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FirstEnergy owns 10 energy companies that generate and supply energy to customers across the Mid-Atlantic and Midwest.

This year's Fortune 500 marks the 65th running of the list.

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This year's Fortune 500 marks the 61st running of the list. Wal-Mart claims the top spot again. See who made the list.

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FirstEnergy was formed in 1997 through the merger of Ohio Edison and Centerior Energy. Together with its subsidiaries, FirstEnergy is engaged in the transmission, distribution, and generation of electricity in the U.S., serving customers across Ohio, Pennsylvania, New Jersey, West Virginia, Maryland, and New York. It operates through three business segments: distribution, integrated, and stand-alone transmission.

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Q3 2024

FirstEnergy (FE): Company Profile, Stock Price, News, Rankings

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FirstEnergy

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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 Kaffee, Director of Investor Relations and Corporate Responsibility. Please go ahead, Gina.

Thank you. Good morning, everyone, and welcome to FirstEnergy's Q3 2024 earnings review. Our President and Chief Executive Officer, Brian Tierney, will lead our call today, and he will be joined by John 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 in 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 Q3 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 Q3 results, GAAP earnings from continuing operations were $0.73 per share compared to $0.74 per share in the Q3 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 3rd 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 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 5 year CapEx plan of $26,000,000,000 through 20.28 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 20 29 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 Q3, our capital investments totaled $3,100,000,000 an increase of 22% compared to the 1st 9 months of 2023. We are increasing our 2024 investment plan from $4,300,000,000 to $4,600,000,000 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 $26,000,000,000 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, 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 $3,800,000,000 in investment. FirstEnergy also submitted nearly $1,000,000,000 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 11. Karen brings to FirstEnergy more than 3 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, 4 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 McCoy led a tremendous response to challenging summer storms in Ohio and New Jersey. In New Jersey, Doug led JCP and 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 6 consecutive weeks as they restored service to our customers. In Ohio, an historic storm on August 6th in the Cleveland area disrupted power for more than 600,000 customers. This included 5 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 $120,000,000 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 a 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 $225,000,000 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 approved 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 5th electric security plan referred to as ESP5.

As we have discussed previously, the ESP5 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 5 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 withdraw, 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 and L's energy efficiency and conservation plan. Program costs of $817,000,000 from January 2025 to June 2027 are included in our financial plan.

As a reminder, JCP and L earns its authorized return on the included program investments. Currently, we are in settlement discussions on JCP and L's infrastructure investment plan, energize New Jersey, which includes significant investments over 5 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 3.90 terawatt hours by 2,030 equal to the energy use of approximately 1 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 6,000,000 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 $4,600,000,000 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 RTAP 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 first energy. I'm proud of the progress we've made and excited about our future. With that, I'll turn the call over to John.

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 Q3 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 $30,000,000 of non deferred storm O and M, which represents 10% of the consolidated O and 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 $550,000,000 of which about $60,000,000 were included in O and 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 Q3 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 1 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 Q3 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 3rd 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 $6,900,000,000 in the Q3 of 2023 to $6,100,000,000 in the Q3 of 2024. Turning to our year to date results, I'll remind you that in the Q2, we took charges for the resolution of the OOCIC and SEC investigations. Those settlements were completed during the Q3 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. And 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 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 planned 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 $50,000,000 annually beginning June 1st this year.

And although we have captured O and M reductions to address these challenges, the increased storm restoration O and M expenses in Q3 required us to adjust the midpoint of our guidance. More detail on our Q3 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 $225,000,000 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 $7,000,000,000 and related cost of service. The difference between our original request of approximately $500,000,000 and the $225,000,000 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 1, 2027, which is consistent with our plan. This settlement once approved would result in 4 constructive outcomes in base rate cases over a 14 month period. These cases provide annual revenue adjustments of nearly $450,000,000 allowing our regulated utilities to increase investments to better serve our customers. In Ohio, Brian mentioned that 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 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 $817,000,000 total program includes $784,000,000 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 5 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 24, we enhanced the company's overall liquidity position by increasing JCP and L's credit facility by $250,000,000 to accommodate its increasing investment programs and extend the maturity date on all eight liquidity facilities by 1 year. Moving forward, FirstEnergy and its subsidiaries have $5,900,000,000 of committed liquidity to support growth. As of October 28, FirstEnergy's total liquidity including cash on hand was approximately $6,000,000,000 So far in 2024, we've completed 4 long term debt transactions at our regulated operating companies totaling $1,400,000,000 at a weighted average coupon of 5.1%.

In early September as part of our strategic financing plan, FET launched an $800,000,000 debt transaction in a private offering with SEC registration rights. We priced the senior unsecured notes in 2 tranches at a weighted average coupon of 4.78%. This transaction, which will be used to redeem $600,000,000 of FET notes, resulted in greater transparency and broadening the investor audience with the deal being 10 times oversubscribed. JCP and 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.

Issuer and unsecured credit ratings to BBB Flat from BBB Minus and several subsidiaries received a 1 notch upgrade. FE Corp and certain subsidiaries remain on positive outlook with S and 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 and A.

Thank you. We will now be conducting a question and answer session. Our first question comes from the line of Shahriar Pourreza with Guggenheim Partners. Please proceed with your question.

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

Thanks for the question, Shar. 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 megawatts 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 are other industrial centers, places like aluminum smelters that have shut down or we have transmission capacity to serve large customers at this scale. So we think our 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.

And 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. These 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.

if any of the ones that are over a gigawatt because it just mentions customer 1, customer 2, are they data centers?

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 ESP4? And does vetting through ESP6 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.

Yes. So thanks for the question, Shar. 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 didn't 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 not 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 ESP4 versus ESP5 or ESP6.

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

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.

Good morning. 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 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 bill outlook? Thank you.

the question. First on the capacity that we have, we think we have several 1,000 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 on 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 in ROE, it does seem like it would be material. Just should you get back to a regular return here in 'twenty five?

Is that the way to kind of think about this?

Hey, Nick, this is John. So that 2.5% was based on the filing that we made in the application, so requesting the $500,000,000 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.

Thank you. Our next question comes from the line of David O'Carroll with Morgan Stanley. Please proceed with your question. Hey, thanks.

you might be able to elaborate on some of those options that you

mentioned you're discussing in terms of getting more generation.

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. And I think there are market constructs that or there are 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 2,030, 2001 of a combined cycle nature and allow everyone to bid on delivering that. IPPs could, investment companies could, utility companies could.

And 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?

Yes, Dave. So I think the current plan right now is to provide that update early next year likely on the Q4 call as we update the longer term plan. So I think the plan is to give 2025 guidance as well as a 2025 to 20 29 CapEx and long term growth rate plan sometime on the yes, on the Q4 call.

Thank you. Our next question comes from the line of Steve Fleishman with Wolfe Research.

So I know there's been some challenges this year, but just the I just wanted to clarify, you reaffirmed the 6% to 8% growth off basically last year's midpoint. Is that

That's right. So the way to think about it, the $271,000,000 was based off last year's midpoint of $254,000,000 Our growth going forward is going to be based off the $271,000,000

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

Okay. Good. And then just for $25,000,000 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 25% kind of okay to be 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. And then maybe Brian back to the prior question about Generation Solutions, the idea you mentioned of like state agency and the like. In the key in your key states would those require a 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 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 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.

FirstEnergy (FE) Q3 2024 Earnings Call Transcript

Company Participants