NRG Energy Inc (NRG) — Q2 2022 Earnings Call Transcript

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 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 timeline 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's 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 were 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 market generation hedges, and some opportunistic market purchases, which together impacted EBITDA by an estimated $70 million. In addition, the benefit normally associated with higher build volumes with our home and business customers affected 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 settlement 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 insurance 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 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.

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 from you today. As you consider this year, how do you view the desire to maintain the generation portfolio? Have recent events led you to think about reevaluating the integrated strategy and shifting focus towards retail? Or are you even more convinced in this strategy, and might we see you engaging in more contracting? Additionally, could you connect this with your comments on the PPA strategy you've been implementing in prior periods? Are you considering increasing your commitment to that strategy given the current higher energy price environment?

Sure. Let me start with the retail business. The numbers show that it is very robust. In this environment, I see customers opting for safety, and Elizabeth can elaborate on that. When considering our supply strategy, it's essential to identify the retail needs and determine the supply that best supports them. We aim to avoid complete reliance on our own generation for retail supply, instead preferring a diversified supply strategy. This was a significant takeaway from Winter Storm Uri, as we want to avoid a single point of failure. Therefore, moving forward, our approach will include a mix of our own generation and third-party power sources to meet our retail demand. Regarding our generation strategy, we continue to invest in our fleet. Currently, our annual maintenance capital expenditure is about $200 million. However, it's important to acknowledge that the generation fleet has been operating in a low gas price environment for nearly a decade. Our maintenance expenditure has been aligned with those conditions, where not every megawatt is vital in a $2 or $3 gas pricing context. Now that gas and power prices have increased, we will adjust our maintenance spending to ensure every megawatt is available, as each one is critical at higher prices. On the third-party power sources, we utilize various agreements. We initiated power purchase agreements with wind and solar and have expanded to include storage and gas peakers. I can discuss opportunities within our fleet regarding gas peakers and potential partnerships. We employ tolling agreements, bilateral contracts, and financial hedges, creating a multifaceted supply strategy. It’s important to note that with our own generation, we face operational risks, while third-party sources pose counterparty risks. However, the fundamental characteristics of these power sources are quite similar; it's primarily about the type of risk involved. Looking ahead, our strategy of incorporating third-party sources aligns with our vision for the future. We anticipate an increase in wind, solar, and storage options, and we need to ensure our supply adapts to the ongoing shifts in the electric grid. Solely relying on our generation portfolio will not suffice to match the market's transition. This is why we believe that a combined strategy of both our own generation and third-party power sources is the most effective way to address our demand.

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 load, 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 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 a half in identifying new projects. We actually have one that is 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 off-take and we can also be 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.

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 help there?

Yes, there will be a combination of factors. As Alberto mentioned, we are working on mitigating the transitory items throughout the year. We are examining the potential for one-time cost savings. We feel confident about the Direct Energy synergies and are now looking to enhance those efforts. We need to consider the insurance proceeds and whether we can expedite receiving them, as Alberto touched on. While this isn't entirely within our control, we are committed to working hard to accelerate it. Additionally, some aspects are leveraged. It's important to note that we manage this business with a focus on cash. The sale of Watson exemplifies our commitment to maximizing the value of our portfolio. If we can expedite the divestiture of non-core assets, we will continue to do so to generate cash this year to offset the costs associated with the unit insurance outage. We are actively taking steps, Shar, to address the lost earnings from 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 pass it over to Elizabeth for the details on East Texas, but I want to emphasize that our retail operations are performing exceptionally well. As I mentioned earlier, we're witnessing a trend where customers are seeking safety, and our brands provide that reassurance. Consequently, we're seeing very strong results. Elizabeth, could you share more information?

Yes. Thank you for the question, Shar. We are experiencing strong retention, which Mauricio mentioned is 5% above expectations. This is largely due to our exceptional analytics and care capabilities. We also enjoy considerable customer and community loyalty, along with compelling products. When comparing Texas to the East, the results are fairly consistent, with perhaps a slight edge for Texas, though it is not significant. Additionally, retention from the DE acquisition is also exceeding expectations. Overall, the strength of our platform during the current volatility in costs of goods sold is impressive. We are very satisfied with how resilient our platform is, as well as the robustness of our sales and marketing channels that allow us to adapt within and between regions. Indeed, our platform is strong.

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

Thank you, Shar.

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 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 that 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. In the last earnings call, I discussed our hedge strategy for 2023. Approximately half of our expected load will come from third-party megawatts and the other half from our own economic generation, which we also use as a form of insurance alongside our uneconomic generation. We have various agreements in place, including tolling agreements with combined cycle plants and heat rate options with peaking plants, as well as out-of-the-money call options from the financial market. This mix of tools helps us manage weather variability. The second quarter was quite extreme, and while we plan for some variability, the record-breaking heat we experienced in Texas this past spring and July made it very costly to manage all weather fluctuations. Moving forward, I believe we will be purchasing more insurance against extreme weather in 2023 than we have in the past, which is a prudent approach given the conditions in Texas. The peak demand reached about 80,000 megawatts, surpassing the previous record by approximately 5,000 megawatts, representing a significant increase of around 7% to 8% year-over-year. We need to acknowledge the likelihood of more extreme weather events and prepare accordingly.

Texas is experiencing significant demand growth that exceeds the national average. This is partly due to new residents moving there, as well as demand from the chemical industry and possibly crypto mining, which is being analyzed in various patents. If Texas experiences sustained peak load growth in the range of 3% to 5% over several years, would that change your power procurement and asset ownership strategies, especially if demand persists well above the levels seen in the past three to five years?

Yes, absolutely. Regarding demand growth at 3% to 4% annually, it's advantageous for us since maintaining our market share would lead to growth in our retail business, which is what we aim for. We need to align our supply strategy with this increasing demand. We plan to achieve this by potentially adding new megawatts at our existing sites, primarily through gas peaking and energy storage. We already have one fully permitted project that is ready to go, and we are currently identifying the right partner for it. There is another project in the permitting stage right behind it, and our team is actively exploring additional storage opportunities. Therefore, you can expect us to engage in new dispatchable quick-start generation at our sites, but we won’t necessarily be using our own capital for this; instead, we will act as the off-taker. Additionally, we will continue to integrate new wind, solar, and energy storage, as we have already done with our current power purchase agreements. We are focusing on these two strategies: securing new megawatts at viable costs from wind, solar, and potentially storage, and establishing contracts for new gas peaking dispatchable generation at our current sites without relying solely on our capital.

Got it. And one last one in this probably in Elizabeth's 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?

From a customer count perspective, year-over-year since the Direct Energy acquisitions, it has remained relatively steady with a slight decline. As I have mentioned in previous calls, after completing both book acquisitions and large acquisitions, there is often a settling period in the first year or two. We have observed this trend. However, we're performing better than we anticipated and had projected from those acquisitions. In terms of customer usage in the ERCOT market, it has remained relatively steady, although there has been an increase due to weather, particularly in this second quarter compared to the previous period. Therefore, we expect customer usage to either remain steady or grow as people's lives and communities become more electrified.

Right. I mean, I think, Michael, you need to think about that usage in two contexts, weather normalized 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.

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. This deal could potentially benefit nuclear owners, including us. Everyone is looking for the trigger that will allow us to obtain the PTCs, which is uncertain and depends on market conditions. I can't provide specific details about what price is hedged because we consider it on a portfolio basis. However, as this bill develops, we'll clarify our position and ensure we can support and justify the additional PTC if it passes.

Okay. Returning to the hedging of your retail book, I was surprised to find that when you hedge, you typically use various delta hedges and options to guard against unexpected outages and spikes in usage. I would have expected that Parish wouldn't significantly impact the supply stack from the outset, given coal supply constraints, and that you would have had those additional hedges in place. I'm surprised by the magnitude of the impact. Additionally, I noticed that in your yearly drivers, there are no remarks about an increase in bad debt expense, which we've observed in regulated utilities. How do 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 offsets 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, regarding your question about bad debt expenses, we are not experiencing any increase in bad debt expenses despite the significantly higher level of receivables due to current gas and power prices. The percentages we see are completely in line. Additionally, late payment fees are normal, particularly in Texas. For now, we are not observing any signs of deterioration in the quality of our receivable portfolio.

Great, thank you.

Thank you, Angie.

Yeah hi, good morning everyone.

Good morning, Steve.

Hey Mauricio. You mentioned increasing the maintenance CAPEX on the fleet from the $200 million. How much higher might that go going forward?

We are a value-driven company, and we will assess these factors. If your plants are significantly more profitable now than they were over the last five to six years in a low gas environment, they can support additional maintenance capital expenditures. It's not just that they can support it, it's advisable to do so. Every megawatt counts right now. In the past, we had more marginal megawatts that weren't essential for maximizing plant output, but now we need to fully optimize our plants. The capacity factors and the duration that these plants will operate are expected to be greater than in the past, which we must consider. Therefore, I anticipate an increase, but it won't be a drastic change in maintenance capital expenditures. We need to align it with the amount of operational hours the unit will have and ensure it aligns with the plant's profitability. Every megawatt is crucial, and we want to ensure we have them available when needed.

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.

So, at a high level, there is a cost of over $200 million this year. Next year, some costs will carry into the first half, but there should be a significant benefit from business interruption that will likely outweigh the costs incurred in 2023.

Correct.

Yes. Okay. Regarding the impact of the IRA on the nuclear plant, can you speak more broadly about the various provisions in this bill that could affect the business? Is there anything else in particular that you are focusing on?

Sure. The main concerns are the impact on wind and solar renewable energy and the effect on nuclear power. Regarding wind and solar, we are seeing renewed interest and acceleration in renewable development, which we are ready to engage with developers on. On the nuclear side, we will explore the benefits we can derive from our SPP facility. Like other nuclear generators across the country, we are also calculating how to take advantage of the production tax credits. These are the two key areas we are concentrating on that could affect our business.

Okay, thank you.

Thank you, Steve.

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