Firstenergy Corp (FE) — Q3 2024 Earnings Call Transcript

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 to $2.71 from our previous range of $2.61 to $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% to 8% long-term annual operating earnings growth rate, which is driven by average annual rate base growth of 9%. We plan to provide a more comprehensive update, including a 2025 to 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 to $4.6 billion, with over 70% in formula rate investments. The enhanced 2024 investment plan reflects increased reliability investments, primarily in our distribution and stand-alone transmission businesses. We're also participating in PJM's 2024 regional transmission expansion plan, which is incremental to our $26 billion Energize365 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-kV, 500-kV, 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 strength, 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 operation 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 stand-alone 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 and 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 received 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, John 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 1, 2025. In Ohio yesterday, after careful consideration, we filed to withdraw our fifth electric security plan referred to as ESP V. As we have discussed previously, the ESP V 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 time frame 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 IV until an ESP VI is filed and approved. We expect to file ESP VI 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 II 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 end-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, EnergizeNewJersey, 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 megawatts 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% to 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 6 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 base growth in formula rate investment programs, partially offset by other items, mainly the impact of the Ohio ESP V 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 base growth in distribution and transmission formula rate investment programs, and lower financing costs, partially offset by higher storm restoration expenses. In our stand-alone 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've 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. 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 work 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 $2.61 to $2.81 a share to $2.61 to $2.71 per share, reflecting a midpoint of $2.66 per share versus our original midpoint of $2.71 per 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 V, which reduced DCR revenue relative to our guidance by $50 million annually beginning June 1st of this year. And 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 in 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 end-state peers. To stabilize electric bills, the settlement includes a stay-out provision for new rates until January 1, 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 the decision to withdraw our Ohio ESP V. The objective is to avoid the uncertainty in ESP V 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 reported knowledge is 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 the 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% and 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 10x 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- 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 marking 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.

Hey guys. Good morning.

Good morning, Shar.

Brian, last week, you guys filed in the PJM load committee indicating kind of load increases of 4 gigs and seeing 3 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.

Thank you for the question, Shar. We are certainly observing an increase in requests for both conceptual and detailed design load studies. So far in 2024, we've received over 60 requests for load studies of 500 megawatts or more. We believe this demand is genuine, as these parties are discussing specific locations and investment strategies with us. We have several sites where we previously operated our own power plants and other industrial centers, such as aluminum smelters that have closed, where we possess the transmission capacity necessary to accommodate large customers. The conversations indicate that we have the capability to support these opportunities, there is available land, and we believe the commitment is real based on our discussions. Some of these projects are public knowledge; for example, you may have heard about developments in the panhandle of Maryland, including a significant project known as Quantum Loophole, which is aimed at expanding capacity in relation to the Northern Virginia data load center campuses. We are also seeing growing interest in the panhandle of West Virginia, right across the border from Maryland, as well as along the lake and the Ohio River Valley. This demand is substantial and increasing. The discussions we're having are specific about the timing and locations of investments in our system, and we are eager to serve these customers as they come online.

Can you confirm, Brian, if any of the ones that are over a gigawatt because it just meant is customer one, customer two. Are they data centers?

I would say yes, they are.

Okay. Perfect. And then just lastly on ESP V withdrawal, can you maybe just dig into kind of the financial impacts from reverting back to ESP IV. And does vetting through ESP VI, while in the GRC kind of complicated 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 PCO is looking at all the riders. It's a lot to juggle. So maybe just some sense there. Thanks.

Thank you for the question, Shar. The financial impact of withdrawing ESP V is minimal. It's primarily a matter of risk management. Some of the riders that were supposed to be included in ESP V ended up being pushed to the general rate case, so we were uncertain about their future handling. This situation now gives us the opportunity to align ESP VI with the timing of the general rate case release. We consulted with our rates team regarding whether this would complicate the general rate case, and we were assured that it actually simplifies the case, placing the riders where they rightfully belong in ESP VI. We aimed to avoid this issue during rehearing, but a ruling from the Ohio Supreme Court took away the chance to address these matters. Ultimately, this is more about reducing risk rather than making financial decisions concerning ESP IV compared to ESP V or VI.

Okay. That's perfect, Brian. That's super helpful. I'll see you guys in about a week. Thanks.

Thanks, Shar.

Hey, good morning. Thanks for taking my questions.

Good morning, Nick.

Just a quick follow-up on Shar'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're kind of flagging the higher bills in PJM. How should we kind of think about like an 11% to 19% increase against like a 6% distribution rate base growth outlook? Can you still kind of execute on that against that build outlook? Thank you.

Thank you for the question. 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 '26. 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, and 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.

Yes, 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 like a 2.5% earned ROE in Pennsylvania and every $0.07 is for 100 bps improvement and ROE does seem like it would be material. Just should you get back to a regular return here in '25? 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.

Hi, 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.

Yes, I believe there are solutions beyond the PJM capacity auction that could ensure the addition of new capacity while effectively signaling prices. We have seen successful market mechanisms like NIPA and NYSERDA, where state agencies conduct auctions to acquire specific types of capacity. I can envision similar approaches in states like Ohio, Pennsylvania, and Maryland, where a state agency invites bids for new capacity of a certain type, such as dispatchable generation for the years 2030 and 2031, particularly in a combined cycle format. This process would allow various entities, including independent power producers, investment firms, and utility companies, to bid on delivering that capacity. By establishing contracts and design milestones, we could ensure that the new capacity is guaranteed to be delivered in that state. Rather than merely relying on price signals that might or might not work, having genuine auctions with actual participants and clear milestones will facilitate the certainty that the necessary capacity will be available when required.

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?

Yes, 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, Dave.

Yes, excuse me. Good morning. Thanks.

Good morning, Steve.

Yes. I know there have been some challenges this year, but I wanted to clarify that you reaffirmed the 6% to 8% growth based on last year's midpoint? Is that correct?

That's right.

So the way to think about it, the $271 million was based off last year's midpoint of $254 million. Our growth going forward is going to be based off the $271 million.

Okay. So you're not going to go down to this lower half.

Right.

Okay. Good. And then just for '25 specifically, you need to manage this period with the transition back to the prior ESP, but you do get the DCR back. On the other hand, you also receive Pennsylvania rate relief. So is '25 expected to fall within that 6% to 8% growth rate?

Yes, 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. Brian, regarding the previous question about Generation Solutions, in your key states, would the idea you mentioned about state agencies require legislation, or could it be implemented without a build?

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 legislation 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 when we'd come to an 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 looks 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 a strong opposition from others in the IPP camp.

Got it, thank you.

Thank you, Steve.

Hi, thanks for taking my questions. 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?

Yes. 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 '29 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% to 15%?

Yes. 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 questions.

Thank you, Michael.

Hey, good morning. If I could follow up on the storm question. I think you said some of the costs 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 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 not out of service due to storm activity. And restoring customers to serve as 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. Our neighbors, right, my friends at AEP, our friends at DT&E, PP&L, and others who are 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, and happy to go help in those circumstances that our employees tell me were absolute 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 a 6% to 8% growth rate and 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% to 8% EPS growth rate? Should we think of now you're trending more towards the higher end as you 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% to 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 or 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? Like how long do you think customer bills are impacted by these capacity charges before like the state or the government will act to mitigate it?

Yes. 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 construct, 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 prints 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.