Good day. Welcome to the PPL Corporation Q1 2023 earnings conference call. All participants will be in a listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touch-tone phone. To withdraw your question, please press star then two. Please note this event is being recorded. I would now like to turn the conference over to Mr. Andy Ludwig, Vice President in Investor Relations. Please go ahead, sir. Good morning, everyone, and thank you for joining the PPL Corporation conference call on Q1 2023 financial results. We have provided slides for this presentation on the investor section of our website. We'll begin today's call with updates from Vince Sorgi, PPL President and CEO, and Joe Bergstein, Chief Financial Officer, and conclude with a Q&A session following our prepared remarks. Before we get started, I'll draw your attention to slide two and a brief cautionary statement. Our presentation today contains forward-looking statements about future operating results or other future events. Actual results may differ materially from these forward-looking statements. Please refer to the appendix of this presentation and PPL's SEC filings for a discussion of some of the factors that could cause actual results to differ from the forward-looking statements. We will also refer to non-GAAP measures, including earnings from ongoing operations and adjusted gross margins on this call. For reconciliations to the comparable GAAP measures, please refer to the appendix. I'll now turn the call over to Vince. Thank you, Andy, and good morning, everyone. Welcome to our Q1 investor update. Let's start with our financial results and a few highlights from the quarter on slide 4. Today, we announced Q1 reported earnings of $0.39 per share. Adjusting for special items, Q1 earnings from ongoing operations were $0.48 per share, compared with $0.41 per share a year ago. This increase was supported by solid results from our newly acquired Rhode Island business, as well as lower O&M expenses, partially offset by lower sales volumes due to the mild winter weather and higher interest expense. We remain confident in our ability to deliver on our 2023 ongoing earnings forecast of $1.50-$1.65 per share, with a midpoint of $1.58 per share. Joe will speak to this more in his detailed review of our financial results. In addition to solid financial performance, we continue to execute on our commitment to provide safe and reliable electric and gas service to our more than $3.5 million customers. This includes managing several significant storms at our utilities, including a severe March windstorm in Kentucky, the third most significant weather event in the last 20 years in our service territory. Our teams, with the help of mutual assistance from several of our peers, restored power to more than 400,000 LG&E and KU customers. I thank each one of our men and women, as well as all those that provided mutual assistance for their dedication, commitment to safety, and demonstrated operational excellence. From a financial perspective, we received approval to treat nearly $20 million of Q1 O&M costs related to this extraordinary event as a regulatory asset. These types of events emphasize the importance of the investments we are making across our company to harden and improve the resiliency of our network. As the frequency of these events continues to increase, it becomes even more critical to ensure we are taking proactive steps to prepare our distribution and transmission networks. We look forward to delivering on that goal in the most affordable way possible for our customers. We've also made significant progress during the Q1 in several areas that will improve our operating efficiency, deliver our clean energy strategy, and improve service to our customers. First, we continue to execute our plan in transitioning Rhode Island Energy to PPL Systems and remain on track to exit the remaining transition services with National Grid in 2024. We also advanced several key regulatory proceedings, which I'll discuss further on the next couple of slides. We successfully executed more than $3 billion of financings in the Q1, reducing our interest rate exposure and strengthening our ability to achieve our top-tier earnings growth targets. Our execution of approximately $600 million in capital investments during the Q1 keeps us on track to invest nearly $2.5 billion in infrastructure investments this year. These investments benefit both customers and shareowners as we continue to advance our strategy to create the utilities of the future. Today we are reaffirming our plans to invest nearly $12 billion in infrastructure improvements through 2026 to modernize our electric and gas networks and replace retiring generation in Kentucky. Looking forward, we remain confident in the low-risk business plan we outlined in January and reaffirmed our projected compound annual earnings per share and dividend growth rates of 6% to 8% through at least 2026. Turning to slide 5, we were pleased to secure a positive outcome in our first infrastructure, safety, and reliability proceeding before the Rhode Island Public Utilities Commission. ISR plans are submitted annually in Rhode Island and outline proposed capital investments and related operating costs to strengthen safety, reliability, and resiliency of our electric and gas distribution networks. The approved plans address Rhode Island Energy's proposed spending from April 1, 2023 to March 31, 2024. In its decision, the Public Utilities Commission approved $290 million of the approximately $350 million Rhode Island Energy proposed in its ISR filing. Disallowed investments on the electric side were largely tied to grid modernization and associated improvements. On the gas side, most of the disallowed investment related to roughly 10 miles of leak-prone pipe replacement. While we believe the disallowed investments are the right projects to better serve our customers, we understand the commission's desire to complete reviews of our grid modernization and advanced meter filings and to make further progress in the future of gas stakeholder proceedings before approving additional spending in those areas. The investments not approved in this year's ISR plans may be recoverable in future proceedings subject to regulatory approval. This could be through future ISR filings, new base rate cases, and/or reopener provisions within the base rate cases that we are currently operating under, particularly related to the grid modernization and AMF projects. Ultimately, we look forward to continued engagement on these matters with the Commission, the Division of Public Utilities and Carriers, and other stakeholders in Rhode Island. Turning to slide 6. We continue to progress our generation investment plan in Kentucky and remain confident that this plan is the best path forward for our customers as we plan for the state's energy future. Our plan is more affordable, maintains reliability, and represents significantly cleaner energy resources for our customers than continuing to operate the coal units that we have proposed to retire by 2028. In fact, we estimate that our plan provides nearly $600 million of net present value benefits for our customers compared to continuing to operate these coal units. As we shared in March when Senate Bill four became law, we're confident that the generation replacement plan we filed in December exceeds the standards set by the new law. As a result, we have not changed our CPCN strategy. As proposed, our plan would replace 1,500 megawatts of aging coal generation with over 1,200 megawatts of new combined cycle natural gas generation, nearly 1,000 megawatts of solar generation, and 125 megawatts of battery storage. In addition, our plan proposes the implementation of more than a dozen new energy efficiency programs by 2028. The plan represents a $2.1 billion investment in Kentucky's energy future and the least cost option to reliably meet the needs of our Kentucky customers 24 hours a day, 365 days a year. As an added benefit, our proposed plan would cut our carbon emissions nearly 25% from current levels while further diversifying our generation fleet. To comply with the new law, we expect to file our retirement request with the KPSC by May 10th. Given the law provides the KPSC 180 days to issue a decision on retirement requests, this timing essentially aligns the retirement ruling with the expected decision on our CPCN filing. A decision on our filings is expected by November 6th. Again, we're confident the plan we proposed offers the best path forward for the customers and communities we serve. We don't see any signs of federal environmental mandates easing over time. We believe investing hundreds of millions of dollars in environmental controls, continue operating aging uneconomic coal plants is not in our customers' best interest. However, should we be required to make such investments, we do have the environmental cost recovery mechanism, or ECR, in place that would enable recovery of these investments outside of base rate cases. We'll continue to actively engage with stakeholders in Kentucky throughout the CPCN process to demonstrate how our plans best meet the needs of our customers. That concludes my strategic and operational update. I'll now turn the call over to Joseph f or the financial update. Thank you, Vince, and good morning, everyone. Let's turn to slide 8. PPL's Q1 GAAP earnings were $0.39 per share. We recorded special items of $0.09 per share in the Q1, primarily due to integration and related expenses associated with the acquisition of Rhode Island Energy. Adjusting for these special items, Q1 earnings from ongoing operations were $0.48 per share, an improvement of $0.07 per share compared to Q1 2022. The addition of Rhode Island Energy to our portfolio and our focus on O&M savings were the primary drivers of the increase, partially offset by lower sales volumes of about $0.05 per share due to the unusually mild winter weather in Kentucky and Pennsylvania and higher interest expense. Overall, our teams performed very well in the face of significant storms, and results for the quarter were in line with expectations apart from the weather. Heating degree days were down nearly 25% in our Kentucky service territory and 30% in our Pennsylvania territory. This resulted in lower quarterly sales volumes of nearly 9% in Kentucky and 7% in Pennsylvania. We remain confident in delivering our 2023 earnings forecast as we have several potential offsets to the mild weather, including the benefit of our recent financings at attractive rates compared to our plan, incremental DSIC revenues in Pennsylvania, outperformance on our integration of Rhode Island Energy, and effective O&M cost management. While we're not relying on weather, a warmer than normal summer could also provide some potential upside. We have an excellent track record of achieving our targets, which we expect to continue in 2023. Turning to the ongoing segment drivers for the quarter on slide nine. Our Pennsylvania regulated segment results were flat year-over-year. Results were primarily driven by increased transmission revenue and distribution rider recovery, offset by lower sales volumes due to the mild weather and higher interest expense due to increased borrowings and higher rates. Our Kentucky segment decreased by $0.04 per share year-over-year. Results were impacted primarily by lower sales volumes due to the mild weather and higher interest expense from increased borrowings, partially offset by lower O&M expenses. The addition of our Rhode Island segment increased earnings by $0.10 per share for the quarter. Rhode Island's Q1 results reflect the seasonal nature of gas operations during the winter months, as a significant amount of annual natural gas demand and earnings occur within the heating season. Results at corporate and other increased $0.01 per share compared to the prior year, primarily due to lower O&M expenses and other factors that were not individually significant, partially offset by higher interest expense due to increased debt and higher rates. Moving to slide 10. During the quarter, we successfully navigated a volatile rate market and completed our financing plan for 2023. This included 5 separate transactions, issuing a combined total of $3.2 billion of debt, including a billion-dollar convertible offering that was the first executed in our industry in 20 years. Our first mover advantage on the convert led to strong demand from investors as our deal ended up pricing about 250 basis points lower than straight debt, resulting in roughly $25 million in annual interest expense savings. Given these savings, this transaction is favorable to issuing straight debt and any potential share dilution as a result of significant share price appreciation will be manageable. We also executed several operating company issuances in Pennsylvania and Kentucky for combined proceeds of nearly $2.2 billion. A portion of the proceeds were used to reduce both short-term and floating rate debt, while the remaining will be used primarily to fund each utility's respective CapEx plans. In total, we repaid $1.75 billion of floating rate debt, reducing our floating rate exposure to approximately $600 million, which is less than 5% of our total debt portfolio. In summary, our strong execution of the financing plan this quarter reflects PPL's excellent credit position. We continue to target strong credit metrics and maintain one of the sector's best credit profiles without any planned equity issuances through our planning horizon. That concludes my prepared remarks. I'll turn the call back over to Vince. Thank you, Joseph. In closing, we remain solidly on track to deliver the midpoint of our 2023 earnings forecast, and we remain well positioned to deliver top-tier earnings and dividend growth of 6%-8% annually through at least 2026. We're off to a strong start in 2023, executing on our $2.4 billion capital plan, continuing the integration of Rhode Island Energy, advancing our plans in Kentucky and Rhode Island to deliver least cost reliable energy for our customers, and remaining on track with our first leg of achieving at least $175 million in O&M savings by 2026. As we pursue our strategy to create the utilities of the future, we are as strong as we've been in years, and I'm convinced we're only getting stronger. With that, operator, let's open it up for questions. We will now begin the question-and-answer session. To ask a question, you may press star then one on your touch tone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. At this time, we'll pause momentarily to assemble our roster. The first question will come from Durgesh Chopra with Evercore ISI. Please go ahead. Hey, team. Good morning. Thanks for giving me time. Good morning, Durgesh. Good morning. A lot of investor discussion, Vince, around just the legislation in Kentucky. Can you just share some initial feedback, if you have any, from your filings? You know, a lot of investors are looking at this legislation, you know, thinking about, you know, what the, you know, what it may mean for you and whether the state is actually, you know, going to accept your application to retire these coal plants. Just any additional color that you can share that would be appreciated. Sure. Look, in general, you know, these are open proceedings. You know, we're going through the formal processes with the commission. Not a lot to share directly in terms of feedback from the commission. As we think strategically, Durgesh, you know, the CPCN that we filed with the commission is, again, you know, our view as a least cost option to serve our customers. Again, as I mentioned in my remarks, we quantify the NPV savings to our customers at about $600 million versus continuing to operate the coal plants that we're proposing to retire. Our plan also ensures reliability. It checks all of the issues that SB 4 has in it in terms of cost and reliability, et cetera. We think we meet the requirements that have come out in the new law. From our perspective, we still feel very confident that we can get our plans approved through the commission. Engaging with our customers, and the various intervenors and stakeholders in the process. Overall, nothing changing from our perspective in terms of the CPCN strategy. Got it. That's, that's helpful, Vince. Is there a middle road here perhaps, and I know this is early innings, but like, you know, not your plan in entirety, but a portion of your plan might get accepted and you have alternatives for, you know, the balance of the plan. I'm just, I'm just thinking about, you know, the risks 'cause it's a significant portion of your, of your CapEx, which is included in your plan as you go into the CPCN filings and whether there's a, there's a sort of a collaborative approach here to get some of it, if not all of it, approved. Yeah. Look, I think that's a fair question, Durgesh. We'll, we'll ultimately have to see when we go through the process with our intervenors, if there's a settlement scenario or case that we ultimately can agree to your point. Of course, you know, we're always open to those types of discussions. I think it's important to comment that if we do need to continue to operate the aging uneconomic coal plants that we're proposing to retire, that would require us to invest potentially significant amounts of capital to comply with existing EPA regulations, which again, we don't think would be in the best interest of our customers. If we're required to do that, we would have to make those capital investments. If you look at all of the plants that we're talking about, retiring, you know, again, we'd have to evaluate the final EPA regs, you know, once they come out in final form, and then analyze all that. Sitting here today, that could be between, you know, half a billion and $1.5 billion of environmental investments alone, not to mention the maintenance capital that we would have to incur to keep those plants operating. So quite a significant amount potentially of investment that would be required there. As I discussed again in my remarks, that would be recovered through the ECR mechanism, which basically provides real-time recovery for our share owners, should we need to make those investments. We have other... If we're not gonna spend $2.1 billion on gen replacement, I think from an affordability perspective, we have other investments we can make in Kentucky, primarily in the T&D businesses. We're seeing increased severity and frequency of storms in the state. We saw that just this quarter. Continuing to strengthen the grid in Kentucky, we certainly have the opportunity to do that as well. From a capital plan perspective, we really don't have a lot of the IIJA project funding in our plan. Specific to Kentucky, we have about $300 million worth of projects that we've submitted with the DOE. $150 million would be funded by us, and $150 million would be funded by the DOE. At the end of the day, we're feeling really good about the overall capital plan, Durgesh, and obviously feeding the earnings targets that we've laid out. That's great color, Vince. Thank you so much. Sure. The next question will come from David Arcaro with Morgan Stanley. Please go ahead. Hey, Dave. Thanks so much for taking my question. Hey, let's see. Wondering if you could just maybe give an update on your confidence level in achieving your previously planned cost cuts for this year, what you're seeing for inflationary pressures, and I guess how hard of a stretch is it to dig deeper and also offset the weather headwinds that you're facing? Yeah, sure. I'll ask Joe maybe to comment on that. Yeah, sure. Hey, Dave. Well, first of all, for the O&M targets that we've set for this year, we are on track to achieve those, and we feel really good about our ability to do so. As far as offsets for this year and the weather impact that we saw in the Q1, I hit on a number of them during my prepared remarks, but those include the benefits from the strong execution of the convert that we issued earlier this year, and that's about $0.01-$0.02 better than our expectations. We're also anticipating the DSIC mechanism in Pennsylvania provides additional earnings. Which could be about another $0.01-$0.02 there. Any potential outperformance on the integration of Rhode Island Energy and, you know, we're very focused on that integration process there and always trying to do better than our plan. That could be another $0.01, maybe $0.02. If you're looking beyond that, we always have the ability to flex our O&M spending, which we could do on top of that. A number of levers we have at our disposal, David. Great. You anticipated my other question, which was to get a little more clarity on those other levels. That's really helpful. I was wondering if you could touch on Rhode Island and just following the ISR decision. Maybe one, do you think there's still interest in pursuing those projects by the commission that didn't get approval? Just wondering more, maybe more holistically, are there other opportunities that you would look for additional CapEx upside in Rhode Island more broadly? Yeah, sure. First of all, I'd say I think the process in Rhode Island was very constructive. As I talked about in my prepared remarks, you know, the projects that did not get approved were really associated with other proceedings that are currently in front of the Commission, in particular, the Grid Modernization on the electric side and the lead chrome pipe on the gas side. Because we have other proceedings in front of the Commission on those areas, it wasn't a total surprise to me that they decided to, you know, temper some of the increase in those areas pending getting a little further down the road on those proceedings. We will have the opportunity, to your question, to request those projects in future proceedings. Again, though, those could be future ISR proceedings. They could be future base rate cases, depending on the timing of when we file our next base rate case. We also have reopener provisions in the current rate case for both Grid Mod and the AMF filing. We could also, potentially, you know, use that avenue as well. I think it's important to point out that the $290 million, almost $300 million of investments that we did get approval for, right? Those are vital in strengthening the safety, reliability, and resiliency of our networks. I think it highlights the importance of the ISR mechanism for our customers, but it also demonstrates the constructive regulatory framework for our investors. In terms of additional capital opportunities, I think probably the biggest one would be again in the IIJA buckets. You know, we have about $480 million worth of projects that we've applied for with the DOE. $330 million of that would be PPL funded. $150 million of that would be DOE funded. Obviously, that helps the economics on those projects. We could again funnel those through the ISR or other mechanisms to get approval. We would need regulatory approval for those projects. Again, with the DOE kicking in, you know, about 30% funding on those, it really helps the cost-benefit analysis on those projects. Hopefully we would get a lot of support in the state to do those types of projects. Okay, excellent. I appreciate it. Thanks so much. Sure. The next question will come from Paul Zimbardo with Bank of America. Please go ahead. Hey, Paul. Hi. Good morning. Thank you, team. Thank you for the color on Kentucky in particular. Just if I add up the pieces that you mentioned, is it fair to say that in a worst case scenario, you could offset the majority of that $2.1 generation plan with other spending if you needed to? Yeah, Paul. You know, we're very confident in being able to meet our earnings targets and trajectory. I think how we get there, under different scenarios of a CPCN approval process, we'd have to look at that depending on what exactly gets approved. Like I was saying, if some of that capital ends up being environmental spend on coal plants where we earn, you know, cash recovery on that spend pretty much as we're spending it, where, as we know, our base plan is assuming under the $2.1 billion we'll be spending under the CPCN $1.6 billion in our time period, that requires a base rate case for cash funding. We would get some potential, you know, upside on the earnings profile by recovering quicker. Again, we have to see how much the impact on the overall capital plan is, if any, coming out of the CPCN. really, we feel confident in our ability to hit our targets under various scenarios coming out of the CPCN filing. So it's a little tough to just say, you know, this capital bucket for that capital bucket because you also have the positive effect of the ECR mechanism in there. Okay. No, I thank you. That's good context as well. I appreciate it. Switching topics. Joe mentioned that the outperformance of the Rhode Island integration could be a penny or two favorable for 2023. Should we think of that as more of a timing element? Or if you're successful there, would that accrue to 2024 plus? Thank you. Yeah. Joe, do you wanna. Yeah, no, I think it's more on just our overall performance against our expectations there and being able to integrate at a lower cost than we expect. The TSA period goes through 2024. You know, my comments were really focused on 2023 and our ability to offset the negative weather start to the year. Okay, great. Thanks a lot. Sure. The next question will come from Angie Storozynski with Seaport. Please go ahead. Thank you. First, maybe something completely different. We're probably halfway through the earnings season, we haven't yet heard from any utility about some additional O&M efficiencies associated with lower, you know, reduced office space. Is that even something that you guys are considering? I mean, it seems like this hybrid work model has persisted even in your industry. I just wonder if that's, you know, a lever that you might pull in the future from an O&M perspective or it's not something that you're currently considering. Angie, I think that's a great question. Great point. I think generally why you haven't probably heard a lot about it is either utilities own their buildings, their office buildings that they're operating out of or they have leases that they're, you know, fixed leases that they're currently paying under. Maybe not an immediate source of, operating efficiency or O&M savings. But clearly in the post-pandemic world. As we think about, you know, hybrid or remote working versus in the office working, I think it's an area that you will see most of corporate America focusing on over the years to come. I think specifically to answer your question, we're not necessarily seeing it, right away or even in the next year or so, but certainly I think that could be an opportunity longer term as we right-size our real estate needs for sure. Okay. Just taking it one step further, are you seeing any sort of a slowdown among commercial customers, again, somehow linked to office buildings and downsizing or any other signs of economic slowdown, like any leading indicators that you see among your customers, not only on the commercial side, but also industrial? Joe, you want to talk about maybe just load in general? Yeah, sure. Hey, Angie Storozynski, it's Joe Bergstein. We are. We continue to see a number of positive economic factors in both of our jurisdictions in Pennsylvania and Kentucky, including continued low unemployment rates and strong GDP growth. In Kentucky, as we've talked about a number of times, we saw back-to-back record years of economic development with over $10 billion of announced investments in each of 2021 and 2022. That includes the Ford EV battery plant initiative that we've talked about a number of times. That's recently broken ground and well under construction. We continue to see strong industrial growth primarily in the manufacturing and agriculture sector. We have not seen that in our territories. Rhode Island Energy's decoupled and less reliant on those things. Yeah, I think just in general, you're seeing people catch up from the lull in COVID, right? Whether that was supply chains or supply chain-driven or just the lull in the economy during COVID and kind of the bow wave to not only catch up to pre-COVID levels, but then the growth. We're seeing some of our major industrials not only getting back to pre-COVID, but talking also about expansion, expanding their footprints and their production facilities. In our jurisdictions, generally, I think we're feeling really good about our local economies and where, you know, the growth that we're seeing in our areas. Mm-hmm. Just one last follow-up on Kentucky. Again, I should know that. I mean, the purpose of the bill was to basically continue the usage of the coal, you know, that is mined in Kentucky, or is it, you know, continued operations of the coal plants? I mean, it might be a subtle difference, but, you know, how about just running these coal plants on gas and thus checking that box of continued operations of these plants while, you know, sourcing energy from those new gas plants, which given the gas price environment just became even more, you know, beneficial to the end user. Well, look, I don't want to comment on the purpose of the bill. I think we'd have to probably hear that from the folks that wrote the bill. In general, I would say coming out of the Winter Storm Elliott, there was a general concern on just ensuring that reliability is kind of at the forefront of generation decisions in the state. There was concern that the clean energy transition is happening too quickly and making sure that reliability, again, is front and center. I will say that that has always been an area that we and our commission have focused incredibly on as we put together our generation planning, our CPCN filings, what the form of generation replacement looks like, et cetera. It's why we have 2 combined cycle units in our CPCN, and it's not 100% renewables. We were absolutely as focused on reliability as I think the legislature is in the state to ensure that we can deliver that power 24 hours a day, 7 days a week. I think we were already operating under the reliability issues that were addressed in the bill, in terms of, you know, driving either coal mining or running coal plants. I can't necessarily speak to that per se. I would say we will continue to put forth plans that ensure reliability but do that in the least cost manner for our customers, which the bill also has in it as well. Again, we think our CPCN plan absolutely balances all of those in the most productive way for our customers. Great. Thank you. Thank you. The next question will come from Paul Patterson with Glenrock Associates. Please go ahead. Hey, good morning, guys. Morning, Paul. With respect to the back to the Rhode Island gas modernization program, I guess what sort of comes to mind when looking at that case is, again, sort of dating myself, how do you think about the potential for stranded investment with electrification efforts in places like Rhode Island or what have you? I know it's different in different jurisdictions. I'm just sort of wondering, sort of broad picture when you're thinking about this, How does the idea of electrification or these sort of a really aggressive carbon greenhouse gas reduction efforts, how do you think about that with respect to your gas CapEx plans and what have you? Yeah, I think there's a number of factors that go into that, Paul. One is the cost of electrification. The second is the reliability of supplying electricity if the bulk of the economy is, or the vast majority of the economy becomes electrified. Ultimately, you know, the benefits of fuel diversity by having natural gas in addition to, in addition to electricity. The state has targets to be economy-wide, net zero by 2050. On the electricity side, you know, net, basically 100% renewable driven by 2033. Our investment plans on the T&D networks are geared towards that 2033 100% renewable date. We are actively engaged with, numerous stakeholders in Rhode Island, including the PUC, on the future of gas docket. We're actively engaged with doing analysis on various scenarios on how we could see the future of the Rhode Island energy sector feeding the economy there and how the natural gas system will ultimately be used or not. We would expect to have our initial view of that and issue a report to the PUC late fall of this year. In the spring of next year, the PUC would then target issuing its report to the government agency that's in charge of implementing the act on climate rules within the state. We would expect that organization, EC4, to issue their report in 2025. Great question. There's a lot of work and actually a formal docket within the commission to exactly answer that question. I think you could see various possibilities there, right? Whether or not we're blending different molecules through the, through the pipes. You know, maybe it's not all natural gas. We're using more renewable natural gas. We're using hydrogen, combination of those things. Really we're right in the middle of it right now, Paul, and more to come as I think we make progress on that analysis and ultimately those reports coming out of those various agencies. Okay, awesome. You obviously have a reliability initiative in Kentucky and what have you. Obviously things are a little bit more limited in places like Pennsylvania and Rhode Island, just given to the structure there. As you know, there's some alarm bells ringing off or have been ringing off for some time in PJM regarding reliability. We're seeing some stuff in New Hampshire with respect to long-term PPAs, potentially and what have you. I'm just wondering, is there any potential on the electric side that you guys are thinking about here, either in terms of longer term PPAs, maybe in terms of on the reliability side, batteries, virtual power plants? I don't know. You know, or just own generation or what have you, in terms of addressing these issues as opposed to maybe, the way the construct has been, which is sort of like relying on PJM, you know, the RPM model or capacity markets or what have you, that maybe it's time to sort of pivot at least a little bit and look at terms of, maybe other structures than yet another sort of, capacity market remake, if you follow what I'm saying. Yeah. I don't know. I'm just thinking about when we're just hearing a lot about right now, a Senate hearing with FERC. I'm just wondering what your thoughts are on that. I would say yes to all of that. This is an area that I spend a lot of time thinking about, and we're starting to formulate our strategy along the lines of many of the things that you just mentioned. To your point, PJM themselves, I think are very concerned about 40 to 45 gigawatts of thermal generation announced to be retired between now and 2030. That's an incredible amount of very reliable dispatchable generation that is scheduled to come out of the ISO, out of the gen stack. The vast majority, almost all of the replacement generation are intermittent renewables, and developers are having a hard time getting the siting and permitting or getting any of it built. Even if it does get built, which there's a lot of, I think, concern in terms of the timing of when this replacement generation gets built, you're replacing very reliable dispatchable energy with intermittent energy. I do think PJM is concerned as they're looking at their generation stack and thinking about the ISO itself, which of course then makes me focus on how do we ensure we have electrons flowing through our wires in Pennsylvania and Rhode Island. We are absolutely focused on this, laser-focused on this, I would say. Some of the things that you had mentioned, I would say all of those, I think, are areas that we think we can take a look at to try to shore up the gen supply in our own jurisdictions. Great question. Just a quick follow-up on that. Do you think the people in the legislature or whatever the lawmaker, whatever the officials in those states are open to those ideas as well? I would assume it might have to take changes on the part of the regimes in those states. Do you follow what I'm saying? I mean, are they open to this, do you think? Or do they recognize it, or? I think it's new. This is a new topic for them. We will be engaging with not only our legislators, but our regulators, just to make sure that we're all on the same page as we look at security of energy going forward. We have flexibility within the current rules to do a lot of what you suggested. Not all of this requires, you know, legislative change. We'll certainly use as much of the levers within current legislation and regulation to shore up, gen supply. To your point, if we need to go beyond that might require legislative change. I can't handicap today, you know, the likelihood of that happening or not. Okay, gotcha. Awesome. Thanks so much, guys. Sure. The next question will come from Ross Fowler with UBS. Please go ahead. Morning. Morning, Ross. Most of my questions have been asked and answered. Maybe let me ask this one, and apologies if I drag out the past here, but can you sort of give us the context or at least the contention in this fraudulent conveyance claim against PPL Montana that's out there with Talen? Sort of if there's any process here or timeline around actually resolving that. Sure. The case itself relates to when we still owned PPL Montana. When PPL still owned PPL Montana, we had sold the hydro assets to NorthWestern and the proceeds of those assets, $700 million about we distributed those proceeds back to PPL following the sale. That was known and negotiated when we created Talen Energy as part of spinning out energy supply and merging that with Riverstone's assets. All of that was well understood, well documented. The contention is that we somehow by doing that, we made PPL Montana insolvent. That is the fraudulent conveyance charge. We feel extremely confident in our position in defense that PPL Montana was not only in compliance with all applicable laws at the time the distributions were made, but that it was also solvent at all relevant times as it relates to the law and those distributions. Just in terms of an update on the situation with the case, we did go into mediation between the parties recently. We could not come to agreement in that mediation. We have discontinued that. We're basically back in the bankruptcy court. We would expect to resolve this with the court proceeding hopefully by the end of the year, Ross. Talen Energy has indicated, certain time frames on coming out of bankruptcy within the next couple of months. This issue will not and does not necessarily need to be resolved before they can do that, but we do expect it will be resolved by the end of the year. Yeah, that's a fantastic update, Vince. Thank you. Sure. This concludes our question and answer session. I would like to turn the conference back over to Mr. Vincent Sorgi for any closing remarks. Please go ahead, sir. Thanks again for joining us this morning. We look forward to speaking with investors at our annual shareowners meeting in a couple weeks, or perhaps we'll see you on the road here soon. Thanks again for joining us, and we'll close out. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.