NRG Energy, Inc. (NRG) Q2 2022 Earnings Report, Transcript and Summary

Good day and thank you for standing by. Welcome to the NRG Energy Inc.'s Second Quarter 2022 Earnings Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. [Operator Instructions]. Please be advised that today's conference is being recorded. I would now like to hand the call over to today’s speaker, Kevin Cole, Head of Investor Relations. Please go ahead.

Thank you, Felicia. Good morning and welcome to NRG Energy's second quarter 2022 earnings call. This morning's call will be 45 minutes in length and is being broadcast live over the phone and via webcast, which can be located in the Investors section of our website at www.nrg.com under Presentations 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, our Chief Financial Officer. Also on the call and available for questions we have Liza Killinger, Head of Home; Rob Gaudette, Head of Business and Market Operations; and Chris Moser, Head of Competitive Markets and Policy. I'd like to start with the three key takeaways of today's presentation on Slide 4. We are maintaining our financial guidance ranges as we continue to navigate through volatile market conditions and are increasing our capital available for allocation by $140 million. We continue to make good progress in achieving our strategic growth priorities particularly on direct energy integration. And finally, our share repurchase program continues with approximately $600 million in remaining capacity to be executed this year. Moving to the second quarter financial and operational results on Slide 5, we delivered $358 million of adjusted EBITDA for the second quarter. 70% of the difference compared to last year are items that we previously identified, including asset sales and transitory items. The remaining variance is primarily driven by the forced outage of our 610 megawatt coal unit at the W.A. Parish facility. This outage began on May 9th, and is expected to be back for summer operation next year. The unit is covered by both business interruption and property damage insurance. I am pleased to report that we once again achieved top decile safety performance for the quarter and that we published our 12th sustainability report, a testament to our commitment to transparency and accountability. We also continued to realize strong customer retention which I will discuss in more detail shortly. We continue to make progress on our five key strategic priorities. Integrate direct energy, perfect our integrated platform by better matching retail with supply, grow our core electricity and natural gas businesses, integrate adjacent products or services that will allow us to expand margins and term from our customers, and return capital to our shareholders. I'd like to give you a quick update on those priorities. The direct energy integration is going well and we are on track to achieve our run rate synergies of $300 million by the end of 2023. In late June, we received ERCOT securitization proceeds related to Winter Storm Uri in line with our expectations. We have continued to make progress on our mitigation efforts, and now expect an additional $80 million in recovery, bringing our total mitigation efforts to 70% of the original impact. We continue to optimize our supply portfolio through monetization of the Watson Generation facility in California and retirements of fossil assets in PJM. We have also expanded our capital like PPA strategy to focus on energy storage and quick start natural gas generation. I expect PPA market conditions to improve into year-end, especially if the proposed Inflation Reduction Act is passed. Our retail brands continue to perform well with the strong customer count, retention metrics, and an unmatched ability to generate insights on price elasticity. We remain focused on expanding our product offerings and improving our digital customer experience. I am proud that one of our flagship brands, Reliant Energy was also recognized as the best electricity company in Houston, our hometown. Last quarter, I spoke about Goal Zero, our resilience and battery storage business and the significant opportunity it represents given growing grid instability and extreme weather events. During the quarter, we launched a marketing campaign in one of its core markets, California to increase awareness for the product and brand with very strong results. As a result of these targeted campaigns, web traffic increased 400% and the average order increased by almost a third. We continued to make progress in other areas, but remain keenly focused on pacing our investments as we navigate ongoing supply chain constraints and recessionary environment. Finally, we are maintaining our financial guidance range, but due to the impact of the W.A. Parish unit outage, we're currently trending towards the bottom end. We have been focused on taking steps like one time cost savings and incremental direct energy synergies to improve our results. Alberto will provide details on this and the additional capital available for allocation. Turning to Slide 6 for our market review in Texas. ERCOT experienced record hit during the quarter, 32% above the 10-year average, resulting in record peak demand. However, real-time power prices were mixed versus what the forward indicated, driven primarily by the performance of renewable energy on any given day. As we look into the summer, we expect prices to remain volatile and highly dependent on renewable performance. Turning to the right-hand side of the slide, beginning with retail. We saw a strong performance through the quarter with retention 5% ahead of expectations and customer count increasing 1.2%. We also extended term length of customer offers, which enables new [ph] management and improves margin predictability. This occurred while consumers grappled with inflation, only further demonstrating the resilience of our retail brands and pricing strategy. On supply, the unplanned outage at W.A. Parish Unit 8 impacted performance. While there is an earnings recognition delayed given the time line to receive business interruption insurance proceeds, insurance is an effective tool to mitigate this risk. Beyond that, we have seen strong operational performance from our fleet due to our expanded spring outage maintenance plan and opportunistic maintenance outages, that best positions our fleet to perform through these extreme and extended summer conditions. Finally, our balanced hedging strategy that uses both own generation and third-party contracts further derisks our portfolio through optimizing operational versus counterparty risk, which are important attributes through current market conditions. Now moving to Slide 7. Just like we did last quarter on Goal Zero, today I want to focus on one area of growth that is complementary to our core offerings and presents an exciting opportunity, heating and pulling our HVAC maintenance and installation. Airtron is our Home Services HVAC company, which was acquired as part of Direct Energy. It represents a complementary offering to our existing core products as HVAC systems use the most energy of any single home appliance, responsible for up to 50% of a home energy consumption. The HVAC industry with a total U.S. addressable market of $100 billion is highly fragmented and traditionally served by local providers with limited scope and reach. In contrast, Airtron operates in nine states, which represents a $10 billion serviceable market, including Texas, where they hold leadership positions in both Houston and Dallas with a single recognizable brand and scale that is unmet. Combined with our existing consumer services platform, we can grow both within our existing customer base and through expansion into new territories, creating a significant and compelling opportunity. In the last three years, Airtron has grown revenues 11% per year to $450 million with gross margins of 30% or more. The revenues come from residential new construction, services and maintenance, as well as direct-to-consumer home replacement. Our early insights suggest that there is significant growth potential in direct-to-consumer home replacement, given energy efficiency initiatives and extreme weather that shortens the lifetime of HVAC systems. The ability to leverage our existing consumer base and sales channels to augment the direct-to-consumer growth while cross-selling with our electricity and gas customers is precisely the type of value opportunity that increases margin and retention that we highlighted during our Investor Day. I look forward to providing you updates on their progress as we integrate these solutions closer with our core energy offerings. So with that, I will pass it over to Alberto for the financial review.

Thank you, Mauricio. I will now turn to Slide 9 for a review of the second quarter results. NRG delivered $358 million in adjusted EBITDA, a $298 million decrease versus prior year, excluding the impact of Winter Storm Uri. As you can see in the waterfall chart, this decrease is primarily due to the previously guided impact of the 4.8 gigawatt fossil asset sales completed in December, PJM assets retirement in the second quarter, New York capacity revenue, and early settlement of demand response revenue in the second quarter of 2021. In addition, not included in our expectation where the extended unplanned outage at Parish Unit 8 and the modest amount of growth expenses. From a regional perspective, adjusted EBITDA in Texas declined $61 million compared to the second quarter of last year. As Mauricio said in his scripted remarks, summer came early with record setting temperatures beginning in May raising both market prices and build volumes. On May 9th, a fire at the Parish facility caused an extended outage at Unit 8 and a 10-day outage at Unit center. We were therefore forced to replace the power with the combination of our more expensive out of the many generation hedges, and some opportunistic market purchase, which together impacted EBITDA by an estimated $70 million. In addition, the benefit normally associated to higher build volumes with our home and business customers, affect the impact of additional outages on our remaining Texas fleet and higher maintenance expenses recorded in the quarter. Finally, we were able to fully offset the previously disclosed transitory items, which includes the limestone outage and the ancillary costs for a total negative $61 million with some nonrecurring items of $79 million, which include an earlier-than-anticipated partial insurance reimbursement of the business interruption expenses aligned to Unit 1 and the early testament of an online PPA. Turning on the East, West, and other segments, the year-over-year decline was primarily driven by the $63 million EBITDA reduction from asset divestiture and retirement, as well as by the decline in demand response revenue associated with an early settlement in the second quarter of 2021. Next, compared to Texas where the impact of coal constraints was minimal, generation in this continues to be impacted by coal availability for a $23 million impact during the quarter. After accounting for these previously guided items, the remaining $63 million negative variance versus 2021 was driven by the combination of lower power volumes, reduced profitability at our Watson facility, which was monetized during the quarter, an intra-year timing related to C&I customer hedge monetization, which will be recovered through the second half of this year as we associated to retain hedges cycle and the balance by higher supply costs. Next, I will provide you a brief update regarding our progress in achieving Direct Energy savings and mitigating Winter Storm Uri impact. Direct Energy, incremental synergies from the beginning of the year reached $39 million. We remain on track to achieve our full year target of $50 million in 2022 and $225 million since the acquisition of Direct Energy. We also expect to improve the recovery of our 2021 losses from Winter Storm Uri. You may recall that at the end of the last year, we estimated that the final impact net recovery was going to be $380 million. During Q2, we were able to make progress in several areas where we have remaining gross losses and therefore, we have improved our estimates by $80 million, bringing the net impact to $300 million. Now let's move to the full year guidance. As Mauricio mentioned, we are maintaining our guidance range but based on the recent events, we are trending to the bottom of the guidance ranges. The full year impact from the Parish Unit 8 outage based on current prices, is estimated to be a little over $200 million. The fleet carries both business interruption insurance for lost earnings and property damage insurer to cover the cost of returning the unit to full operation. Given that the outage started at the beginning of May, the second quarter impact reflects the deductible period. As of today, we're assuming the business interruption insurance proceeds will not be collected until 2023. However, the property damage proceeds will more closely match the expenses and the maintenance CAPEX deployed throughout the time needed to restore the unit. Additionally, for free cash flow before growth, we continue to closely manage the impact to working capital from higher commodity prices, primarily in our natural gas business. To be clear, as for the transitory items disclosed at the end of last year, we have taken and we will continue to take steps aimed to improve our position. In particular, we have identified a serious opportunity in managing our costs and operating expenses, including early realization of synergies and onetime reduction of expenses. And as you know, we manage our business for cash so we have also incorporated action to improve cash generation and mitigate our net working capital increases, including through the recovery of property damage proceeds and noncore asset sales. We look forward to providing you additional updates throughout the year. I will turn now to Slide 10 for a brief update of our 2022 capital allocation. Moving left to right, the midpoint of our free cash flow before growth guidance remains unchanged at $1.290 billion. Next, we received $689 million of securitization proceeds from ERCOT related to Winter Storm Uri in late June, which net of the bill credit issued to C&I customers brings the total net inflow for 2022 to $599 million. As mentioned before, we expect to receive an incremental $80 million of cash proceeds from some additional recovery. Focusing next on change from last quarter, since mid of this year we have repurchased an additional 143 million of shares towards our $1 billion repurchase program, leaving a robust $595 million to be completed by year-end. Next, we have reduced the amount of expected other investments by the net cash proceeds of the sale of our interest in the Watson facility for $59 million. Lastly, given the additional Uri recovery and asset sales net cash proceeds, we have increased capital available for allocation by $141 million. As you see in the far right column, the total remaining capital available for allocation is $456 million, of which we have earmarked approximately $100 million to fund the initial project in our $2 billion growth plan, including the initiatives that are being launched to accelerate the growth of our Goal Zero business. The remaining $356 million will be allocated later in the year as we earn the cash. Back to you, Mauricio.

Thank you, Alberto. I want to provide some closing thoughts on Slide 13. During the quarter, we continued to make progress on all our strategic priorities. As we have done in the past, over the remainder of 2022, our team will work tirelessly to improve our results. I am confident we have built the right platform and have the right strategy to deliver strong and predictable earnings and create significant shareholder value. So with that, I want to thank you for your time and interest in NRG. Felicia, we're now ready to open the line for questions.

Thank you. [Operator Instructions]. The first question comes from Julien Dumoulin-Smith of Bank of America. Please go ahead.

Hey, good morning team. Thanks for the time. How are you guys doing?

Good morning Julien.

Yeah, hey. So Mauricio, I'd love to hear -- I want a couple of strategy questions to you today. As you think about this year, how do you think about the desire to continue with the generation portfolio, have the latest events pushed you towards saying maybe we should reevaluate the integrated strategy and the pivot towards retail or actually, are you even more convinced in this strategy and could we see you engaging in more contracting? And maybe to that end, could you also marry this up with some of the comments around PPA strategy you guys have been undertaking in prior periods, are you thinking about doubling down on that considering the higher energy price environment today?

Sure. Well Julien, let me start with the retail engine. I mean, as you can see on the numbers, it is incredibly, incredibly strong. Customers are in this environment, I described them as a flight to safety and obviously, Elizabeth can talk a little bit more about that. But when I think about the supply strategy, you really need to think about, okay, what is the retail that I need to serve and what is the supply that better serves that retail. It always starts with that. Now we have been in a path where we don't want to rely completely on our own generation to supply our retail. We want to make sure that we have a supply strategy that is diversified. And that was the big lesson learned from Winter Storm Uri. We don't want to have a single point of play there [ph]. So what you should expect in the future is a combination of our own generation and third-party megawatts to supply our retail loan. Now on the generation side, obviously we are -- we always have invested in the fleet. Right now, I think the maintenance CAPEX that we have on the fleet per year is in the order of $200 million. But we have to recognize that the generation fleet has been going through a period, almost a 10-year period of very low gas prices. And our maintenance CAPEX is sized according to that, right. Not every megawatt matter in a $2 or $3 gas price environment. Now that it is resetting itself to much higher natural gas and power prices we're going to right size our maintenance CAPEX to make sure that every megawatt is available because every megawatt matters at a dollar per MMBtu. So that's the first thing that I will say on the generation side. Now on the third-party megawatts, we actually use a combination of things. The first one is we have PPAs. We started that with wind and solar and now we have expanded that to storage and some gas peakers. And I can talk to you about the opportunities that we have within our own fleet for those gas peakers and how do we partner with other people on that. We have tolling agreements, we have bilateral physical contracts, we have financial hedges. So it is a combination of things that allow us to just have a very diverse supply strategy. Now remember, the main difference between own generation and third party is that on our own generation, we are exposed to operational risk. And on the third-party megawatts, we're exposed to counterparty risk. But the attributes of those megawatts are basically the same. It is just what type of risk you want to carry. So as I think about in the future, the strategy of relying on third-party megawatts is completely consistent with how we see things in the future. We're seeing more wind, more solar, we're going to start seeing more storage, and we want to make sure that our supply is keeping up with the transition that we're seeing in the electric grid, right. So just relying on our generation portfolio, is not keeping up with the transition that we're seeing in the market. And that's why this combined strategy of own generation and third-party megawatts, I think, is the right strategy to better serve our load.

And just to clarify and boil that down to make sure I heard that essence of the last one. Are you talking about contracting out more gas peakers and could that result in new gas peakers in for instance, ERCOT here, just to make sure I'm hearing this right?

Correct. So when you think about the PPA strategy, we started with wind and solar, and this is really bringing new megawatts to the market. We provide them long-term contracts because our retail supply, our retail low, and we can actually bring these new megawatts to market because they can now finance those power plants. We're now extending that to storage, and we actually are running RFPs on storage that gives us a lot of visibility in terms of what's in the market. For now, we have expanded that to gas peaking. And the gas peaking, not only we need to -- we can rely on developers but keep in mind, we already have a lot of brownfield opportunities within our sites. And I will tell you today that we've been working over the last year and half in identifying new projects. We actually have one that is show already fully permitted. Another one is right behind it. And right now, we want to explore potential partnerships where we can bring capital from other entities, we can take the offtake and we can be also the developer since we have a long history of power plant development. So I think it can be a win-win for everybody. So we don't need to use our own capital to develop these plans and still benefit from this incremental megawatts in the grid.

Right. And just to make sure I'm hearing you right, this would be effectively monetizing upfront the development rights that you have on your brownfield to another party that you're developing megawatts, not taking the operational risk, but ultimately enabling new assets to be developed in ERCOT.

Exactly.

Alright, excellent. I have asked you enough here, but thank you so much for elaborating on that, really critical here. Thank you.

Thank you Julien.

Our next question comes from Shahriar Pourreza of Guggenheim Partners.

Hey guys, good morning.

Good morning Shar.

Mauricio, as we look at sort of the balance of the year, how should we sort of think about maybe the size and shaping of the lever as you laid out to maybe help get you back to that midpoint, could sort of that synergy upside from Direct Energy health there?

Yes. I mean there will be a combination of things, Shar. As Alberto pointed out, I mean, we're looking at -- and we've been working on this because as part of the transitory items, we wanted to mitigate also those transitory items. So we've been working on this throughout the year. That is -- do we have the opportunity for onetime cost savings, obviously, the Direct Energy synergies, we feel very comfortable with the number, but we are now looking at spicing that and working on it. Obviously, we need to make insurance proceeds and whether we can accelerate some of these insurance proceeds, and Alberto already mentioned some of that. Look, I mean, that's not completely dependent on us, but that doesn't mean that we're going to work hard to accelerate that. And then -- so I would say that some are some of them are levered. I also want to mention that we run this business for cash. And I think the sale of Watson, it is an example of us being completely focused in monetizing the value of our portfolio. And if we can accelerate some of the divestitures of noncore assets, we're going to continue to do that, to bring cash in this year to make up for the cost of the unit insurance outage. So there is a number of things that we're doing Shar to make up for the lost earnings of the Unit 8 outage.

Okay, perfect, that helps there. And then just lastly, I know you guys mentioned retention is exceeding your internal targets. Just is this split fairly evenly between East Texas or is it skewed? And then just curious how East has held up with a heavier C&I book? Thanks.

Sure. I'll turn it over to Elizabeth for kind of the East Texas split, but I will tell you that the -- I mean, the retail engine is really, really strong. And as I said in the previous answer, we're seeing a flight to safety and our brands are that flight to safety. So we're seeing really, really strong numbers, but Elizabeth, can you provide additional detail.

Yes. Thanks for the question, Shar. We are seeing really strong retention Mauricio mentioned, 5% above expectations. That's really driven by our unmatched analytics and care capabilities. We also have a significant amount of customer and community loyalty and of course, the compelling products. From a Texas versus East, pretty consistent, maybe a slight advantage in Texas, but it's not dramatic. And we're also seeing retention better than expected from the DE acquisition. So really, our -- the strength of our platform right now, especially during the -- with the volatility in the COGS. I mean, we're so pleased with how resilient our platform is through this. And frankly, the strength of our channel, both sales and marketing channels to pivot within regions and between regions. So yes, it really is a strong platform.

Perfect, that is super helpful. Very good color this morning guys. Thanks.

Thank you Shar.

Our next question comes from Michael Lapides of Goldman Sachs.

Hey, guys thank you for taking my questions. And congrats for being able to keep the guidance range during a tough operational time given the Parish outage. Just curious [Multiple Speakers] the history of Texas, shows that there are power price and heat rate blowouts that happened in an unusual time. I mean if I go back in time, you own the Reliant business because of what I thought was an April heatwave blowout that happened 12-14 years ago or so. Just curious, with Parish, one of your base load units out through the second quarter next year, can you just talk about how much gas fire generation you have under contract for next year, meaning whether it's a hedge from a gas-fired unit or whether it's a PPA or a toll from a gas-fired unit, we've seen some periods recently where some of the renewable units were running fine and then all of a sudden due to cloud cover shut down and it caused a price blowout, happened a couple of some days ago in Texas, so just trying to think about how much backup you've got from third-party fossil for the period when Parish is out?

Yes, Michael. So I think in the last earnings, I provided an indication of our hedge for 2023. And if you recall, that one had against the expected law that we have for 2023 half comes from third-party megawatts about half comes from our economic generation. And then we have an economic generation that is maintained as insurance, our own uneconomic generation. So there is a co -- it's just a lot of combination in that third-party megawatts. We have some tolling agreements with combined cycle plants. We have some heat rate options with peakers, we actually have some heat rate options with -- or actually out-of-the-money call options from the financial market. So there is a combination of tools that we have to be able to manage weather variability in any given year. Now as you mentioned, I mean, the second quarter was pretty extreme. We always plan for some weather variability but what we actually saw in the Spring and July is record-breaking heat in Texas. And while we manage for some variability, it is incredibly expensive to manage for all weather variability now. Now perhaps one of the lessons learned here is as we think about 2023 and given that we have a lot of time to plan for how to set up the portfolio for that year, I expect that we're going to buy a little bit more insurance for extreme weather than in the past. And I think that's -- I mean, that's going to be the prudent thing to do given what we're seeing in Texas. I mean the peak -- the record peak was broken by, I think, 5,000 megawatts. I mean the old peak was 75,000. Now the new peak is close to 80,000 megawatts. I mean year-over-year 7%, 8% increase. I mean, that's pretty significant. And I think we need to recognize that. Perhaps we're going to see greater weather, extreme weather events, and we need to plan for it.

Well -- and Texas is showing massive robust demand growth, way above the national average. Part of that is just residential new connect, people moving there. Part of that is [indiscernible] chem industrial demand. Part of it is probably crypto mining, which they're all kinds of dockets that are patents PCT [ph] discussing the impact of that. If we enter a sustained period where Texas load -- peak load growth is in the 3% to 5% range for a number of years, would that alter your power procurement strategy and your asset ownership strategy at all, meaning if demand comes in for a multiyear period, way above what we saw in the last three to five years?

Yes, well, absolutely. So two things on that, if demand is growing at 3% to 4% a year, that's really good for us because if we maintain our market share, that means we're growing our retail business, and that's really, really good, and that's what we want to see. Now obviously, we need to make sure that we keep up our supply strategy with that incremental demand. And the way we're going to do it is, one, as I mentioned, I think there is an opportunity for us to bring new megawatts in some of our current sites and those would be primarily gas peaking and energy storage. And we are -- as I mentioned, we already have at least one project that is being fully permitted and is shovel-ready and now it's just a matter of what's the right partner to bring into the table. We have another one that is right behind it and is in the process of getting permitted. And I'm sure that -- and I will tell you, the team is already looking at other opportunities where we can bring storage there. So I think you're going to see us participate on that new dispatchable quick-start generation opportunity in our sites, but not necessarily with our capital. And we will be the off-taker. In addition to that, we're going to continue bringing new wind and solar and energy storage as we have done already with our current PPA. So we're looking at these in kind of these two ways, bring new megawatts that are viable [ph] cost in the form of wind, solar and perhaps storage. And bring contract also with new gas peaking dispatchable generation in our existing sites, but not necessarily with our capital.

Got it. And one last one in this probably in Elizabeth question. Just curious, over the last year or so, can you talk about what your Texas customer count has done since the Direct Energy acquisition, so January of 2021, like how much is your mass market customer count up since the Direct deal meaning if I did it apples-to-apples? And then what are you seeing on the residential level at a usage per customer basis?

So from a customer count perspective, year-over-year between -- since the DE acquisitions, relatively steady, a slight decline. And as I have mentioned before on calls, from a customer count perspective, year-over-year between -- since the DE acquisition, relatively steady, a slight decline. And as I have mentioned before on calls, when we do both book acquisitions and large acquisitions, there's a bit of a settling period in the first year or two. And so we've seen that. But as I mentioned earlier, we're performing better than we expected and modeled from those acquisitions. From customer usage perspective, in the ERCOT market relatively steady, although with weather we're seeing an increase especially in this second quarter versus prior period. So we do expect customer usage to be either steady or growing with the electrification of people’s lives and communities.

Right. I mean, I think, Michael, you need to think about that usage in two contexts weather normalize and then weather affected. And I think what you saw in Q2 is a significant increase in usage per customer because of weather. But we're also seeing an increase in usage per customer because of the electrification of the economy, right. So you can point to electric vehicles, you can point to a lot of different things that are driving this electrification that will increase the usage per capita.

Got it, thank you guys. Much appreciated Mauricio.

Thank you, Michael.

The next question comes from Angie Storozynski of Seaport.

Good morning. So I wanted to change the topic just for a moment. The pending inflation bill and the benefits that your nuclear plants could get some nuclear PTCs. I'm just struggling to gauge what is the price that STP is hedged at say for the next year or two, as we're trying to calculate the delta between that and the $44 per megawatt hour that this bill would rank?

Yes, good morning Angie. Well, I mean, so clearly, this deal could potentially be a positive for nuclear owners, including us. And as you mentioned, I mean, I think everybody is looking at, okay, what is that trigger that will allow us to get the PTCs or not. So that's a moving target. And obviously, that's a moving target with the market, right, like everybody else. So I'm not sure if I can give you that level of specificity in terms of what price is hedged because we look at it on a portfolio basis. But I mean, this is something that we'll start to -- I guess, outlined as this bill progresses and if passed, then we will need to have that level of clarity to ensure that we can support and justify the incremental PTC, but that's something to be worked on.

Okay. And then going back to the hedging of your retail book. So one thing that sort of surprised me is that, I mean, you -- when you hedge your retail book, you always have all kinds of delta hedges and options in order to protect you against unplanned outages also spikes in usage. So I would have thought that Parish was not a big component of the supply stack to start with, given coal supply constraints, and then you should have had those additional hedges, so I'm a little bit surprised that the impact is this big? And then lastly, when you show your drivers for the year, I don't see any comments about any uptick and bad debt expense and we see it at regulated utilities, so I was just wondering how you manage that?

Yes, Angie. So as you mentioned, we always plan for some forced outages and some weather variability. I think the impact here is that the outage was in a pretty large coal unit close to 600 megawatts with prices where they were in the forward market starting in May. That unit is pretty deep in the money. So as you mentioned, I mean, the coal conservation that we have was really in the shorter months and perhaps in some of these shorter hours. But in the peak hours, this unit was expected to be there to help manage and supply our load. The unique situation here is both happened at the same time. We had a forced outage on a large coal unit exactly at the time when we had record-breaking heat, and that really goes outside of kind of this planning area that we look at. So this was the combination of these two very extreme conditions. And it's not like we don't plan for it, but we don't plan the intersection of both of them exactly as we're leading into the summer. Now we use some of our uneconomic generation, and it was very effective, but this uneconomic generation that we have, some of the gas peakers, they come at a really high cost given where the natural gas price is today. So if you're at $8, $9 gas and you're deploying 12, 13 peak rate peakers, the cost of that is pretty high, although it -- us from buying the cap, for example, but it's still pretty high compared to where the cost of generation is for our coal plant. Anything to add, Alberto.

Yes, Angie, so regarding your question regarding -- related to bad debt expenses, we are not seeing any pickup in the bad debt expenses considered now the level of receivables is much higher, given the level of gas prices and power. So when we see percentage is absolutely in line. And even we look at late payment fees and so on, and it's pretty normal, particularly in Texas. So for the time being, we are not seeing any sign of deterioration of the quality of our receivable portfolio.

Great, thank you.

Thank you Angie.

Our next question comes from Steve Fleishman of Wolfe Research.

Yeah hi, good morning everyone.

Good morning Steve.

Hey Mauricio. The -- you mentioned increasing the maintenance CAPEX on the fleet from the $200 million, how much higher might that go going forward.

Well, I mean we're a value -- yes, Steve I mean we're going to evaluate these. But obviously, if your plants are a lot more profitable than they were, let's say the last five to six years under a low gas environment, they can support incremental maintenance CAPEX. And not only they can support, it's advisable, right. Because right now, every megawatt counts. Before we had a lot more megawatts that were marginal and we don't necessarily need it to have that maximize the output of the plant. Now we really need to maximize the output of the plant. And look, the capacity factors, the amount of time that these plants are going to run are going to be more than they have been in the past, and we need to take that into consideration. So I would say that there will be an increase. I don't think it's a step-up change from the maintenance CAPEX. But it is -- we need to right size it to the amount of run hours that the unit is going to have, number one. And number two, for the profitability of the plant, right. So every megawatt counts, and I want to make sure that we have it available when we need them.

Okay. Great. On the Parish outage and the insurance, so I assume you're not assuming you're going to book any business interruption proceeds this year, it will be next year?

Alberto?

Yes, it is correct. However, based also on the experience with Limestone, we're trying to accelerate the property damage, insurance proceeds, and link it basically to the expenses and the CAPEX that we're going to deploy this year. So that's the area where we see more opportunity.

Okay. So just high level, you have the $200 million plus cost this year. Then next year, there will be some cost that continues in the first half, but then you'll have a benefit for business interruption that should offset -- should be more meaningful than the cost in 2023?

Correct.

Yes. Okay. And then just a high level, I know somebody asked about the impact of IRA for the nuclear plant. But just maybe more broadly, could you -- there's a lot of provisions in this bill in different ways that could impact the business, so just could you just talk to anything else that particularly you're particularly focused on?

Sure. I mean the -- I mean the two big ones is what is the impact on wind and solar, renewable energy, and what is the impact on nuclear, right. So, on wind and solar we can see a reengagement and an acceleration of renewable development which we have benefited from and our team is ready to start the conversation with developers again. And then on the nuclear side, we're going to be looking at what is the benefit that we can have with our SPP facility. And like every other nuclear generator in the country, I'm sure that they're starting to do the math to figure out how do we benefit from these production tax credits. So I would say those are the two big areas where we are focused on and that can impact our business.

Okay, thank you.

Thank you Steve.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes today's program. I will now turn the call back over to Mauricio.

Thank you, Felicia, and I look forward to speaking with you shortly. Thank you.