Firstenergy Corp (FE) — Q2 2024 Earnings Call Transcript

Thank you. Good morning, everyone, and welcome to FirstEnergy's second 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, Irene. Good morning, everyone. Thank you for joining us today and for your interest in FirstEnergy. Today, I will review our financial performance and highlights for the second quarter as well as our progress executing our business plan. I will also provide updates on recent regulatory and legacy issue developments, discuss trends we are seeing in the industry, and review the value proposition we offer our shareholders. Looking at our second quarter results, GAAP earnings were $0.08 per share in the second quarter of 2024, compared to $0.41 per share last year. We recorded a number of special items that impacted second-quarter GAAP results, which Jon will address in a few minutes. Operating earnings for the quarter were $0.56 per share versus $0.47 per share last year, an increase of 19%. Positively impacting second-quarter operating earnings were rate adjustments and associated investments to better serve our customers. Customer demand was also a positive impact for the quarter, with weather-adjusted residential and commercial sales up 4% and 7%, respectively. These positive impacts were partially offset by higher planned operations and maintenance expenses and expected dilution from the 30% sale of FET. The items driving growth for the quarter point to the expected trend of improving utility earnings quality. Our capital investments to improve the customer experience increased 22% for the first six months of the year. This is reflective of our improved balance sheet that enables our Energized365 capital plan. We are executing well in 2024 and are on track to achieve the goals we've outlined. Today, we are reaffirming our 2024 operating earnings guidance range of $2.61 per share to $2.81 per share. We are reaffirming our 2024 CapEx plan of $4.3 billion versus $3.7 billion in 2023, and we are reaffirming our 6% to 8% long-term annual operating earnings growth rate. June 1st marked my one-year anniversary with FirstEnergy. Our employees have made a significant amount of progress in the last year, positioning the company for success. From an operations standpoint, we have organized FirstEnergy into four new segments, representing our five major businesses. We have restructured the company into a strong operating company model and recruited external and promoted internal executives to lead these businesses. These changes put leadership, responsibility, and decision-making closer to the customer. We are investing in our people by engaging with our unions to enact mid-cycle pay adjustments to help ensure we are paying competitive wages to our representative workforce. We started an effort to hire journey-level line workers to better serve our customers, and we are forming a new apprenticeship program to further support a skilled and well-trained workforce to serve our customers going forward. Regarding capital investment, we initiated our new five-year $26 billion capital investment program, Energize365, to enable the energy transition and improve reliability and the customer experience. Energize365 represents a 44% increase in investment over our previous five-year plan. On the regulatory front, we concluded constructive regulatory engagements in Maryland, New Jersey, and West Virginia, representing 35% of FirstEnergy's rate base. In Ohio, we currently have three traditional rate proceedings in flight. We received a constructive order in May for our ESP V case, but one that left a number of unresolved issues. We have asked for a rehearing on those issues and are seeking to obtain more clarity during this phase. We filed a partial settlement agreement in our Grid Mod II case in April, focused on deploying automated meters for all of our customers. Hearings concluded on this non-controversial issue on July 2, and we are anticipating an order in the fourth quarter. We filed our base rate case in late May, requesting a 10.8% ROE and an average equity ratio of approximately 55%. We will be updating that filing today to reflect changes from the ESP V order and other updates. We expect this case to continue well into 2025. In Pennsylvania, we filed a base rate case in early April, requesting a $502 million rate adjustment including an 11.3% ROE and an equity ratio of 53.8%. As is customary in Pennsylvania, we will engage with intervening parties in an effort to reach a settlement prior to the scheduled hearings in mid-August. New rates are expected to be effective January 1, 2025. Also in Pennsylvania, we filed our long-term Infrastructure Investment Plan 3 on July 22. This five-year plan will result in approximately $1.6 billion in investments to support enhanced reliability. The proposed LTIP 3 is about twice the investment of the prior plan and demonstrates our ability to invest our strong balance sheet for the benefit of our customers. Finally, in New Jersey, we are currently in settlement discussions for the Energize New Jersey plan, which was filed in November and updated in February. This is a $935 million plan designed to upgrade Jersey Central Power & Light Electric Grid infrastructure, using modern technology and smart devices to help reduce the size and duration of outages. We are currently in settlement discussions and hope to reach a constructive outcome. From a financial standpoint, the strides FirstEnergy made over the past year to improve its balance sheet were nothing short of remarkable. On March 25, the company closed its transaction to sell 30% of FET. This was the final transaction of a multiyear $7 billion equity raise that has transformed the future prospects of the company. On July 17, the company received the last $1.2 billion of the $3.5 billion sale. This cash has been used to pay down short- and long-term debt and recapitalize our operating companies. Rating agencies have taken notice, with all three rating FirstEnergy Corp.'s senior unsecured rating as investment grade and S&P and Fitch retaining positive outlooks. Last week, S&P increased FET's senior unsecured rating from BBB- to BBB+ and retained its positive outlook. This two-notch upgrade reflects FET's enhancements in liquidity, governance and cash management practices and places FET's senior unsecured credit rating at or above the rankings of our fully regulated utilities. This significantly strengthened balance sheet represents a major transformation for FirstEnergy, as well as a significant differentiator from many of our peers. It is on the basis of this balance sheet that we were able to introduce Energize365 and make the investments needed to enable the energy transition and improve reliability and the customer experience. Many of our peers still have to raise significant amounts of equity to continue to grow or will have to issue large debt volumes at higher rates. FirstEnergy does not have to do either. The balance sheet component of our transformation is complete. We are now focused on executing our operating and regulatory plans for the benefit of our customers. Turning to Slide 9, let's talk about data centers. We are getting a fair number of load study requests from data center developers across our service area. Large load studies for this type of development have more than doubled from last year. We are fortunate that in much of our service territory, we have excess transmission capacity to serve this and other economic development priorities. This capacity comes from previous manufacturing processing and generating facilities. We are also participating in the PJM open windows related to data center and other load growth. We were successful last year in the Window 3 RTEP solicitation process, and we'll be submitting proposals for the current one. Generation resource adequacy has become a very hot topic over the past year. It appears that load growth and baseload generating retirements could outpace dispatchable generating resource additions. You know in four of our five states, we are wires-only utilities. We are working with customers, states and other interested parties to help ensure there is adequate capacity to meet growing load and enable the energy transition. Finally, regarding potential retail tariff changes, we are reviewing our current tariffs and think there is enough flexibility for us to negotiate terms to serve new loads while maintaining existing customer protections. We need to be able to serve all loads affordably. If we find the need for future tariff adjustments, we will file them on a state-by-state basis. During the second quarter, we made significant progress resolving legacy issues. On July 21st, the U.S. Attorney's Office for the Southern District of Ohio, filed a status report confirming that FirstEnergy successfully completed the obligations required under a three-year period under the deferred prosecution agreement, including remediation measures and the implementation of a compliance and ethics program. As a result, the report requirements related to those obligations have ended. As provided under the DPA, we will continue to fully cooperate with the DOJ on other outstanding matters, and we will continue other reporting obligations. This was an important step as we put the past behind us and move forward as a stronger company with a robust culture of ethics, integrity, and compliance. We have reached an agreement in principle with the SEC staff, subject to the approval of the commission, which would settle the SEC security claims against FirstEnergy. The proposed settlement is based on the fact set forth in the DPA. We have recorded a reserve of $100 million for this settlement. Similarly, we are in the final stages of a resolution with the Ohio Organized Crime Investigations Commission. The resolution is expected to include a non-prosecution agreement based on the facts and the DPA and is expected to resolve the Ohio Attorney General civil case against FirstEnergy. We have recorded a reserve of $19.5 million in anticipation of resolving both Ohio matters. The three docketed cases related to these legacy issues continue to move forward at the PUCO. An audit report is due on August 28 on the political and charitable spending review. Discovery continues and hearings are scheduled for October 9 on the corporate separation review. Discovery is ongoing with a hearing scheduled for February 3 on the Rider DMR/DCR audit. We continue to cooperate in these audits and appreciate that these cases are the appropriate form for a review of this activity and not our business-as-usual rate cases. Let's take a moment to review FirstEnergy's value proposition to shareholders. Our 6% to 8% operating earnings growth rate is predicated on an average annual growth in rate base of 9%. Our ability to invest in our system for the benefit of our customers is enabled by a strong balance sheet. We have the need, opportunity, and means to make the necessary investments to enable the energy transition and improve reliability and the customer experience. FirstEnergy has an attractive low-risk profile that supports solid BBB credit metrics. We are targeting a 14% to 15% FFO-to-debt profile over the horizon and do not anticipate incremental equity needs for our Energize365 investment plan beyond our employee benefit programs. The increase of traditional utility earnings means that our earnings quality has improved, and our customer affordability is expected to remain strong for the foreseeable future. Our long-term annual operating earnings growth rate combined with our dividend represents a total shareholder return proposition of 10% to 12%. We have made significant progress on strengthening our balance sheet, restructuring our business, putting legacy issues behind us, and focusing on our operational, regulatory, and financial plans. The men and women of FirstEnergy are singularly focused on that execution and serving our customers. Before I turn the call over to Jon, I would like to mark two significant management transitions for FirstEnergy. Two executives have recently notified me of their decision to retire after many years of service to the company. Chris Walker, our Chief Human Resources Officer, will be retiring with nearly 39 years of service. I would like to thank Chris personally for all she has done for me over the past year, and also thank her for her many years of dedicated service on behalf of our employees. We owe Chris a debt of gratitude and wish her well in retirement. After more than 40 years of service, Irene Prezelj has decided to retire. Many of you have gotten to know Irene as our Head of Investor Relations and Communications. For many years, Irene has been the face of the company to investors and the public alike. We are grateful to Irene for her leadership and dedication to serving our employees, investors, customers, and the public. We wish her the best going forward. With that, I will turn the call over to Jon.

Thank you, Brian, and good morning, everyone. I also want to extend my sincere gratitude and best wishes to Chris and Irene. They have been great to work with over the years and have always been there for me and the employees of the company. Today, I'll review our financial performance, discuss economic and customer trends, and provide an update on our regulatory and financial initiatives. Let's start by reviewing the larger special items that impacted our second quarter GAAP results. These include increased asset retirement obligations recognized in connection with the planned transfer of a legacy impoundment site to a third party and the impact from the new EPA legacy coal combustion residuals rule. Costs associated with redeeming high-cost debt using the proceeds from the FET transaction, charges connected to the anticipated resolution of the OOCIC and SEC investigations, partially offset by the receipt of insurance proceeds associated with the shareholder derivative lawsuit settlement and regulatory charges resulting from a commitment in the Ohio ESP V order. We continue to see strong execution on our Energize365 capital investment program, solid financial discipline, and a culture of continuous improvement. And because of that, we delivered second-quarter operating earnings of $0.56 per share, which is above the midpoint of our guidance and compares to $0.47 per share for the second quarter of 2023. The results primarily reflect new base rates in our integrated business, strong invested capital across all of our businesses, and formula rate investment programs and significantly higher year-over-year customer demand. Looking at our segment results for the quarter, in our distribution business, operating earnings were $0.22 per share compared to $0.24 per share in the second quarter of last year. This reflects planned increases in operating expenses we discussed previously, partially offset by higher customer demand and rate base growth rate investment programs and a lower customer rate credit in Ohio as part of our 2021 earnings test settlement. In our Integrated segment, operating earnings were $0.21 per share versus $0.12 per share in the second quarter of last year. Results primarily reflect new base rates in Maryland, West Virginia, and New Jersey that went into effect over the past eight months. Rate base growth in distribution and transmission formula rate investment programs and the impact of higher customer demand, partially offset by a higher effective tax rate. Operating earnings in our stand-alone transmission segment were $0.14 per share, compared to $0.18 per share in the second quarter of 2023. Year-over-year rate base increased more than 10% as a result of our transmission investment program, but this was offset by the dilution from the 30% interest sale of FirstEnergy Transmission LLC to Brookfield, which closed in March of this year. Finally, in our Corporate segment, losses were $0.01 per share versus $0.07 per share in the second quarter of 2023. This improvement is the result of ongoing lower financing costs from the redemption of high-cost debt. More detail on our second-quarter and year-to-date results can be found in the strategic and financial highlights document we posted to our IR website yesterday afternoon. Looking ahead, we are providing guidance of $0.85 to $0.95 per share for the third quarter, which reflects the continued impacts of new base rates in our integrated business, continued rate base growth, and higher customer demand, partially offset by a lower planned earnings contribution from Signal Peak. And as Brian mentioned earlier, we are reaffirming our 2024 guidance of $2.61 to $2.81 per share, as well as our long-term 6% to 8% annual operating earnings growth rate. In his remarks, Brian shared a look at the trends related to data center growth in our service territory. I want to expand on that by taking a quick look at some of the broader economic and load activity in our region. Recent trends over the past year are positive in our region, including GDP that has averaged just over 2% for the past year, and employment growth of just under 1.5% over the past 12 months. And from a customer demand perspective, we're seeing positive weather-adjusted customer demand of 1% over the last 12 months, primarily resulting from increases of 1.3% in the commercial and 1.1% in the industrial customer classes, with demand in the auto and services sectors, up 14% and 7%, respectively. And so we believe we're in a great position to serve our customers and our investment program will adjust as needed to ensure capacity and reliable service. From a financing plan perspective, earlier this month, we received the remaining $1.2 billion in proceeds from the $3.5 billion, 30% FET interest sale to Brookfield. You'll recall that we received the initial proceeds of $2.3 billion when the transaction closed in March, the remaining $1.2 billion in interest-bearing notes that were extinguished with Brookfield's final payment on July 17. We're deploying those proceeds in a credit-accretive manner, consistent with our plan to further transform our balance sheet and support our Energize365 grid investment program. As we've discussed, the sale completes a series of transactions over the last two and a half years that resulted in nearly $7 billion in equity capital at an equivalent share price of $87 a share or 36 times trailing PE multiple. In total, these proceeds were used for over $3 billion in high-cost debt reductions at FE Corp, including the remaining $460 million of the 2031 bonds in the second quarter, nearly $2 billion in utility long-term debt redemptions, and $2 billion to pay off short-term debt that would have otherwise been financed with long-term debt at our utilities. Following the closing of this transaction in March, our corporate credit rating was upgraded by Moody's and S&P, restoring it to investment grade at all three rating agencies. The credit ratings at our subsidiaries were also upgraded, and this momentum continued last week as S&P further upgraded FET and its subsidiaries. Going forward, our focus is on continued execution of our plan, achieving cross-supportive regulatory outcomes, moving past legacy issues, and financing our robust investment plan in a credit-supportive manner, consistent with a BBB flat credit profile. Additionally, earlier this month, we launched a request for proposal for a second pension lift-out transaction to eliminate the remaining $700 million in non-regulated pension liability. This transaction, if successful, would eliminate all non-regulated pension liability, further reduce pension volatility and improve the quality of earnings of the company. Recall that in December of last year, we executed the first pension lift-out transaction, removing approximately $720 million of pension liability at $0.95 on the dollar. Turning now to recent regulatory activity. In Ohio, we filed our base rate review on May 31, requesting a $94 million rate adjustment on a rate base of $4.3 billion, a 10.8% proposed return on equity, and a 55% equity capitalization ratio based on a 2024 test year. The rate adjustment supports recovery investments in the distribution system and customer experience enhancements while keeping rates affordable for customers. The case includes recovery of investments in Riders DCR and AMI, which includes the Grid Mod I capital investments in base rates and resetting those riders to zero. It also includes a request to change the recovery of pension costs from service cost only to total pension costs, including previously incurred actuarial losses as well as a request for a pension tracking mechanism to avoid volatility in the future. It also includes recovery of other costs previously incurred, including the major storm restoration costs and a program to convert street lights to LEDs. Today, the Ohio companies will file an update to the base rate case review filing with an updated rate request. The update is necessary to include the impacts addressed in the May 15 ESP V order and to update 2024 test year financial information through May 31 to reflect actual operating results. Our initial request represents an estimated overall bill impact for typical residential customers ranging from a rate decrease of 1.3% in Toledo Edison to a 3.5% increase in CEI, or an average increase of 1.4% across Ohio. Also in Ohio, on May 15, the PUCO issued an order approving our ESP V with modifications, which became effective June 1. The order extended Rider DCR through the conclusion of the base rate case but excluded certain investments from recovery in Rider DCR. The order also provided for recovery of vegetation management expenses for the first two years of the ESP and prospective deferral of major storm expenses. While we appreciate the support for key terms of our ESP V in the near-term, the order did not provide clarity regarding these key terms of the ESP for the entire five-year period, with many directed to the base rate case for resolution. We subsequently filed an application for rehearing seeking greater certainty regarding key terms, as well as proposed modifications, which included shortening the ESP V term to three years, providing full recovery of investments in the DCR through the conclusion of the base rate case and other proposals that preserve the economic value of the order for customers. Earlier this month, the PUCO granted the applications for rehearing filed by all parties for the purposes of further consideration. This step gives the PUCO more time to make its final decision; there’s no statutory deadline for the decision. The summer hearings were held in our Ohio Grid Mod II settlement, and we anticipate an order during the fourth quarter. In Pennsylvania, earlier this month, we filed the third phase of our long-term infrastructure improvement plan known as LTIP III, which is part of our Energize365 investment program. LTIP III includes a total projected investment of $1.6 billion over five years, building on the projects completed in LTIP I and LTIP II. The third phase of the program supplements reliability investments and includes both grid modernization and system resiliency projects. This includes targeted investments to accelerate infrastructure improvements and help enhance service reliability for more than two million customers in the state while remaining focused on affordability. Investments are recovered through a distribution system improvement charge, or DISC, based on actual capital structure and the benchmark ROE, which is currently 9.8%. The cumulative average residential customer rate impact recovered through DISC is $2.88, or a 2% increase. Pending PUCO approval, we expect capital deployment to begin in the first quarter of 2025, with DISC revenues estimated to begin in the second quarter of 2026. Also in Pennsylvania, in mid-August, hearings will begin in our base rate review filed in April. As we discussed on quarter's call, this is a request for a $502 million rate adjustment on a rate base of $7.2 billion, with an 11.3% proposed return on equity and a 53.8% equity capitalization ratio. The review builds on our service liability enhancements in Pennsylvania with additional investments in a smart, modern electric grid and customer-focused programs, while keeping rates comparable to other utilities in the state. Key components include implementing a 10-year enhanced vegetation management program to reduce tree-caused outages, reduce outage restoration time, and reduce future maintenance costs; recovery of costs associated with major storms, COVID-19, and LED street light conversions; changing pension recovery from average cash contributions to traditional pension expense, including previously recognized actuarial losses. The review also includes a blended federal statutory tax rate of approximately 27%, but also continues to provide customer savings from previous legislative changes to federal and state tax rates. Additionally, the application proposes a pension OPEB normalization mechanism to track and defer differences between actual and test year expense to reduce volatility from the pension. And as Brian mentioned, we are engaging with the intervening parties in an effort to reach a settlement prior to the scheduled hearings in mid-August. Finally, in addition to the settlement discussions on our Energize New Jersey infrastructure improvement proposal, we are also engaged in settlement discussions for our New Jersey Energy Efficiency and Conservation Plan. This plan, which was filed with the BPU in December 2023, covers the period from January 1, 2025, through June 30, 2027, with a proposed budget of approximately $964 million. It consists of a portfolio of programs addressing energy efficiency, peak demand reduction, and building decarbonization with recovery of lost revenues and provides a return on the investments. The BPU suspended the procedural schedule on July 1 in light of these settlement discussions. A final BPU decision and order is required no later than October 15 of this year. So, we're making good progress in 2024; we're executing well. We have a strong strategy and opportunities to continue our positive momentum and growth. Thank you for your time today, and I'll open the call to your questions.

Hey guys. Good morning.

Good morning, Shar.

Good morning, Brian. Just a couple of quick ones here. Brian, just on the growth numbers out there, obviously, you're highlighting the opportunities around data centers and kind of large energy-intensive consumers, you have transmission capacity to take on the load, but you still have this kind of 1% load growth figure out there. A lot of your peers have been raising expectations, some are quantifying the impact. I guess, what's holding back? And how and when are you thinking about updating investors around potential upside there? Thanks.

Thank you for that, Shar. We're going through our evaluation of our future load growth rate right now. Look, we're seeing some things that are positive from the data center side. Some of those are still a few years out. We're seeing some positive impacts from the adoption of EVs in places like Maryland and New Jersey. But overall, we're still seeing modest, steady load growth and not a knockout of the park at this point. There's been so much talk about data centers, Shar. And when we look at it, even if we get the load growth, they're generally taking service at a transmission level, which isn't as earnings impactful. Today, it could be rate impactful in a positive way to our existing customers as we spread some of that existing capacity over more units. But the real opportunity for us around data centers has been around things like the PJM Open Window 3, where we were awarded about $800 million worth of opportunity to invest in the transmission system to serve some of that data center load in that Northern Virginia, Panhandle, Maryland area. So that's where we've seen more impact from the data centers, but more to be seen, and I anticipate probably around EEI, we'll be able to update you on the load growth.

Okay. Perfect. And then lastly, and maybe somewhat related. It's been noise around sort of co-located nuclear data center deals in PJM. I mean, some of your current states like in Pennsylvania and Ohio could see similar deals like we saw with Susquehanna and AWS. I guess, why haven't you filed at FERC around the Susquehanna ISA docket when most of your peers have? And what's your stance on the current complaint out there? Thanks.

Yes. So thank you for that question. Look, I think those are things that FERC will figure out in time. It's not as business impactful to us at this point, given our service territory and where we are. And I'm interested in what FERC has to say about that. I'm not sure what their tools are to be able to block something like that, what their view is on whether or not it takes net capacity out of the market and what that would do for existing customers. We just saw some pretty high prints on the PJM capacity auction yesterday. I think people are looking to that mechanism to solve generation resource adequacy. I'm not sure it really does, right? That's one print in that auction that happened yesterday. There was virtually no new generating capacity was offered and I don't think that a one-year print or a two-year print or a three-year print is going to solve that problem and attract significant increased investment into the PJM region. So something we need to figure out. It's important for our customers. We're actively engaged in that discussion. But I don't think the PJM auction is the place where that issue is going to be solved.

Got it, Brian. And just a quick follow-up on that. Are you referring to potentially owning a certain amount of peaking assets and rates? Is that what the discussions are?

So the issue is how could we help that happen. And in certain of our states today, we're not allowed to own capacity. In West Virginia, we do; in Maryland, under certain circumstances we could; in Ohio, under certain circumstances we could. But in other states, we'd have to have legal challenges to allow that to happen. And if our states were to come to us and say, we would like you to invest in some form of dispatchable generation for the life of the asset at a regulated return. Those are things that we think would benefit our customers. If other people aren't adding capacity, and today, they're not. And those are discussions that we think would be constructive on behalf of our customers.

Okay. Perfect. Fantastic. Guys, we will see you soon. Thank you again.

Thanks, Shar.

Yeah. Hi. Good morning. First, I don't know if Irene started working there when she was 10 years old, but congrats to Irene on 40 years and her retirement. I guess, first question, just on Pennsylvania, you mentioned you're getting close to settlement actions there. Just any sense yet on kind of the likelihood that you might be able to reach a settlement in Pennsylvania?

So thanks for that, Steve. Those talks are in early discussions. And we would always like to reach a settlement and present that to the commission, but I'd say early stages at this point, and we're optimistic that we'll be able to get something done hopefully before the hearings in August.

Okay. Regarding Ohio and the ESP V, it seems that the advantage of keeping the period shorter is that you’ll spend less time working with an ESP under this limited definition. Is your goal to achieve a clearer understanding of some of the clauses over the duration of the ESP?

Here's what happened, the commission punted some key aspects of ESP V to the base rate case. And so it's hard for us to accept a five-year plan when there's uncertainty beyond the current rate case. And so if we were to time those things up a little better, and get more certainty on it, it's easier for us to accept an ESP V over a five-year term with more certainty. It's really hard for us to know what's going to happen to certain of those items that got punted after we get resolution of the base rate case.

Got it. That's right. And then obviously, it's your decision whether to accept an ESP or not. So that's part of the…

Yes. That's correct.

Got it. Okay. I know you mentioned that you are, I guess, far enough on some of the Ohio issues to take a reserve on those this quarter. Just maybe you could just talk to and then resolving the DPA 2 period. So just could you maybe just talk to kind of your overall take on the environment there and how FirstEnergy is viewed these days?

Yeah. So thank you for that, Steve. Look, we've worked very, very hard to take responsibility for what happened in the past, make any payments and penalties that we need to move on beyond that. The thing that was very positive this quarter was in three of those issues, we made some real significant progress. First, there was the filing by the US Attorney's Office for the Southern District of Ohio recognizing that the three-year term of the DPA had ended and that we've been fully compliant with the requirements during that term. Second, we were able to make progress on the OOCIC and we were able to take a reserve for the amount that we think will be required to put that behind us. And then third, we were able to make progress achieving an agreement in principle subject to commission approval with the SEC. So across all fronts, we're making real progress on putting those legacy issues behind us and focusing on the future. And I think it's being well received in all of those venues.

Great. Thank you.

Thank you, Steve.

Hi, good morning.

Good morning, Jeremy.

Just wanted to follow up a little bit more on some of the earlier points on power prices here. And given the rise in both capacity and energy prices, just wondering how you think about this impacts customers bill headroom there. And just, do you see any potential efforts out there to kind of curb this? Could you share any thoughts on potential for state legislation to support new generation, state to form a strategic reserve, multiple VIUs coming together for a larger consolidated IRP, greater FRR use? Or just in general, do you see anything happening to stem higher prices?

Jeremy, you used just about every acronym we have in the industry in that question. That was amazing. Here are some of the things that we're doing right now, right? It was late-breaking news yesterday afternoon. So we're going by a jurisdiction-by-jurisdiction analysis of the impact of a couple of things. One is the higher capacity print that we saw yesterday. But we also still have some energy prices in there that are reflective of the Ukrainian impact on gas prices and electricity in the United States, and some of those are rolling off, at the same time, those higher capacity prices will be rolling in. So we're trying to determine right now on a jurisdiction-by-jurisdiction basis, how that will happen and what the impact to our customers will be. In West Virginia, we think the impact will be kind of a wash. We have about the amount of capacity that our West Virginia customers need and buying and selling at those amounts; we don't expect there to be a significant impact in the state of West Virginia. As we look forward to the other states, we have what I would say are among the most progressive energy policy states in the country and among the most traditional as well. So I think West Virginia has traditionally been responsive to being pro-coal, but also all of the above. We've added some solar there recently. And I'd like to see if in our next IRP, we might be able to add some combined cycle gas in West Virginia in addition to that. And then in some of the other states where we're wires-only, we're open to any construct that would allow us to invest in capacity on something that looks like a regulated basis. So, if we were to have in Pennsylvania and Ohio, something that looked like NYSERDA or NYPA, where a state agency could buy at long-term capacity that they might hold an auction for that any competitive generators, regulated generators could offer into that, those auctions. If it looked like a regulated basis and we could offer at a price that would allow us something that looked like a regulated return and allow us to recover on a pass-through basis, fuel and energy, those are things that we'd be willing to do. The thing we wouldn't be willing to do would be to start competitive generation of our own. That's something that we've recently come out of. We paid a heavy price for that. We've rebuilt our balance sheet in the wake of that, and that's not a place that we're going to be going back to. But other opportunities that could benefit our customers and have the capacity that they need are all things that are on the table and are all things we're talking to our states about.

Got it. That's clear. Competitive generation: been there, done that. Just wanted to pivot a bit here, a smaller question. Just wondering if you could speak to the size of cost savings that you guys are expecting with some of the facility optimization moves you're making, shrinking, changing location, just where those initiatives stand today? And what can we expect for timing impact of that and other kind of cost-saving initiatives on radar?

Hi, Jeremy, it's Jon. I think we'll see some savings associated with, for instance, getting out of the general office headquarters here in Akron moving over to an owned building. But those savings, I would say, are fairly minimal in the grand scheme of things. Where we're really trying to focus our efforts on continuous improvement and taking costs out of the business is really around our productivity of the workforce, investing in infrastructure and data and technology that will help us drive better decision-making, faster decision-making. And we have some pretty aggressive targets on productivity of our workforce, so we can make sure that we get contractors off the property that we do our work ourselves. That's where the bulk of the savings are coming from. And, in fact, if you look over the last couple of years, we've done a pretty nice job of taking costs out with about $200 million of cost savings in 2023. About $100 million of that was sustainable, and we're targeting $70 million of cost savings this year. So we'll continue to do what we can to offset inflation going forward, and that's part of our plan.

Got it. That's very helpful. I forgot to mention with my earlier question, as far as offshore wind is concerned, is that anything that on your radar at all or really just kind of the transmission side? I just wanted to check on that.

I'll tell you what our favorite part of offshore wind is, it's the on-land part. And we are investing a significant amount of money to shore up the transmission system in New Jersey to enable their initiatives to have significant offshore wind commission in our service territory, and we're making hundreds of millions of dollars of investments to enable that, and that's the part of offshore wind that we want to participate in.

Understood. Appreciate it. Thank you.

Thanks, Jeremy.

Hey, good morning. Thanks for taking my questions. I know a lot of talk on PJM. Just I wanted to follow up on that, Brian, I know you said that one print is not a signal, but we'll have another one in December. And my guess is that not much changes just given the lead times to build this generation. And I guess my question is, is there a tipping point if this is kind of truly a step change in the environment, is there any need to reevaluate how you deploy capital? Or are you being very comfortable where you are right now? Thanks.

Look, thank you for the question, Nick. Look, I think it's interesting. I'd call yesterday's print the canary in the coal mine and the canary didn't make it. If you look at what's happened with the IPP prices over the course of the year, they are all anticipating higher prices in the years going forward. If you look at the amount of new generation that cleared in the auction yesterday, according to PJM's auction report, it was like 100 megawatts, so essentially nil. Same in the auction prior to that it was about 300 megawatts, again, not the right amount. If people were to respond to yesterday's print and say, yes, I think it's a good idea to invest in baseload dispatchable generation in PJM, it would be six years before that capacity would come online. The reality is that we can increase load and build data centers almost immediately, and it takes years of planning, permitting, and procurement and construction to build a power plant. So I think it's indicative of the future, but it certainly doesn't solve the problem. So what we're going to do is what we need to do is enable the energy transmission you need; a robust grid to be able to do that. PJM keeps opening these open windows. There's a current one open that we will be submitting proposals to. We just had significant action that we won in the last one, and we'll continue to do that. And we're going to engage in the discussion constructively with our states, regulators, and customers to see if there's a way that we could deploy our balance sheet capacity for generation that looked regulated to us and our investors. But that's how we're viewing the lay of the land right now. I don't have the silver bullet that's the solution that will solve this tomorrow or in two years or in three years, but we're engaged in that discussion. I just don't think the PJM construct is going to fix the issue even if it sends some positive price signals.

I really appreciate your thoughts on all that. And then you brought up the balance sheet capacity. And one thing that we've noticed is, obviously, you've done a great job derisking the balance sheet this year. You're really not relying much on capital markets this year either. And I know you kind of are working towards another update maybe in the fall or later in the year. Just as you roll forward, presumably the CapEx plan is pressure higher? And how are you kind of thinking about financing that? Is this a plan that continues to have sizable balance sheet capacity where we see no equity on a roll forward? Thank you.

Hey, Nick, this is Jon. So we'll work through that as we do our long-term plan and update the investment community in the springtime or wintertime of next year. I would tell you, listen, we got to balance a couple of different things. We want to be at a BBB flat credit rating with rating agencies; we're not there yet. If you look at where their thresholds are versus where our planned targets are, we do have some balance sheet capacity, I would say 4% of the CapEx program is probably in the right neighborhood. But there are going to be a lot of puts and takes as we think about the capital plan over the next five to ten years that we'll have to consider. Is it base capital that you'll have regulatory lag? Or is it formula rate transmission capital? Those are all things that are going to go into the mix. But we do have some balance sheet capacity, but I would probably peg it at less than 5% of the CapEx program.

That’s very helpful. Appreciate that. Have a great day.

Thanks, Nick.

Hey, good morning. Thanks so much for taking my question. Just like to quickly go back to the load growth piece. Strong prints across both commercial and residential customer classes this quarter. Could you just talk a little bit about what's driving that and kind of how you see that evolving going forward?

Yeah, Carly, let me start with residential. I mean, we're just generally seeing at least this quarter higher average usage per customer across all of our jurisdictions, especially in areas like New Jersey and Maryland, which have a much more progressive energy policy with respect to electrification of vehicles or other industries. We also continue to see higher customer growth in Maryland, given some of the economic activity that we're seeing in that part of our service territory. So that's really what's driving the residential growth for the quarter. If you look at commercial and commercial for us, it's kind of our small- and medium-sized businesses. This is a customer class that took a pretty hard hit after the COVID pandemic. We saw a pretty significant drop-off. And now we're starting to see some of that rebound. And if you look at the last four quarters, three of the four have been higher quarter-over-quarter, and it's getting closer to what I would call pre-pandemic level usage. So those are really what are the drivers for the residential and commercial prints for the quarter.

Great. Appreciate that. I'll leave it there. Thank you.

Thank you, Carly.

Hi. Good morning. Thanks for taking my question. So in the Ohio rate case, obviously, it's early on, but just wondering if you see an opportunity for ultimately reaching a settlement there. You reached a partial settlement in Grid Mod this year, a settlement with the House Rule 6 refunds credits a few years ago. Now you're resolving some of the legacy issues in the state. But that being said, ESP V, there are some issues with that. So just wondering what your thoughts are about ultimately settling there.

Michael, it's always our desire to reach a settlement in any of these rate cases. This one is something that I think is very much at its early stages. We'll be filing our update to the rate case filing later today. And then, of course, we'll be engaging with interveners and other interested parties as we work our way through the balance of 2024 and well into 2025. So yes, always want to reach a settlement, always open to that, and always striving to do that in any case that we find.

Got it. Great. And then secondly for me, obviously, the big CapEx increase earlier this year, the 44%, an expectation is that you'll file more regular rate cases. Obviously, you have the two big ones going on in Ohio and Pennsylvania right now, and you recently reached settlement in your other states. Just wondering how we should think about the jurisdictions and timings of your next rate cases.

Yes. So thank you for that as well, Mike. Look, I have the belief that a well-run and growing utility should be going in for regular rate cases. We have a strong balance sheet. We have Energize365, the CapEx plan we're pursuing. By the way, we have a significant amount of our capital covered under riders and trackers. But I think a very regular interaction with our regulators is something that we should be doing regularly. So I think in most jurisdictions, we should be going in every two to three years at the max and updating rates, clearing out trackers and riders, getting them reflected in base rates and then moving forward with those again. So I just think it's a hallmark of a growing utility that you should be regularly engaging with your regulators.

Great. Thanks for taking my questions.

Thank you, Michael.

Hey, good morning.

Good morning, Paul.

I wanted to congratulate Irene first of all. Many of my questions have been addressed, but I’d like to revisit the idea of regulated or central procurement that you mentioned. Which jurisdictions in your distribution-only service areas do you believe might be more open to that concept? Although some of these logical issues may seem straightforward, there can be differences in receptiveness among them. Do you have any thoughts on which areas might be more amenable to that idea?

Yes. So, Paul, you asked a politically fraught question. Look, I think the real need here in the near term is for baseload dispatchable generation. And we are ready, willing, and able to engage in all of our jurisdictions for anyone who would like to add that on a regulated type basis. West Virginia has really said to us that coal is important to them, but everything should be in the tool bag in West Virginia. We're willing to engage with them on that basis. Maryland and Ohio, under certain circumstances, we could add generation there, and Pennsylvania would take a legislative change. So, we are open to all. And if they're open to us, we'd be willing to engage on that regulated type basis. And again, there are people that get upset and say, 'You're going back to regulation.' I don't think you have to go back to regulation. I think you can still have energy markets. I think you can still have retail choice where you have it today. But I also think you could have constructs like NYSERDA or NYPA where they could buy on behalf of the state's residents. And that doesn't have to be an end to competition. And they can even have auctions where all people could participate in that, utilities, independent power producers, and others. So for the people that say it has to be one or the other, I just don't think that's a valid premise.

Great. Thanks a lot. Have a great one.

Thank you, Paul. Appreciate it.

Hi, good morning. I want to also congratulate Irene on an incredible career and Chris, I don't know you, but looking at the number of new leaders who joined FE in the last year, I think you certainly deserve congratulations as well.

Thank you for that. I'll pass that on.

I have a few quick questions about the balance sheet. I understand you're aiming for a 14% to 15% FFO-to-debt ratio, in line with previous guidance. Are you still on track to meet that by the end of the year? What does that metric look like as of June 30th after the FET proceeds? Additionally, I see you're still indicating a need for up to $100 million in equity each year, and you've allocated $120 million in reserves. If those reserves turn into cash outflows, would that necessitate additional equity as a one-time event, or could you manage it without seeking more equity? I know the timing is uncertain, but I would appreciate your thoughts on this.

Yes, Andrew, this is Jon. We have seen significant improvements in our metrics, with nearly 200 basis points of improvement based on the trailing June 30 numbers, largely driven by higher FFO. Our debt levels are approximately $2 billion lower than they were at the same time last year. I believe we may face some challenges this year in reaching the 14% target, primarily due to the SEC and OOCIC accrual. Excluding those factors, we would be much closer to the 14%. However, in the longer term, we expect to achieve a range of 14% to 15%.

Okay. Does that mean by next year? Or will it...

It would be next year. So sometime like in probably the first, second, or third quarters of next year on a trailing basis, we would probably get to that 14% level.

Okay. Great. Thank you. And then just a quick follow-up. Remind me, if you were to do a pension lift-out, would that be cash or non-cash?

Well, it would be funded through the pension plan. It would be non-cash to the company, but the pension plan would have to fund it, which would use the investments that it has on hand to fund that.

Right. Okay. But it wouldn't require external financing.

No, no, no, that's right. If you think about what we did in December, eliminated a $720 million liability by paying $0.95 on the dollar through the pension plan. So, no external financing to the company.

Okay. Very good. Thank you so much.

Thank you, Andrew.

Yes. Thank you and thank you, Irene. I appreciate it. Just a couple of timing questions. Just on the potential construct of a NYSERDA-type agency. What is the earliest do you think something like that could get started in any of your states? And then just on Grid Mod II, I know you've got the partial settlement there. What's your thinking on sort of the timing to get that done? What has to be done there?

So let me take Grid Mod II first, Greg. Would anticipate an order in the fourth quarter of this year on the settlement that we proposed. So hope to get that done, like I said, this year, and we could start making those investments right away in the AMI. On the NYSERDA, it would require legislative changes in all of our jurisdictions to make that happen. And then they would have to have a process where they would run an auction to do that. So, I'd say it's not a short-term process. It would require legislation changes and then activation of that new entity to do what it needs to do on behalf of its customers. So on behalf of the residents of the state rather than customers. The important thing about that is it could be a structural change that could be a path forward rather than an auction-to-auction, 'Do I build, don't build?' There would actually be a structure for how the state would procure its incremental needs that could survive auctions, administrations, and the like, and it could be truly sustainable. And I think we need a sustainable solution here, even if it's not a short-term fix.

Thank you.

Thank you, Gregg.

Hey, thanks for squeezing me in. Just one quick one, Brian. You talked about the PJM contract maybe it's not going to struggle to attract new generation, canary in a coal mine, all this. Do you think as we're in this period, while they're trying to figure out how to incentivize new generation, that could delay the economic growth or stall the economic growth or load that you should see in the region?

I don't think so, Anthony. Obviously, we have the capacity to use still. I think we're still serving capacity. We're still adding load; we still have transmission capacity to serve people. I think long-term it could be a problem for economic development and load growth, and I think that's why we need to solve it. So it's not happening now; it could happen going forward. And I think on a regional and statewide basis, that's why we need to think about this. We can't cede our competitiveness to other regions because we don't have the energy to serve them. And it's our job to make sure that doesn't happen.

Great. Thanks for taking my questions.

Thank you, Anthony.