Good day and thank you for standing by. Welcome to the NRG Energy, Inc. Q2 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 one one 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.
Thank you, Felicia. Good morning and welcome to NRG Energy's Q2 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. With that, I'll now turn the call over to Mauricio Gutierrez, NRG's President and CEO.
Thank you, Kevin. Good morning, everyone, and thank you for your interest in NRG. I'm joined this morning by Alberto Fornaro, Chief Financial Officer. Also, on the call and available for questions, we have Elizabeth Killinger, Head of Home, Rob Gaudet, Head of Business and Market Operations, and Chris Moser, Head of Competitive Markets and Policy. I'd like to start with the 3 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. Finally, our share repurchase program continues with approximately $600 million in remaining capacity to be executed this year.
Moving to the Q2 financial and operational results on slide five. We delivered $358 million of adjusted EBITDA for the Q2 . 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-MW coal unit at the W.A. Parish facility. This outage began on May ninth 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 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-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, 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 continue 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
Parish Unit Eight 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. Although Alberto will provide details on this 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 hedge 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 Eight impacted performance. While there is an earnings recognition delay, 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 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 wanna 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, Airtron 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, 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's 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. 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 Q2 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 impacts of the 4.8 gigawatt fossil asset sales completed in December, PJM asset retirement in the Q2 , New York capacity revenue, and early settlement of demand response revenue in the Q2 of 2021. In addition, not included in our expectation were the extended unplanned outage at Parish Unit Eight and the modest amount of growth expenses. From a regional perspective, adjusted EBITDA in Texas declined $61 million compared to the Q2 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 bill volume. On May ninth, a fire at the Parish facility caused an extended outage at Unit Eight and a 10-day outage at Unit Seven. We were therefore forced to replace the power with a combination of our more expensive out-of-the-money generation hedges and some opportunistic market purchase, which together impacted EBITDA by an estimated $70 million. In addition, the benefit normally associated with higher bill volumes with our home and business customers, of such 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 non-recurring items of $79 million, which include an earlier than anticipated partial insurance reimbursement of the business interruption expenses at Limestone Unit One and the early settlement of an online PPA. Turning to the East, West and Other segment, 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 Q2 of 2021. Next, compared to Texas, where the impact of coal constraints was minimal, generation in the East continued 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 H2 of this year as the associated retained hedges 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 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 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 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 Q2 impact reflects the deductible period. As of today, we are 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 own costs and operating expenses, including early realization of synergies and one-time reduction of expenses. 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 Free Cash Flow Before Growth guidance remains unchanged at $1.29 billion.
Next, we received $689 million of securitization proceeds from ERCOT related to Winter Storm Uri in late June, which net of the bill credits issued to C&I customer 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 recoveries. 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 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 projects 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. 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. At this time, we will conduct the question-and-answer session. As a reminder, to ask a question, you will need to press star one one 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 Julien Dumoulin-Smith of Bank of America. Please go on.
Hey, good morning, team. Thanks for the time. How you guys doing?
Good morning, Julien. Good morning.
Yeah. Hey. Excellent. Mauricio, I'd love to hear. I want 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? Actually, are you even more convinced in this strategy, and could we see you engaging in more contracting? 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 strong. You know, customers are in this environment. I describe them as a flight to safety and, you know, obviously, Elizabeth can talk a little bit more about that. But when I think about the supply strategy, you know, you really, you know, need to think about, okay, what is the retail load 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. That was the big lesson learned from Winter Storm Uri.
We don't want to have a single point of failure. 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 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 ten-year period of very low gas prices. Our maintenance CapEx is sized according to that, right?
Not every megawatt matter in a 2 or 3 dollar gas price environment. Now that it's resetting itself to much higher, you know, natural gas and power prices, we're gonna right-size our maintenance, you know, CapEx to make sure that every megawatt is available because every megawatt matters at $1 per MMBtu. 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, you know, some gas peakers. And I can talk to you about, you know, the opportunities that we have within our own fleet for, you know, 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. It is a combination of things that allow us to just have a very diverse, you know, 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. On the third-party megawatts, we're exposed to counterparty risk. The attributes of those megawatts are basically the same. It is just what type of risk you wanna carry. As I think about in the future, the strategy of relying on third-party megawatts is completely consistent with how we see things, you know, in the future. We're seeing more wind, more solar. We're gonna start seeing more storage. You know, we wanna make sure that our supply is keeping up with the transition that we're seeing in the electric grid, right?
Just relying on our own generation portfolio is not keeping up with the transition that we're seeing in the market. That's why this, you know, this combined strategy of own generation and third-party megawatts, I think is the right strategy to better serve our load.
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? Could that result in new gas peakers in, for instance, ERCOT here? Just to make sure I'm hearing this right.
Correct. 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, you know, 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, you know, 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. Now we have expanded that to gas peaking. 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 sites.
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. Right now we wanna, you know, explore potential partnerships where we can bring, you know, capital from other entities. We can take the offtake, and we can be also the developer since we have a long history of, you know, power plant development. I think it can be a win-win for everybody. We don't need to use our own capital to develop these plants and still benefit from these incremental megawatts in the grid.
Right. 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.
All right. Excellent. All right. Well, I've 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 Shar Pourreza of Guggenheim Partners.
Hey, guys. Good morning.
Good morning, Shar.
Mauricio, 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?
Yes. I mean, there will be a combination of things, Shar. 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. 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 upsizing that and working on it. You know, obviously, you know, 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 gonna work hard to accelerate that. I would say that, you know, some of them are some of our leverage. I also wanna mention the
that we run this business for cash. You know, I think the sale of Watson is an example of us being completely focused in monetizing the value of our portfolio. If we can accelerate some of the divestitures of non-core assets, we're gonna continue to do that to bring cash, you know, in this year to make up for, you know, the cost of the Unit A insurance outage. There is a number of things that we're doing, Shar, to make up for the lost earnings of the Unit 8 outage.
Got it. Perfect. That helps there. Just lastly, I know you guys mentioned retention is exceeding your internal targets. Is this split fairly evenly between East Texas or is it skewed? Just curious how East has held up with a heavier C&I book. Thanks.
Sure. I'll turn it over to Elizabeth for, you know, kind of this East Texas split. I will tell you that I mean, the retail engine is really, really strong. As I said, you know, in the previous answer, we're seeing a flight to safety, and our brands are that flight to safety. We're seeing really, really strong numbers. Elizabeth, can you provide additional detail?
Yes. Thanks for the question, Shar . We are seeing really strong retention. Mauricio Gutierrez 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. 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. Frankly, the strength of our channels, both sales and marketing channels, to pivot within regions and between regions.
Yeah, it really is a strong platform.
Perfect. That's super helpful. Very good color this morning, guys. Thanks.
Thank you, Shar.
Our next question comes fro m Michael Lapides of Goldman Sachs.
Hey, guys. Thank you for taking my question. Congrats for being able to keep the guidance range during a tough operational time given the Parish outage. Just curious.
Thank you, Michael. Good morning.
Good morning, guys. The history of Texas, you know, 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 Parish, one of your base load units out through the Q2 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. Just trying to think about how much backup you've got from third-party fossil for the period when Parish is out.
Yes, Michael. I think in the last earnings, you know, an indication of our hedge for 2023. If you recall, that one had, you know, against the expected low that we have for 2023, half comes from third-party megawatts, about half comes from our economic generation. We have an economic generation that is maintained as insurance, our own economic generation. You know, it's just a lot of combination in that third-party megawatts. You know, 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.
There is a combination of tools that we have to be able to manage weather variability, you know, in any given year. Now, as you mentioned, I mean, the Q2 was pretty extreme. We always plan for some weather variability, but what we actually saw in the spring and July is, you know, record-breaking heat in Texas. While we, you know, manage for some variability, it is incredibly expensive to manage for all weather variability now.
Now, you know, perhaps one of the lessons learned here is as we think about 2023, and given that we have, you know, a lot of time to plan for how to set up the portfolio for that year, you know, I expect that we're going to buy a little bit more insurance for extreme weather than, you know, than in the past. 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 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, it's 7 to 8% increase.
I mean, that's pretty significant, and I think we need to recognize that. Perhaps we're gonna see greater, you know, weather, extreme weather events, and we need to plan for it.
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 petrochemical industrial demand. Part of it is probably crypto mining, which there are all kinds of dockets that are going on at 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 multiyear period, way above what we saw in the last 3 to 5 years.
Yeah. Well, 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, you know, that's really, really good, and that's what we wanna see. Now, obviously, we need to make sure that we keep up our supply strategy with that incremental demand. The way we're gonna do 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.
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 to the table. We have another one that is right behind it and is in the process of getting permitted. I'm sure that, you know. 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 gonna see us participate in 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 offtaker.
In addition to that, we're gonna continue bringing new wind and solar and energy storage as we, you know, have done already, with our current PPA. So we're looking at these in kind of these two ways, you know, bring new megawatts that are, you know, zero variable cost in the form of wind, solar, and perhaps storage, and bring, you know, contract also with new gas peaking dispatchable generation in our existing sites, but not necessarily with our capital.
Got it. One last one, and this 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 2021? Like, how much is your mass market customer count up since the Direct deal? Meaning if I did it apples to apples. 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 DE acquisition, relatively steady, a slight decline. As I have mentioned before on calls, when we do both bolt-on acquisitions and large acquisitions, there's a bit of a settling period in the first year or two. 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, that especially in this Q2 versus prior periods. We do expect customer usage to be either steady or growing with the electrification of people's, you know, lives and communities.
Right. I mean, Michael, you need to think about that usage in two contexts, weather normalized and then weather affected. I think what you saw in Q2 is a significant increase in usage per customer because of weather. We're also seeing an increase in, you know, usage per customer because of the electrification of the economy, right? You know, you can point to electric vehicles. You can point to a lot of different, you know, 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. 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 at, you know, what is the price that STP has had, 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.
Yes. Good morning, Angie. Well, I mean, so clearly this bill could potentially be a positive for, you know, nuclear owners, including us. 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? That's a moving target, and obviously that's a moving target with, you know, with the market, right? Like everybody else. I'm not sure if I can give you that level of specificity in terms of at what price you hedge, because we look at it on a portfolio basis. I mean, this is something that, you know, we'll start to, you know, I guess, outline as this bill progresses.
If passed, you know, we will need to have that, you know, 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. Going back to the hedging of your retail book. 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. I would have thought that you know, Parish was not a big component of the supply stack to start with, given coal supply constraints. You should have had those additional hedges. I'm actually you know, a little bit surprised that the impact is this big.
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.
Yes, Angie. 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, coal unit, close to 600 megawatts with prices where they are, they were in the forward market for starting in May. That unit is pretty deep in the money. As you mentioned, I mean the coal conservation that we had was really in the shoulder months and perhaps in, you know, in some of these shoulder hours. In the peak hours, this unit was expected to be there, you know, 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. You know, that really goes outside of, you know, kind of this planning area that we look at. This was the combination of these two very extreme, you know, conditions. It's not like we don't plan for it, but we don't plan, you know, the intersection of both of them exactly, you know, as we're leading into the summer. Now, you know, we use some of our uneconomic generation, and it was very effective. 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.
You know, if you're at $8 to 9 gas, you know, and you're deploying 12-13 heat rate, you know, peakers, you know, the cost of that is pretty high, although it caps us from, you know, buying at the cap, for example. It's still pretty high compared to where, you know, the cost of generation is for our coal plant. Anything else, Alberto?
Yeah, Angie, so regarding your question regarding the related to bad debt expenses, we are not seeing any pickup in the bad debt expenses. Consider now the level of receivables is much higher, given the level of gas prices and power. When we're seeing percentages absolutely in line, and even we look at the late payment fees and so on, and it's pretty normal, particularly in Texas. 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.
Hi, Mauricio. You mentioned increasing the maintenance CapEx on the fleet from the $200 million. How much higher might that go going forward?
Well, I mean, yes, Steve, I mean, we're gonna evaluate this, but obviously, you know, if your plants are a lot more profitable than they were, let's say the last, you know, 5, 6 years under a low gas environment, you know, they can support incremental, you know, maintenance CapEx. 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 needed to have, you know, that, maximize the output of the plant. Now, we really need to maximize the output of the plant. Look, the capacity factors, the amount of time that these plants are gonna run are going to be more than they have been in the past, and we need to take that into consideration.
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, you know, we need to rightsize it to the amount, of run hours that the unit is gonna have, number one. Number two, for the profitability of the plant, right? You know, every megawatt counts, and I wanna make sure that we have it available when we need them.
Okay, great. On the Parish outage and the insurance. I assume you're not assuming you're gonna book any business interruption proceeds this year? It'll be next year.
Yeah. Alberto?
Is that correct?
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. That's the area where we see more opportunities.
Okay. Just high level, you have the $200 million plus costs this year. Next year there will be some cost that continues in the H1 , 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. Just high level, I know somebody asked about the impact of IRA for the nuclear plant, but maybe more broadly, could you know, there's a lot of provisions in this bill and different ways it could impact the business. Could you just talk to anything else that particularly you're focused on?
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? On wind and solar, you know, we can see a re-engagement 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. Then on the nuclear side, you know, we're gonna be looking at, you know, what is the benefit that we can have with our STP facility and, you know, like every other nuclear generator in the country, I'm sure that they're starting to do the math to figure it out, you know, how do we benefit from these production tax credits.
I would say those are the two big areas where, you know, 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 Gutierrez.
Thank you, Felicia, and thank you. With you shortly. Thank you. I look forward to speaking with you shortly. Thank you.