Hello, and welcome to the FirstEnergy Corp third quarter 2024 earnings conference call. As a reminder, this conference is being recorded. It is now my pleasure to turn the call over to Gina Caskey, Director of Investor Relations and Corporate Responsibility. Please go ahead, Gina. Thank you. Good morning, everyone, and welcome to FirstEnergy's third quarter 2024 earnings review. Our President and Chief Executive Officer, Brian Tierney, will lead our call today, and he will be joined by Jon Taylor, our Senior Vice President and Chief Financial Officer. Our earnings release, presentation slides, and related financial information are available on our website at firstenergycorp.com. Today's discussion will include the use of non-GAAP financial measures and forward-looking statements. Factors that could cause our results to differ materially from these forward-looking statements can be found in our SEC filings. The appendix of today's presentation includes supplemental information along with the reconciliation of non-GAAP financial measures. Now, it's my pleasure to turn the call over to Brian. Thank you, Gina. Good morning, everyone. Thank you for joining us today and for your interest in FirstEnergy. Today, I will review our financial performance for the third quarter and discuss key strategic updates. I will also provide updates on recent regulatory developments, address critical issues in our industry, and review the value proposition we offer shareholders. Looking at our third quarter results, GAAP earnings from continuing operations were $0.73 per share compared to $0.74 per share in the third quarter of 2023. Operating earnings for the quarter were $0.85 per share compared to $0.88 in 2023, which included state tax benefits that did not repeat this year. Earnings for the quarter benefited from higher distribution sales, primarily from more normal weather versus 2023, the implementation of new base rates in our integrated segment, and the impact of formula rate investments across all of our businesses. These items were primarily offset by higher storm-related expenses, dilution from the 30% sale of FirstEnergy transmission, and the absence of state tax benefits that were recognized in 2023 in our corporate segment. Our team continues to do a great job maintaining their focus on efficient operations and financial discipline while executing against our plan. We experienced headwinds in the quarter, including significant storm expenses, some of which were not deferred for recovery. Our team responded to the headwinds, demonstrating resilience and discipline to achieve third-quarter earnings within our guidance range. I'm proud of their work, and I'm confident that we are building the right team and culture focused on our core values and priorities to ensure that we deliver sustainable value for our customers, communities, and shareholders. Today, we are narrowing our operating earnings range to $2.61 per share, from our previous range of $2.61-$2.81 per share. During 2024, we were able to offset a number of financial headwinds through cost savings and focusing on capital work. In the quarter, we realized significant storm costs that did not meet the regulatory requirements for deferral. This development is leading us to make the guidance adjustment. We are reaffirming our five-year CapEx plan of $26 billion through 2028, as well as our 6%-8% long-term annual operating earnings growth rate, which is driven by average annual rate-based growth of 9%. We plan to provide a more comprehensive update, including a 2025- 2029 financial plan early next year. We've put in the foundational work to support our goals. Now we're executing against our operational, financial, and regulatory plans to become a premier electric company. We'll continue to make meaningful investments that deliver value to our customers. Through the third quarter, our capital investments totaled $3.1 billion, an increase of 22% compared to the first nine months of 2023. We are increasing our 2024 investment plan from $4.3 billion- $4.6 billion, with over 70% in formula rate investments. The enhanced 2024 investment plan reflects increased reliability investments, primarily in our distribution and standalone transmission businesses. We're also participating in PJM's 2024 Regional Transmission Expansion Plan, which is incremental to our $26 billion Energize 365 investment plan. We entered into a joint development agreement with Dominion Energy Virginia and American Electric Power to propose several new regional transmission projects across multiple states within the PJM footprint. These include several new 765, 500, and 345 kV transmission lines in our collective service territories. We believe this collaboration will facilitate joint analysis of constraints, development of long-range buildable solutions, and execution of those solutions in a cost-effective and timely manner. Leveraging each company's strengths, ranging from expertise in constructing and operating different transmission voltage systems to the use of existing corridors and community relationships, will allow for higher confidence in the execution of our proposals. In September, the joint development parties collectively submitted multiple portfolios of solutions to the competitive planning process. The most comprehensive of these options totals $3.8 billion in investment. FirstEnergy also submitted nearly $1 billion of individual projects to PJM for needs that are outside the joint development agreement. PJM staff is expected to select recommended projects by the end of the year, with final approval expected at the PJM board meeting in late February. From an operations standpoint, we're seeing great results from our new business unit structure, and yesterday we made another key addition to our leadership team. Karen McClendon has been named Senior Vice President and Chief Human Resources Officer effective November 11th. Karen brings to FirstEnergy more than three decades of human resources experience, most recently as the CHRO at Paychex. She will spearhead our efforts to integrate and advance our human capital strategy, ensuring alignment with our strategic vision. She will be responsible for functions including talent management, benefits and compensation, labor and employee relations, as well as our commitment to building an inclusive workforce and a workplace reflective of the communities we serve. I am pleased to welcome Karen to FirstEnergy. Our new business unit structure is driving strong performance. This summer, four of our new business unit executives, recruited from inside and outside the company, took the helm at our New Jersey, Ohio, Pennsylvania, and standalone transmission businesses. John Hawkins, President of our Pennsylvania business, led the team to craft the recent rate case settlement, demonstrating our commitment to building constructive regulatory relationships and driving results that support our customers. Torrence Hinton and Doug Mokoid led a tremendous response to challenging summer storms in Ohio and New Jersey. In New Jersey, Doug led JCP&L through 10 separate storm response events since he came on board at the beginning of the summer. These back-to-back events had our crews in storm rotation for six consecutive weeks as they restored service to our customers. In Ohio, a historic storm on August 6th in the Cleveland area disrupted power for more than 600,000 customers. This included five confirmed tornadoes, resulting in significant damage to the electric distribution system. It was the most impactful storm to hit the Cleveland area since 1993. Our response to this storm totaled more than $120 million and involved more than 7,500 workers, including thousands of FirstEnergy employees and contractors from 12 states. This massive restoration effort, with coordination and collaboration across state and local government agencies, was executed at a high level and allowed us to restore power ahead of our original targets. In Ohio, we received positive media coverage and community recognition for our storm response and our consistent, reliable communications. Coming together to help our communities is a hallmark of our industry. We're grateful for the assistance we receive from outside crews, and we're proud to step in when we're needed elsewhere. More than 1,000 of our own employees and contractors were dispatched this fall to help restore power in communities devastated by Hurricanes Helene and Milton. The work that these men and women do is critical to our country, and I thank them for their service. Turning to regulatory matters, in Pennsylvania, as I mentioned, Jon Hawkins led the effort to engage with parties and reach a settlement in our rate review. The $225 million settlement reflects a carefully balanced compromise with key stakeholders, including Public Utility Commission staff, the Office of Consumer Advocate, and various industrial energy user groups and unions. The rate adjustment builds on the service reliability enhancements we've made in Pennsylvania in recent years. It supports upgrading additional distribution grid equipment, ongoing tree trimming, and improving customer service levels. At the same time, it provides additional resources to help vulnerable and low-income customers manage their bills. This month, the Administrative Law Judge recommended that the commission approve the settlement. We anticipate approval in December, with new rates taking effect on January 1st of 2025. In Ohio yesterday, after careful consideration, we filed to withdraw our fifth Electric Security Plan, referred to as ESP 5. As we have discussed previously, the ESP 5 order did not give us clarity on key conditions throughout the term of the ESP. Specifically, conditions for our Distribution Capital Recovery Rider and the Vegetation Management Rider were only defined through the Base Rate Case and not the five-year period of the ESP. Although we had previously requested a rehearing on these issues, a recent Ohio Supreme Court ruling limited the timeframe the commission has to grant rehearing, effectively resulting in our application for rehearing being denied by operation of law. The withdrawal, which is subject to a commission order, will result in the Ohio companies reverting back to ESP 4 until an ESP 6 is filed and approved. We expect to file ESP 6 by early next year, better aligning the review of that ESP with the review of our Ohio Base Rate Case. This alignment should reduce risk and provide needed certainty for our customers and the company. Turning to other regulatory matters, we anticipate an order by the end of the year in our Ohio Grid Mod 2 case. You will recall we filed a partial settlement agreement in April focused on deploying automated meters for all of our Ohio customers, similar to our in-state peers. In New Jersey, we expect BPU approval this week for JCP&L's Energy Efficiency and Conservation Plan. Program costs of $817 million from January 2025 to June 2027 are included in our financial plan. As a reminder, JCP&L earns its authorized return on the included program investments. Currently, we are in settlement discussions on JCP&L's infrastructure investment plan, Energize New Jersey, which includes significant investments over five years to provide customer benefits through system resiliency and grid and substation modernization. As we look to the future needs of our customers, we must address the challenges that are rapidly coming to the U.S. electric system. Analysts forecast that data center and AI share of U.S. electricity consumption will triple to 390 terawatt hours by 2030, equal to the energy use of approximately one-third of U.S. homes. In our own footprint, load study requests for facilities of 500 MW or more have already more than tripled compared to 2023. While we have transmission capacity to support data center investments, we are being thoughtful about our approach to ensure that our existing customers have adequate protections and that we appropriately manage risks. In PJM, the July capacity auction produced record-high prices that will impact monthly residential bills by 11%-19% beginning in June of next year. Despite the increase in prices, there wasn't any new dispatchable generation that cleared the auction. This is concerning to us on behalf of our six million customers as we think about service reliability and customer affordability. These are complex demand and supply-side issues that require long-term thinking and strategy to appropriately support customers' energy needs. We will always advocate on behalf of our customers to ensure reliable and affordable electric service, and we're committed to working collaboratively across the industry to address this challenge on our customers' behalf. We are laser-focused on executing against our plan, which significantly improves the customer experience through resiliency and reliability investments, grid modernization investments, and enhanced tools and communications. It also supports a cleaner grid and increased load growth through operational flexibility. Delivering these benefits to our customers and communities fuels attractive returns and the compelling value proposition we offer to shareholders. Our updated 2024 capital investment plan of $4.6 billion is 24% more than we invested in the full year of 2023 and 7% more than originally budgeted. Our prudent infrastructure investments to support the customer experience, together with incremental opportunities such as PJM's RTEP process, offer FirstEnergy a long runway for growth. With our Pennsylvania rate case settlement, we achieved another milestone demonstrating our ability to reach constructive and reasonable regulatory outcomes that support our customers, our strong affordability position, and our attractive risk profile. Our year-to-date results represent improved earnings quality that is driven by growth in our core regulated business. This earnings growth and strong dividend yield represent a compelling shareholder return with upside potential. We are building the right team and culture, and we have the financial strength to deliver on this plan. This is a new FirstEnergy. I'm proud of the progress we've made and excited about our future. With that, I'll turn the call over to Jon. Thanks, Brian, and good morning. Thank you for joining the call. I'll provide a few more details on our financial performance and regulatory matters, address economic and customer trends, and provide an update on our financial initiatives. Let's start with a review of our financial performance. Our third-quarter earnings of $0.85 a share were at the low end of our guidance range. Operating earnings versus plan were mostly impacted by storm restoration expenses. As Brian mentioned, we experienced a number of storms in New Jersey and Ohio, including a large number that did not meet the regulatory threshold for deferral. Restoration activity resulted in about $30 million of non-deferred storm O&M, which represents 10% of the consolidated O&M in the quarter. Absent this unusual storm activity, we would have been closer to the midpoint of our guidance range. In fact, total year-to-date storm restoration costs are $550 million, of which about $60 million were included in O&M, with the remaining amount included in our investment plan or deferred to the balance sheet. The $0.85 per share for Q3 compares to $0.88 per share in the third quarter of last year, which included a significant state tax benefit in our corporate segment. In our distribution business, earnings were $0.39 a share in the quarter compared to $0.37 a share in 2023. This reflects higher customer demand, mostly from the mild temperatures last year and rate-based growth in formula rate investment programs, partially offset by other items, mainly the impact of the Ohio ESP 5 that was effective June 1st of this year. Operating expense reductions in this business were offset by higher storm restoration expenses. In our integrated segment, consistent with what we have seen throughout the year, earnings increased $0.09 a share, which is a 32% increase over last year. This reflects the implementation of new base rates in Maryland, West Virginia, and New Jersey, rate-based growth in distribution and transmission formula rate investment programs, and lower financing costs, partially offset by higher storm restoration expenses. In our standalone transmission segment, operating earnings were $0.13 a share compared to $0.17 a share in the third quarter of last year. Rate base increased more than 10% year over year as a result of our transmission investment program, but this was offset by the dilution from the 30% interest sale of FirstEnergy Transmission to Brookfield, which closed in March of this year. When adjusted for this transaction, results increased $0.02 a share for the quarter. Finally, in our corporate segment, we reported a third-quarter loss of $0.04 a share versus earnings of $0.06 a share in Q3 of last year, a difference of $0.10 a share. The largest drivers were the absence of a state tax benefit recognized in 2023 that resulted in a 10% consolidated effective tax rate, as well as lower planned earnings from Signal Peak Energy. These were partially offset by lower interest expense from a decrease in average total debt outstanding at FE Corp, a reduction from $6.9 billion in the third quarter of 2023 to $6.1 billion in the third quarter of 2024. Turning to our year-to-date results, I'll remind you that in the second quarter, we took charges for the resolution of the OOCIC and SEC investigations. Those settlements were completed during the third quarter as we worked to move beyond legacy House Bill 6 matters. Year-to-date operating earnings primarily reflect new base rates in our integrated business, growth from formula rate investment programs, and stronger customer demand compared to last year, although weather-related sales are still below normal on a year-to-date basis. These were partially offset by higher planned operating and storm restoration expenses, the impact related to the FET transaction, and lower planned Signal Peak earnings, among other drivers. As Brian mentioned, we narrowed our guidance for the year from 261- 281 cents a share to 261- 271 cents per share, reflecting a midpoint of $2.66 per share versus our original midpoint of $2.71 a share. This reflects a series of unique items in the year and Q3 that impacted our guidance. Residential demand is down 2% year-to-date versus plan, reflecting the impact of mild weather from this winter, although we did see some of that turnaround in Q2. The impact of the Ohio ESP 5, which reduced DCR revenue relative to our guidance by $50 million annually beginning June 1st of this year. Although we have captured O&M reductions to address these challenges, the increased storm restoration O&M expenses in Q3 required us to adjust the midpoint of our guidance. More detail on our third quarter and year-to-date results can be found in the strategic and financial highlights document we posted to our IR website yesterday afternoon. Turning to regulatory matters, as Brian mentioned, in Pennsylvania, we filed our settlement on the base rate case, and the ALJ recommended the Pennsylvania Commission approve the settlement. We view this settlement as constructive and supportive of our investment strategy. The agreement, which includes an increase in net revenues of $225 million, supports investments to strengthen the grid and service reliability while enhancing assistance programs and the customer experience. It also provides for an enhanced vegetation management program to improve reliability metrics. The settlement was based on a 2025 projected rate base of $7 billion and related cost of service. The difference between our original request of approximately $500 million and the $225 million in the settlement mostly relates to proposed future expenses, such as accelerated storm cost recovery and higher depreciation expenses, which will now not be incurred. The revenue adjustment represents a 4.7% rate increase for residential customers, and our residential rates remain 2% below the average of our in-state peers. To stabilize electric bills, the settlement includes a stay-out provision for new rates until January 1st, 2027, which is consistent with our plan. This settlement, once approved, would result in four constructive outcomes in base rate cases over a 14-month period. These cases provide annual revenue adjustments of nearly $450 million, allowing our regulated utilities to increase investments to better serve our customers. In Ohio, Brian mentioned that the decision to withdraw our Ohio ESP 5. The objective is to avoid the uncertainty in ESP 5 with respect to certain conditions, work to get clarity on key rider provisions, and ensure that rider programs are addressed in the appropriate form of an ESP. The Ohio Political Charitable Spending Audit was also completed in the quarter with no new House Bill 6-related findings. The audit report concluded that approximately $15,000 was charged to pole attachment customers, and the report acknowledges that we already agreed to refund this amount with interest. Additionally, hearings were held in the corporate separation audit earlier this month. In New Jersey, as Brian mentioned, we expect a final order this week in our energy efficiency and conservation program for January 2025 through June 2027 that addresses energy efficiency, peak demand reduction, and building decarbonization. The $817 million total program includes $784 million of investments that will earn a return on equity of 9.6% at an equity ratio of 52% and be recovered over 10 years. Looking at economic and load activity in our region, economic trends remain positive, including GDP growth in all five states and an unemployment rate in line with the U.S. average. Customer demand remains positive overall. We're seeing weather-adjusted load growth of about 1% over the last 12 months. While residential and commercial load are essentially flat, industrial demand increased approximately 3%, led by the chemical and automotive sectors, with growth of 7% and 4%, respectively. Turning to our liquidity position and financing plan, on October 24th, we enhanced the company's overall liquidity position by increasing JCP&L's Credit Facility by $250 million to accommodate its increasing investment programs and extended the maturity date on all eight liquidity facilities by one year. Moving forward, FirstEnergy and its subsidiaries have $5.9 billion of committed liquidity to support growth. As of October 28th, FirstEnergy's total liquidity, including cash on hand, was approximately $6 billion. So far in 2024, we've completed four long-term debt transactions at our regulated operating companies, totaling $1.4 billion at a weighted average coupon of 5.1%. In early September, as part of our strategic financing plan, FET launched an $800 million debt transaction in a private offering with SEC registration rights. We priced the senior unsecured notes in two tranches at a weighted average coupon of 4.78%. This transaction, which will be used to redeem $600 million of FET notes, resulted in greater transparency and broadening the investor audience, with the deal being 10 times oversubscribed. JCP&L is considering a similar structured transaction. And finally, earlier this month, recognizing our progress on legacy issues, our improved credit profile, and constructive regulatory outcomes, Fitch upgraded FE Corp's issuer and unsecured credit ratings to BBB flat from BBB minus, and several subsidiaries received a one-notch upgrade. FE Corp and certain subsidiaries remain on positive outlook with S&P. 2024 has been an exciting year marked by several important milestones in our transformation. We believe we are in a very good position with the financial strength and opportunity to build on our momentum and become a premier electric company that delivers value to our customers, communities, and investors. With that, let's open the call to Q&A. Thank you. We will now be conducting a question-and-answer session. If you would like to ask a question, please press Star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press Star two to remove yourself from the queue. For participants using speaker equipment, it may be necessary to pick up the handset before pressing the Star key. One moment, please, as we poll for questions. Our first question comes from the line of Shahriar Pourreza with Guggenheim Partners. Please proceed with your question. Hey, guys. Good morning. Good morning, Shahriar. Brian, last week, you guys filed in the PJM Load Committee indicating kind of load increases of four gigs in ATS and three gigs in APS zones. Those slides that you guys submitted indicated some customers are over 700 megawatts, with one being 1.2 gigs in Ohio and some similar trends in Pennsylvania, with one customer being a gigawatt. I guess, how real are these projects? Is the spend incremental? And could any of these kind of correlate with co-located deals with certain nuclear assets in the area? I guess some color there would be great. Thanks. Thanks for the question, Shahriar. We are definitely seeing an increase in these large load requests for conceptual and specific design load studies. In 2024, we've had over 60 requests for either conceptual or detailed load studies of 500 MW or more. And so we think it's real. These people are talking to us about specific locations, specific investment plans. As you know, we have a number of places where we previously had our own power plants and where there were other industrial centers, places like aluminum smelters that have shut down, where we have transmission capacity to serve large customers at this scale. So we think we have the transmission capacity. People are looking to us. There's land available. And we believe it's real from the discussions that we're having with these folks. Some of these things are public. You've seen in places like the Panhandle of Maryland. You've heard about things like Quantum Loophole there, which is a very, very large load, and it's meant to be expansive capacity relative to the Northern Virginia data load center campuses. We're seeing other interest in what they call the Panhandle of West Virginia, which is just across the border from Maryland there, and then along the lake in the Ohio River Valley. So it's real. It's coming. The conversations we're having with people are detailed about when and where they're going to be investing on our system. And we look forward to serving those customers as they come online. Can you confirm, Brian, if any of the ones that are over a gigawatt, because it just mentions customer one, customer two, are they data centers? I would say yes, they are. Okay. Perfect. And then just lastly, on ESP 5 withdrawal, can you maybe just dig into kind of the financial impacts from reverting back to ESP 4? Does vetting through ESP 6 while in a GRC kind of complicate things, just given the number of unrelated moving pieces in the current GRC filing, like goodwill treatment? I mean, this is kind of the first time in a while the PUCO is looking at all the riders. It's a lot to juggle. So maybe just some sense there. Thanks. Yeah. So thanks for the question, Shahriar. The financial implications of the withdrawal of ESP 5 are not significant. It's really more of a risk play. It's the idea that certain of the riders that are covered, should be covered in ESP 5, were punted to the general rate case, so we didn't know what their treatment would be beyond that. And this really allows us the opportunity to time the alignment of ESP 6 now with when the general rate case will come out. We've talked to our people in rates about this and said, "Does this complicate things in the general rate case?" And the answer we got was, "This actually simplifies the general rate case and puts the riders where they appropriately belong in ESP 6." This is something we were hoping to avoid on rehearing. And then an order out of the Ohio Supreme Court really withdrew the opportunity to address these in rehearing. And that really tipped our hand. But it's much more of a risk reduction play rather than a financial play around ESP 4 versus ESP 5 or 6. Okay. That's perfect, Brian. That's super helpful. I'll see you guys in about a week. Thanks. Thanks, Shah. Thank you. Our next question comes from the line of Nick Campanella with Barclays. Please proceed with your question. Hey, good morning. Thanks for taking my questions. Morning, man. Morning. Just a quick follow-up on Shahriar's question, just to tie that one off. Just the large load requests, how much capacity is on your transmission system today to facilitate those requests? And then separately, but somewhat related, just with these large loads, potentially things still targeting for behind the meter, and you kind of flagging the higher bills in PJM, how should we kind of think about an 11%-19% increase against a 6% distribution rate-based growth outlook? Can you still kind of execute on that against that bill outlook? Thank you. Thank you for the question, Nick. First, on the capacity that we have, we think we have several thousand megawatts of transmission capacity to be able to serve data center and other loads. And like I said earlier, it's mostly associated with transmission capacity that was used for either power plants that are no longer operating or large industrial customers that have moved on to other places. So we think we have a significant amount of unused capacity that's available to be consumed by data center or other large loads. And I just want to remind people that that's actually good for existing customers, right? We're taking that existing capacity and spreading it over more units for more customers. And that's a rate positive for existing customers as they're consuming unused capacity. In terms of the rate impacts of capacity auctions and the like, those capacity auctions take up headroom and cost our customers real dollars. And the thing that we're concerned about there is that, are they actually getting increased capacity and enhanced reliability for the dollars that they're spending in 2025 and 2026? People talk about sending price signals. We're not sure that these price signals are, in the near term or long term, going to result in incremental net new capacity. And so we're concerned about that. We're talking to legislators, regulators, customers about solutions that would actually add net new capacity at reasonable costs and are looking to be positively engaged in discussions to bring that about. So we don't think today that the costs that are being passed on are going to impair our ability to get regulatory recovery for the investments that we're making, but think that we, as well as others, need to be prudent with every dollar that we're asking our customers to spend for electric service. Yep. That makes a lot of sense, and I appreciate your comments there. Quick question, just good to see the Pennsylvania settlement filed in September. And I know we'll have that order in December. But you are showing a 2.5% earned ROE in Pennsylvania. And every seven cents is for 100 basis points improvement in ROE. Does seem like it would be material. Just should you get back to a regular return here in 2025? Is that the way to kind of think about this? Or are you still going to be lagging? Hey, Nick, this is Jon. So that 2.5% was based on the filing that we made in the application, so requesting the $500 million net revenue adjustment. So that included a lot of proposed expenses to support that rate increase. Now that we have the settlement in place, we'll be at a much more normalized level in terms of the return there. Okay. Thanks for that clarification. Have a good day. Thanks, Nick. Thank you. Our next question comes from the line of David Arcaro with Morgan Stanley. Please proceed with your question. Oh, hey. Thanks. Good morning. Good morning, David. Wondering if you might be able to elaborate on some of those options that you mentioned you're discussing in terms of getting more generation built in PJM. Yeah. So I think that there are some solutions that could be outside of a PJM capacity auction construct that might bring certainty of net new capacity coming on board relative to the sending of price signals that we hope will result in incremental capacity coming on. I think there are market constructs that we've seen out there that have worked. Things like NYPA, NYSERDA, where you have state agencies that run auctions to bring in certain types of capacity. I could see that being effective in places like Ohio, Pennsylvania, Maryland, and others, where a state agency could ask all comers to bid on net new capacity in a given year of a certain type. I'd say dispatchable generation in a year like 2030, 2031, of a combined cycle nature, and allow everyone to bid on delivering that. IPPs could, investment companies could, utility companies could. You'd be certain through a contract and certain design milestones that you would know that that net new capacity was going to be delivered in that state. And I think it's just solutions like that, rather than sending price signals you hope will be effective. Actually have real auctions with real counterparties with real milestones, so you'll know that that capacity will be there when the state needs it. Got it. Got it. That's helpful. And then, I guess, as you look out at all these load requests out over the next several years, just wondering what your thoughts are in terms of looking at your own load forecast. When might you reassess and give a new longer-term outlook in terms of what you're expecting for load growth? Yeah, Dave. So I think the current plan right now is to provide that update early next year, likely on the fourth quarter call as we update the longer-term plan. So I think the plan is to give 2025 guidance as well as a 2025 to 2029 CapEx and long-term growth rate plan sometime on the fourth quarter call. Okay. Great. Thanks so much. Thanks, Steve. Thank you. Our next question comes from the line of Steve Fleischman with Wolfe Research. Please proceed with your question. Yeah. Excuse me. Good morning. Thanks. Good morning, Steve. So I know there's been some challenges this year, but I just wanted to clarify. You reaffirmed the 6%-8% growth off basically last year's midpoint. Is that? That's right. So the way to think about it, the 271 was based off last year's midpoint of 254. Our growth going forward is going to be based off the 271. Okay. So you're not going to, right. You're not going to go down to this lower half. Correct. Okay. Good. Then just for 2025 specifically, just as you on the one hand, you have to manage this period with the going back to the prior ESP, but you do get the DCR back. But then on the other hand, you get Pennsylvania rate relief. So is 2025 kind of okay to be within that 6%-8% growth rate? Oh, yeah. Absolutely. I mean, if you think about the Pennsylvania rate case, you think about our CapEx plan in terms of the amount that's formula rate-driven, plus the financial discipline that we need to create in the organization, we feel really good about our plan for next year. Okay. Good. Then maybe, Brian, back to the prior question about generation solutions, the idea you mentioned of state agency and the like. In your key states, would those require legislation, or would they be feasible without a bill? I think solutions like what I described, where you'd have a state agency, would definitely require legislative action. Things like utility builds in and of themselves would not necessarily include legislative changes in West Virginia, Maryland, and Ohio, but would require legislative changes in Pennsylvania and New Jersey. We are not interested in building competitive generation. If a state would like us to and we'd come to agreement, we would consider adding long-term regulated generation if that was in the state's interest to do that. But I think we'd get a lot of opposition from places like IPPs and others. If they would like to commit to build in something that looked like a state auction, I think that would be a way to have all comers bring their solutions to the problems that the states are facing and might be less likely to have strong opposition from others in the IPP camp. Got it. Thank you. Thank you. Thank you. Our next question comes from the line of Michael Lonegan with Evercore ISI. Please proceed with your question. Hi. Thanks for taking my question. So you have no equity in your financing plan beyond the employee benefit program. Just you're highlighting a lot of incremental investment opportunity. How should we think about financing that additional spending? What portion do you see that needed to be funded with new equity? Yeah. So Michael, I mean, we talked about before. We have some cushion in the metrics that would equate to about 5% of additional CapEx to the $26 billion. And if you look at some of the transmission opportunities that we're pursuing, depending on the different types of solutions, some of that might even fall outside of our current planning window and would be in 2029 and beyond. And a lot of that, quite frankly, is going to be at the FET business, which would be obviously a 50% ownership with Brookfield. So based on everything we know right now, we're comfortable with our current plan. Great. Thanks. And then secondly, so you just talked about some cushion in your metrics. You obviously increased your 2024 capital program and had higher storm costs during the quarter. Where do you expect to end this year on FFO to debt versus the targeted 14%-15%? Yeah. So this year, we'll probably be just under 13%. And a lot of that was impacted by the SEC and OOCIC payment, as well as that unusual storm event we saw in Cleveland back in August. I mean, those two events alone were about $200 million of FFO. So if you were to strip that out and normalize that, I think we'd be closer to 14%. Thanks for taking my question. Thank you, Michael. Thank you. Our next question comes from the line of Anthony Crowdell with Mizuho Securities. Please proceed with your question. Hey, good morning. If I could follow up on this storm question. I think you said some of the cost didn't meet a regulatory threshold for recovery or, I guess, maybe for capitalization. Does that change how you'd respond to storms going forward or anything the utility could do to maybe get a rider or something that prevents that from happening again? So it would never change how we respond to storms, Anthony. We are going to work with dispatch and with all haste to return our customers who are knocked out of service due to storm activity. And restoring customers to service safely and as quickly as possible will always be a key priority for us. We will always, at the same time, work with regulators and others to make sure that we get timely recovery for what we spend on storms. I don't think people would like us to even consider, and we won't, how much it costs to get people back as quickly as we can. But we should also have some comfort and certainty that we'll get timely recovery for what we prudently incur restoring people to service. So I think there's a balance there. I think regulators want us to spend what we need to to prudently get people back to service, not wasting any dollars at all, but to be thoughtful about the dollars we spend and to have a comfort that we'll get recovery for everything we prudently spend. It's been a remarkable year for storms, and it's not just us. I think you're seeing it with other utilities across the country. And I see things like mutual assistance and how they actually happen. It was fascinating, the August 6 storm that we had in the Cleveland area, right? It was such a localized event that it basically hit only us in the Cleveland area and Cleveland Public Power. And our neighbors, right, my friends at AEP, our friends at DTE, PPL, and others who were neighboring us offered resources immediately, and they were on the ground the next day helping us get people restored. It was a privilege for us then to be able to return those favors during the hurricane events that we had. And our people were interested to go, willing to go, happy to go help in those circumstances that our employees tell me were absolutely dire circumstances for the communities that they helped restore to service. So we're going to spend what we need to prudently to get people back. And we think it's fair that we have comfort and certainty that we'll get recovery for what we do spend returning people. Great. And lastly, when you unveiled the 6%-8% growth rate and the capital plan, I think you had said some of the updates today. I think your capital plan is roughly 7% higher than you originally thought. Does that change where you think you would land in the 6%-8% EPS growth rate? Should we think of now you're trending more towards the higher end as you've increased your CapEx by 7%? So Anthony, that increase of CapEx for 7% was 2024 over originally budgeted. The plan that we laid out previously, the $26 billion five-year CapEx plan, really gives us about 9% of rate base growth on average over that period. And that's what drives the 6%-8% growth. So we're still within that range. It's still being driven by our investment in our regulated properties and timely regulatory recovery of that. And remember, a significant percentage, about 70% of the investments that we make are covered by trackers and riders. Great. If I could just squeak one in, I guess, to Steve's question, David's question. You talked about solutions and options maybe to add generation at reasonable cost. You mentioned some state agencies here in New York. I'm just curious, what do you think the timing is on a solution? How long do you think customer bills are impacted by these capacity charges before the state or the government will act to mitigate it? Yeah. So that's the concern, Anthony, is the disconnect between the timing of adding significant amounts of load, whether it be data center or other load that you can really add to the system in about two to three years. And to permit, construct, and procure for a power plant probably takes in the order of about six years. So are our customers going to pay higher capacity auction prices for the next six years before any net new capacity shows up from the price signals that are being sent to this market? It's a concern. And I think states would do better to take these matters into their own hands the way traditional IRP states do, like West Virginia, and be sure that the capacity is there when the state needs it, rather than hoping price signals have the intended effect six years from now. Great. Thanks for taking my questions. Thank you, Anthony. Thank you. Our next question comes from the line of Angie Storozynski with Seaport Global. Please proceed with your question. Thank you. So I just wanted to follow up on those last comments about the six-year wait. I mean, that's how long it would take to build a new power plant anyway, right? So how different would it be versus some intervention in the competitive power market? Also, I don't recall you guys ever making the opposite comment when capacity prices were clearing at $30. I don't remember you guys mentioning that you're concerned about how these low capacity prices will impact the availability of dispatchable power plants in PJM. Well, to your last comment, I'm not sure that was a question. But to the first part of your comments, it does take about six years to permit and build a power plant from the time that you conceive of doing that. The difference for an actual auction where you are contracting with someone to do that is you can monitor their permitting, procurement, and construction during those six years versus the PJM capacity construct where you're hoping that people respond in a way you would like them to today to have a result six years from now. So it's a difference between contracting, monitoring, and verification versus hope. And those are two different things entirely. Right. But one is a regulated setup, but the other one is a competitive power market. I mean, that's basically how it works, no? No, that's not right. What I'm talking about is a construct that is a market where you do have an auction where a state would have an auction, say, all comers, IPPs, utilities, investment companies, insurance companies can come and offer to build. What would you charge me to do it? What would your price be? And then we would have and you'd have a winner from that auction. So it would be a market, and you would go from there. And yeah. So both are markets, is what I'm saying. And both are market solutions. Okay. Understand. Then secondly, so you're talking about the excess transmission capacity in Ohio. But when I actually look at the power flows in PJM, Ohio is an importer of power from Pennsylvania, especially, I think, your area. So now Pennsylvania wants to clearly build up demand for electricity in its states that would seemingly limit the flows of power into Ohio. So is that fair to add load in Ohio given the fact that the state already relies on imports of power? Yeah. So when I talk about capacity, I'm talking about transmission capacity. So we have the wires' capacity to be able to serve load. We are in a regional power pool where there are power flows from states who are long to states who are short. And that's currently handled generally through the PJM power markets. What's needed because of this situation that we find ourselves in with resource adequacy? We do need as a region, and then as you divide that out into states, we need net new dispatchable capacity to be added. And whatever construct enables us surety around that happening at a reasonable cost to our customers, we're in support of. Okay. And then changing topics about the withdrawal of ESP 5 in Ohio. So now, I mean, I understand that it was not optimal, to say the least. But now, basically, the entire 2025, we will be waiting to have visibility into your earnings power in Ohio. And I mean, I don't quite understand how that helps to add visibility. I mean, it's almost as if we have now two rate proceedings. So isn't this doubling down on the regulatory risk associated with Ohio? No, Angie, really the opposite. We're going back to the certainty and transparency that we had in ESP 4, that we knew what our earnings power was there. We knew the timing of it. And this actually better aligns the result of an ESP6 that we're going to file with the Ohio-based rate case. So rather than creating uncertainty, it actually will bring more certainty and actually reduce risk. Okay. I might go off on this one. Thank you. Bye-bye. Bye. Thank you. And we do ask all analysts asking questions to please limit themselves to one question and one follow-up in the interest of time. Thanks. Our next question comes from the line of Paul with Glenrock Associates. Please proceed with your question. Hey, good morning. Good morning, Paul. So just back to the capacity alternatives that you were mentioning. I think with Steve's question, you mentioned the ability of doing perhaps something in rate base, if I heard you correctly, in West Virginia, Maryland, and Ohio. Is that correct? So in West Virginia, certainly. And in Ohio and Maryland, there are provisions in current law that would allow a regulated utility to build generating capacity and get recovery for it. And I heard everything you've said, and a lot of it makes a lot of sense, obviously, concerning what's going on with the capacity markets. But when I think about this, just you guys building modest levels of capacity, it could have a dramatic impact on the capacity market, so to speak, given the vertical demand curve and what have you that P3 and others have said. And I'm just wondering, it would seem to me that it wouldn't just be sort of a modest or a reasonable cost to customers. It would actually maybe perhaps lower cost to customers if you were to take into account the wholesale market impact. So, I guess what I'm wondering is, that seems like something given what Maryland and Ohio and Pennsylvania and New Jersey, all this concern that's already been voiced about the capacity market. What's your sense about the appetite for simply just going forward with that as opposed to a rather more arcane—I don't know how to put it—the stakeholder process, the FERC process of going through the PJM capacity market stakeholder process, if you follow what I'm saying? Do you see what I'm saying? We seem almost a lot more efficient maybe just to go that way. I do, Paul. This company just spent a lot of time and balance sheet capacity getting out of the generation business and moving into a deregulated wires-only stance. We're going to be very thoughtful about returning to investments in generation in states where we just got out of it at many of their being responsive to many of their energy policies that got us here. We're going to be thoughtful and try and come up with solutions that don't add undue capacity to undue risk to the company, but help solve the solution. So we're open to a number of solutions. The one we're not open to is going into the competitive generation business. The virtual business. Okay. Fair enough, I guess. Stay tuned, I guess, right? Yes. Okay. And so then just finally, just to follow up on the approval process for withdrawing this ESP5 and what have you, it sounds like you need something from FERC. I'm sorry, from PUCO on this. But it seems like do you see that as being. It doesn't look that controversial to me from the outside, but could I be missing something? It should not be controversial, Paul. It's something that we've seen it happen before with other in-state peers. And in getting that approval, it took about a month from the time that they asked for it. So you're just going back to a construct that everyone was comfortable with previously. And obviously, we can't put our own rates into effect, so we need to go through the regulatory process. But it should be a brief process, and it should not be controversial. Awesome. Thanks so much. Thanks, Paul. Thank you. Our next question comes from the line of Sophie Karp with KeyBanc Capital Markets. Please proceed with your question. Hi. Thank you for presenting here at the end. Just wanted to quick follow-up on the discussion about the potential changes in the market construct, right, that you're talking about. Given that there are several states that you mentioned, right, with these power flows between them, New Jersey, Pennsylvania, Ohio, would those states have to act simultaneously in this new design of the market to avoid one state subsidizing effectively another with the rate-based money from that state, or how would that work? Thank you. Thank you for your question, Sophie. I don't think so. According to the Federal Power Act, each state is responsible for making sure that it has the amount of generation that's needed to serve its state's needs. States like West Virginia do that through a traditional IRP process, and other states do that through a PJM solution using the capacity construct that PJM has. So having signed on to that construct, that's what many of the states are using. If they think that's working for them and their customers, they can stick with that. If they'd like to take matters into their own hands more directly, they can avail themselves of some of the alternative solutions that we suggested. But no, they could act on their own. And many states have done that already, even in PJM. Got it. Got it. And just to clarify, you're saying that even though the states are deregulated markets, utility is allowed to own generation in the states in the current legal framework? Yes. All right. And again, Sophie, those are issues that are driven by state law. And in our states, the state of West Virginia, Ohio, and Maryland, the states do allow for utility-owned generation. All right. Thank you so much. Thank you for your question. Thank you. Our next question comes from the line of Andrew Weisel with Scotiabank. Please proceed with your question. Hi. Thanks, everyone. Good morning. I'll be brief here. Just quickly on the CapEx increase for 2024, specifically what drove the increase? What kind of spending was it? And was it a pull forward for 2025, or were these incremental opportunities that you didn't anticipate six or 12 months ago? Yeah. So some of the increase, Andrew, was storm-related. So in our distribution business, specifically in Ohio, they had the big storm in August. So some of it was storm CapEx-related. There was some LTIP work in Pennsylvania that we needed to fund as well in our distribution segment. And then the rest of it was what I would consider transmission opportunities, incremental opportunities for this year. So the $26 billion is still intact. I mean, but I don't think it's going to take us off track in terms of the CapEx that we plan for next year. Okay. Great. And then just a quick follow-up. You mentioned, Jon, that you're going to do a refresh and roll forward on the fourth quarter call early next year. Do you have a sense in terms of timing around the PJM transmission opportunities? Will you have a sense about potential wins there, or would you make assumptions around that? Yeah. We'll have a pretty good sense by that time. I think there's several advisory committee meetings between now and then with the final PJM board approval expected in the February timeframe. So we'll have a good sense of that. And if we don't have final approval, we'll kind of let you know where we stand and what we have in the plan and what maybe is to come depending on the outcome of that. Very good. Thank you. Thank you, Andrew. Thank you. Our next question comes from the line of Paul Fremont with Ladenburg Thalmann. Please proceed with your question. Thank you very much. I was going to ask if you could walk us through the procedural path to withdraw ESP5 at the PUCO. Will it involve testimony and hearings? What's involved in terms of getting PUC approval? Yeah. So Paul, we have precedent where there was a case in 2019. The application was filed. There were comments filed amongst different intervening parties. There were no hearings in that particular case. And then there was a commission order on the application to withdraw within a month. So that's kind of the timeline that we're working on. So my sense is there would be comments filed on the withdrawal application. The commission then would consider those comments and then rule on the withdrawal sometime within 30 days based on that precedent. And the precedent that you're talking about, was the application to withdraw contested by intervenor parties, or was it widely accepted by intervenor parties? I'm sure it was mixed. I mean, there was probably some that objected to the withdrawal. There was probably some that supported the withdrawal. But I'm sure just like any regulatory proceeding, there was some that objected, some that supported. The ability to withdraw is codified in Ohio legislation. So it's there. It's a real thing. It's been tested before and actually administered and executed by a utility previously and approved by the commission. So there's precedent for doing exactly what it is we're asking to do. Great. And last question, what type of proceeding was it that you were referring to in 2019? Was it PUC or? You can look it up; it was Dayton Power and Light in their current ESP. And you can pull up the document, I'm sure, on the utility commission website. Perfect. Thank you so much. Thank you, Paul. Thank you. We have reached the end of our question-and-answer session. And ladies and gentlemen, this does conclude today's teleconference webcast. You may disconnect your lines at this time and have a wonderful day. We thank you for your participation.