?

Yeah. Shahriar, they moved up responsive a little bit, a couple of hundred megawatts. But the big change that they made in the middle of the summer last year was to move up the non-spend requirements by a factor of 2 to 3x depending on the hour and the day. 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 what PUCT decides in their hard working sessions. We've seen a memo from Chairman Lake detailing his thoughts. There is plenty of debate about what the future is for ancillaries going forward. The Brattle group is coming in, and they are going to study various combinations of what part of reserves should start ORDC to kick in, at what slope should incline and what should be the cap. There are a lot of moving pieces right now in terms of market designs that should be updated according to the schedule I’ve seen by mid to late December. I think that they’re planning on posting something around December 20, which will be their discussion on ORDC changes, whether or not they have a winter fuel ancillary in there which is different from the two ancillaries I’m talking about, and what level that they want for the non-spend. And then also, we've been advocating for a LDC obligation that would phase in over a couple of years. Chairman Lake included that in his memo too.

And now, Shahriar, just to be clear, some of these ancillary costs that Christopher described we pass through already to our customers, some of them we don’t pass through right away. As I mentioned earlier, we want to avoid creating 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 shocks versus stability of margin and our retention numbers. 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, do 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 the short-term. We are seeing some supply chain issues in solar, particularly in solar. We are going to be constantly in the market running RFPs to get solar, wind, and we are actually now looking at battery options as they continue to be very attractive from an economic standpoint. We are probably taking our feet off the pedal just because we are aware of the supply chain, so we are slowing down a little bit on these PPAs. We want to see how these work out before we re-engage. I think that’s the prudent thing to do. I'm very pleased with where we are today regarding the PPAs that we have been able to sign and the economics we’ve been able to achieve. But I also recognize that there are transitory issues right now with supply chain that I don’t want to sign PPAs at higher costs. We've been very disciplined in terms of where we execute these PPAs. So my expectation is it has slowed down over the past couple of months, and I think it's going to continue like that. 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.

Hi, good morning.

Good morning, Steve.

Another question pertains to costs related to gas prices, which are also driving up power prices. You didn’t mention this as a pressure in 2022. Do you think you can pass this cost onto customers, or is there a delay in doing so? How significant is this additional pressure?

So think about this in two markets now that we have a power and gas business. Let me start with the gas business, perhaps because that's the newest for all of you on the market. 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. As part of that, we get a tremendous amount of asset pipeline, storage, and LDC relationships. So that infrastructure gives us the ability to manage some of the volatility that exists.

I believe that our team can effectively manage our operations due to our extensive natural gas infrastructure network. I'm quite comfortable with the impact of higher natural gas prices on our gas business. Regarding power, as I mentioned earlier, higher gas prices present challenges related to coal supply constraints, but we view these as inflationary pressures. We can and do pass some of these costs through to our customers. Over the medium to long term, we will most likely pass on all costs. The key is to avoid shocking our customers with sudden price increases while ensuring we maintain stable margins and solid customer retention, which are crucial for us. Therefore, I don't anticipate significant issues with consistently higher gas prices. Our main concern arises when gas prices spike rapidly, particularly when there are constraints in the coal supply chain, which we see as a temporary issue.

Okay. And then just more explicitly asking, I think what others asked earlier, obviously, when you look at debt to EBITDA targets, EBITDA is lower. It affects 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 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 through Direct Energy synergies, but also with 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. What's important is our objective in 2023.

Okay, thank you.

Thank you. I wanted to begin by discussing buybacks and their necessity in providing clarity for the stock. I realize that the Board typically makes these decisions in the fourth quarter. However, I believe that given the current updates, an earlier decision would have been beneficial. Your competitors have made some distinct choices in this regard. It appears that the funding for buybacks may not be available in the near future, and there is a clear need to support the stock. Would you consider some unconventional options to expedite the buybacks, perhaps by utilizing a revolving credit facility or another method to support the stock now?

The value proposition of NRG has always been a balanced approach that includes a strong balance sheet, returning capital, and growth. What you're suggesting essentially involves increasing leverage to facilitate stock buybacks, which is not our current focus. Our priority is to continue executing this balanced strategy. However, we expect to generate a significant amount of excess cash over the next 13 months, which we will allocate according to our target principles. This suggests that the floor for share buybacks is established by the $1.6 billion of excess cash available. If we divide that equally, the dividend figure becomes clear, and we can be assured that share buybacks will reach that 50% threshold. Think of that as our minimum. We will be strategic with the remaining 50% deployment, staying true to the value proposition we promised our shareholders. We won’t lose sight of our operational focus and we will consider all available options. Our track record demonstrates that if our shares are heavily discounted, we will respond appropriately, as we have 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, the issue originates from generation. If we had coal generation that could adjust, we would leverage that extra capacity to serve our month-to-month customers. Unfortunately, we don't have that flexibility, and market conditions suggest we should, but due to these constraints, we must purchase at replacement cost. Thus, I wouldn't classify it solely as a retail issue. I'm trying to clarify the connection so you grasp why this is occurring. It begins with a problem in coal supply affecting our coal generation economics, which in turn influences our approach to managing month-to-month customers. If I had a heat rate call option on gas, we wouldn't be having this discussion, as we could increase our megawatts and satisfy our customers. Therefore, I want to emphasize that this is not just a retail concern.

I have a follow-up question regarding the hedging strategy. I would have expected that your retail operations would have been based on economic generation when the hedge was established. Given the rise in power prices, the economic output from your coal plants has increased. Since you have very few gas plants, that shouldn't be a major issue. There seems to be potential excess output from the coal plants, but it’s not being realized due to a lack of access to additional coal supplies. Why would this be a disadvantage compared to 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 the cost. So on the month-to-month, because you have this desirable pricing, you have some costs that we can pass on, but the extent of the increase in gas prices that impacts power prices has put us in a position where we need to make a decision about passing these higher costs through to customers and managing retention of those customers. 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.

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 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 the root cause, but are very close on that. We are well underway on the restoration plan, which is expected to be done by April 15, right in the middle of April.

Okay.

The plant will be available ahead of the summer.

Do you have business interruption insurance on those assumptions?

Yes, there's property damage and business interruption, but that will take a little while to work through. But we notified them, and they've been working through it with us on the process of demolition and the reconstruction.

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?

Our number reflects our current expectations based on what we are hearing from our railroad partners and coal suppliers. We are putting in significant effort to address this situation, and I've already mentioned some of the strategies we're using. I’m not satisfied with the current situation, and I want to emphasize that these issues are currently unrealized, which means there is potential to return to normal levels. If conditions improve more quickly, we can anticipate positive results; however, if conditions worsen, we will continue to take steps to manage the impact. I believe we are proactively addressing this, and we have confidence in our ability to manage these challenges for 2022.

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.

Could you remind me?

So we have about $110 million in 2023 in addition to the normalized run rate, I think that’s what we’re looking at. And obviously, this is just another lever that we're working hard on. 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.

I see that. Great. Thank you very much.

All right. Great. Thanks, Jon.

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