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spk02: Good day, and thank you for standing by. Welcome to the NRG Inc. Second Quarter 2022 Earnings Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 1-1 on your telephone. You will then hear an automated message advising your hand is raised. 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.
spk00: 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 via webcast. which can be located in the investor 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 now turn the call over to Mauricio Gutierrez, NRG's President and CEO. Thank you, Kevin.
spk05: Good morning, everyone, and thank you for your interest in NRG. I'm joined this morning by Alberto Fornaro, Chief Financial Officer. Also on the call and available for questions, we have Elizabeth Killinger, Head of Home Raul Gaudet, 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 four. 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 five, 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 cold unit at the WA Parish Facility. This outage began on May 9 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 continue 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 and services that will allow us to expand margins and terms 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 ERCIP securitization proceeds related to winter, storm, and 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 Light 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 a 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, a 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 this targeted campaign, Web traffic increased 400%, and the average order increased by almost a third. We continue to make progress in other areas, but remain keenly focused on pacing our investments as we navigate ongoing supply chain constraints and recessionary environments. Finally, we are maintaining our financial guidance range, but due to the impact of the WA Parish Unidate 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 these and the additional capital available for allocation. Turning to slide six for our market review in Texas, ERCOT experienced record heat 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 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 meal 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 WA Parish Unit 8 impacted performance. While there is an earnings recognition delay even 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 are fleet to perform through these extreme and extended summer conditions. Finally, our balance hedging strategy that uses both own generation and third-party contracts further de-risks our portfolio through optimizing operational versus counterparty risk, which are important attributes through current market conditions. now moving to slide seven 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 cooling or 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 US addressable market of $100 billion, is highly fragmented and traditionally served by local providers with limited scope and reach. In contrast, Ertron operates in nine states, which represent 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 unmatched. 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, Ertron 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-consumers 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.
spk04: 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 Yuri. As you can see in the waterfall chart, this decrease is primarily due to the previously guided impact of the 4.8 gigawatt fossil hazard sales completed in December, PGI massive 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 hurling with record setting temperatures beginning in May, raising both market prices and bill volume. On May 9th, a fire at the parish facility caused an extended outage at Unit 8 and a 10-day outage at Unit 7. We were therefore forced to replace the power with a combination of our more expensive out of the money generation edges and some opportunistic market purchase, which together impacted EBITDA by an estimated $70 million. In addition, the benefits normally associated to higher bill volumes with our home and business customers affect impact of additional advantages on our remaining Texas fleet and higher maintenance expenses recorded in the court. we were able to fully offset the previously disclosed transitory items, which include the limestone outage and the ancillary cost for a total of negative $61 million, with some non-recurring items of $79 million, which include an earlier-than-anticipated partial insurance reimbursement of the business interruption expenses and limestone unit one, and the early settlement of an online TPA. Turning on the west, 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 interior timing related to CNI customer edge monetization, which will be recovered through the second half of this year as the associated retained edges settle 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 during 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 snow duty. You may recall that at the end of the last year, we estimated that the final impact net of 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 next 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 aid 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 are assuming that business interruption insurance proceeds will not be collected until 2023. However, the property damage proceeds will more closely match the expenses and the maintenance capital 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 own costs and operating expenses including early realization of synergies and one-time 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 non-core 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 freakish flow before growth guidance remains unchanged at $1,290,000,000. Next, we received $689,000,000 of securitization proceeds from ERCOT related to Winterstone-Urey in late June. which net of the bill credits issued to CNI 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 . Focusing next on change from last quarter, since May 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 investment by the net cash proceeds of the sale of our interest in the Watson facility for $59 million. Lastly, given the additional yearly 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 initial projects in our $2 billion growth plan, including the initiatives that are being launched to accelerate the growth of our Gold Zero business. The remaining $356 million will be allocated later in the year as we earn the cash. Back to you, Mauricio.
spk05: Thank you, Alberto. I want to provide some closing thoughts on slide 13. During the quarter, we continue 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.
spk02: Thank you. At this time, we will conduct the question and answer session. As a reminder, to ask a question, you will need to press star 1-1 on your telephone and wait for your name to be announced. Please stand by while we compile the Q&A roster. The first question comes from Julian Dumond-Smith of Bank of America. Please go on. Hey, good morning, team.
spk05: Thanks for the time. How you guys doing? Good morning, Julian. Good morning.
spk08: Hey. Excellent. So, Mauricio, I'd love to hear a couple of strategy questions for 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 in And maybe to that end, could you also mirror this up with some of the comments around PTA strategy you guys have been undertaking in prior periods? Are you thinking about doubling down on that considering the higher energy price environment today?
spk05: Sure. Well, Julian, let me start with the retail engine. I mean, as you can see on the numbers, it is incredibly, incredibly strong. You know, customers are – In this environment, I describe 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 law 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 Winters from Yuri. We don't want to have a single point of failure. So, you know, what you should expect in the future is, you know, a combination of our own generation and third-party megawatts to supply our retail load. Now, on the generation side, obviously, you know, we are – We always have invested in the fleet. Right now, I think the maintenance cap is 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 cap is sized according to that, right? Not every megawatt matter in a $2 or $3 gas price environment. Now that it's resetting itself to much higher, you know, natural gas and power prices, we're going to right-size our maintenance, you know, 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. uh we started that with wind and solar and now we have expanded that to storage and you know some gas speakers and i can talk to you about you know the opportunities that we have within our own fleet for you know those gas speakers and how do we partner with other people on that we have tolling agreements we have uh 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 on 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. 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 low.
spk08: And just to clarify and boil that down to make sure I heard that essence of the last one, Are you talking about contracting up more gas speakers, and could that result in new gas speakers in, for instance, ERCOT here? Just to make sure I'm hearing this right.
spk05: 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. But now we have expanded that to gas peaking. And the gas peaking, not only we need to, you know, we can rely on developers, but, you know, keep in mind we already have a lot of brownfield opportunities within our site. And I will tell you today that we've been working over the last year and a half in identifying, you know, new projects. We actually have one that is shovel ready, fully permitted. Another one is right behind it. And right now we want to, you know, we want to explore potential partnerships and 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 plants and still benefit from these incremental megawatts in the grid.
spk08: Right. And just to make sure I'm hearing you right, this would be effectively monetizing up front 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.
spk05: Exactly.
spk08: All right. Excellent. All right. Well, I've asked you enough here, but thank you so much for elaborating on that.
spk07: Really critical here. Thank you. Thank you, Julian.
spk02: Our next question comes from Sharir Perez of Guggenheim Partners.
spk09: Hey, guys. Good morning.
spk05: Good morning, Shar.
spk09: Marisa, just 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 levers you laid out to maybe help get you back to that midpoint? Could sort of that synergy upside from direct energy help there?
spk05: Yes, I mean, there will be a combination of things, Char. As Alberto pointed out, I mean, you know, 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, you know, do we have the opportunity for one-time cost savings? Obviously, the direct energy synergies, you know, we feel very comfortable with the number, but, you know, we are now looking at upspicing that and working on it. um you know obviously you know we need to make uh insurance proceeds and whether we can accelerate some of these insurance proceeds and alberto already mentioned some of that and look i mean that's not completely dependent on us but that doesn't mean that we're gonna work hard to accelerate that um and then uh uh so i would say that you know some uh some of some of them are are some of our leverage i also want to mention the 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 vestiges of non-core assets, we're going to continue to do that, to bring cash in this year to make up for the cost of the Unit 8 insurance outage. So there is a number of things that we're doing sharp to make up for the... loss earnings of the unit aid outage.
spk09: Okay, perfect. That helps there. And then just lastly, and then 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 CNI book. Thanks.
spk05: Sure. I'll turn it over to Elizabeth for, you know, kind of this East Texas split, but I will tell you that the I mean, the retail engine is really, really strong. And as I said, you know, 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 details?
spk10: Yes. Thanks for the question, Char. We are seeing really strong retention. Maurice, you 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, the strength of our platform right now, especially with the volatility in the COGS, I mean, I'm so pleased with how resilient our platform is through this. And frankly, the strength of our channels, both sales and marketing channels, to pivot within regions and between regions. So, yeah, it really is a strong platform.
spk09: Perfect. That's super helpful. Very good color this morning, guys. Thanks.
spk07: Thank you, sir.
spk11: Our next question comes from Michael Lapidus of Goldman Sachs.
spk01: Hey, guys, thank you for taking my question, and congrats for being able to keep the guidance range during a tough operational time given the parish outage. Good morning, guys. The history of Texas shows that there are power price and heat rate blowouts that happen 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 – heat rate blowout that happened 12, 14 years ago or so. Just curious, with Parrish, one of your baseload units out through the second quarter next year, can you just talk about how much gas fired 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 Sundays ago in Texas. So just trying to think about how much backup you've got from third-party fossils for the period when Parrish is out.
spk05: 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 low 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 economic generation. You know, there is a – it's just a lot of combination in that third-party megawatts. You know, we have some folding 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. As you mentioned, 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, you know, I mean, that's going to be the prudent thing to do, given, you know, 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, you're 7% and 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.
spk01: Well, and Texas is showing massive, robust demand growth, way above the national average. Part of that is just residential new connects, people moving there. Part of that is massive pet chem industrial demand. Part of it is probably crypto mining, which there are all kinds of dockets that are caught in the PUCT discussing the impact of that. If we enter a sustained period where Texas 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 multi-year period way above what we saw in the last three to five years?
spk05: Yeah, well, 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, it is, you know, one, you know, 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, you know, as I mentioned, we already have, you know, at least one project that has been 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, you know, and I'll tell you, the team is already looking at other opportunities where we can bring, you know, storage there. So I think you're going to see us participate on that, you know, new dispatchable quick start, you know, generation opportunity in our sites, but not necessarily with our capital. And we will be the off-takers. 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 zero variable cost in the form of wind, solar, and perhaps storage, and bring contract also with new gas-peaking dispatchable generation in our existing size, but not necessarily with our capital.
spk01: Got it. And one last one, and this is probably an 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 21? 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?
spk10: So from a customer count perspective, year over year since the DE acquisition, 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 a customer usage perspective, in the ERCOT market, relatively steady, although with weather, we're seeing an increase, especially in this second quarter. versus prior periods. So we do expect customer usage to be either steady or growing with the electrification of people's lives and communities.
spk05: 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.
spk01: Got it. Thank you, guys. Much appreciated, Mauricio.
spk07: Thank you, Michael.
spk11: The next question comes from Angie Storzynski of Seaport.
spk03: 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 from nuclear PTCs. I'm just struggling to gauge what is the price that STP is hedged at, say, for the next year or two, you know, as we're trying to calculate a delta between that and the $44 per megawatt hour that this bill would bring.
spk05: Yes, good morning, Angie. Well, I mean, so clearly this bill could potentially be a positive for, you know, nuclear owners, including us, and As you mentioned, I mean, I think, you know, everybody's looking at, okay, what is that, you know, 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, you know, 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 you know we'll start to you know I guess outline as these bill progresses and if passed then you know we will need to have that you know that that level of clarity to ensure that we can you know support and justify the incremental PTC but that's something you know that you know to be worked on okay
spk03: And then going back to the hedging of your retail book, so one thing that sort of surprised me is that, I mean, when you hedge your retail book, you always have all kinds of delta hedges and options in order to protect you against, you know, unplanned outages, also spikes in usage. So I would have thought that, you know, Parish, you know, was not a big component of the supply stack to start with given the coal supply constraints, and then you should have had those additional hedges. So I'm actually 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 in bad debt expense, and we see it at regulated utilities. So we're just wondering how you manage that.
spk05: 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, you know, cold unit, close to 600 megawatts, with prices where they were in the forward market for starting in May. That unit is pretty deep in the money. So as you mentioned, I mean, the cold conservation that we had was really in the shoulder months and perhaps in some of these shoulder 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. you know we use some of our own economic generation and it was very effective but these are economic generation that we have some of the gas pickers they come at a really high cost given where the natural gas price is today so you know if you're at eight nine dollar gas you know and you're deploying 12 you know 13 seed rate you know you know pickers you know the cost of that is pretty high, although it caps us from, you know, buying at the cap, for example, but it's still pretty high compared to where, you know, the cost of generation is for our coal plant. Anything else, Alberto?
spk04: Yeah, Andrew, regarding your question regarding related to bed debt expenses, we are not seeing any pickup in the bed debt expenses, and consider 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, you know, at the late payment trees 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.
spk11: Great. Thank you.
spk07: Thank you, Andrea. Thank you.
spk11: Our next question comes from Steve Fleischman of Wolf Research.
spk06: Yeah. Hi. Good morning, everyone. Good morning, Steve. Hi, Mauricio. You mentioned increasing the maintenance capex on the fleet from the $200 million. How much higher might that go?
spk05: well I mean we're about you yes Steve I mean we're we're gonna evaluate these but obviously you know if your plants are a lot more profitable than they were let's say the last you know five six years on their a low gas environment you know they can support incremental you know maintenance topics 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 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 a step-up change from the maintenance complex, but it is, you know, 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, you know, every megawatt counts, and I want to make sure that we have it available when we need it.
spk06: 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'll be next year?
spk04: 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 capital that we're going to deploy. this year. So that's the area where we see more opportunities.
spk06: 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. Yeah. 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, you know, there's a lot of provisions in this bill and different ways it could impact the business. So just, could you just talk to anything else that particularly you're particularly focused on?
spk05: Sure. I mean, the two big ones is, you know, what is the impact on wind and solar, renewable energy, and, you know, what's the impact on nuclear, right? So on wind and solar, you know, we can see a reengagement and an acceleration of renewable development, which, you know, 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 STP facility. And like every other nuclear generator in the country, I'm sure that they're starting to do the math to figure it 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.
spk06: Okay, thank you.
spk07: Thank you, Steve.
spk11: Ladies and gentlemen, thank you for your participation in today's conference.
spk02: This concludes today's program. I will now turn the call back over to Mauricio.
spk05: Thank you, Felicia, and I look forward to speaking with you shortly. Thank you.
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