Public Service Enterprise Group Incorporated (PEG) Q2 2026 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by. My name is Rob, and I'm your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group's Second Quarter 2026 Earnings Conference Call and Webcast. [Operator Instructions] As a reminder, this conference is being recorded today, August 4, 2026, and will be available for replay as an audio webcast on the PSEG's Investor Relations website at https://investor.pseg.com. I would now like to turn the conference over to Carlotta Chan. Please go ahead.

Good morning, and welcome to PSEG's Second Quarter 2026 Earnings Presentation. On today's call are Ralph LaRossa, Chair, President, and CEO; and Dan Cregg, Executive Vice President and CFO. The press release, attachments, and slides for today's discussion are posted on our IR website at investor.pseg.com, and our 10-Q will be filed later today. PSEG's earnings release and other matters discussed during today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. We will also discuss non-GAAP operating earnings, which differs from net income or loss, as reported in accordance with generally accepted accounting principles or GAAP in the United States. We include reconciliations of our non-GAAP financial measures and a disclaimer regarding forward-looking statements on our IR website and in today's materials. Following our prepared remarks, we will conduct a 30-minute question-and-answer session. I will now turn the call over to Ralph LaRossa.

Thank you, Carlotta, and thank you for joining us to review PSEG's second quarter 2026 results. Starting with our financial results, PSEG reported net income of $0.67 per share and non-GAAP operating earnings of $0.86 per share, bringing our first-half results to $2.15 per share of net income and $2.41 per share of non-GAAP operating earnings. Our ongoing investments in PSE&G system replacement, reliability and energy efficiency were the main drivers of growth in our financial results in the second quarter. And at PSEG Power, an increase in realized market prices, higher nuclear generation and gas operations, more than offset the absence of the Zero Emission Certificate programs that concluded in May of 2025. With results for the first half of 2026 coming in as expected, we are pleased to reaffirm our full-year non-GAAP operating earnings guidance in the range of $4.28 to $4.40 per share. Now our operational results may have even been better as we successfully managed one of the most challenging storm restorations in our company's history. Over the July 4 holiday weekend, a series of heat waves and successive thunderstorms hit our service area, accompanied by winds of over 70 miles per hour. PSE&G reconnected approximately 380,000 customers, with nearly all customers restored within 24 hours of losing power, demonstrating the value of our system reliability investments and our crews' steadfast commitment to our customers. PSE&G's round-the-clock restoration efforts were led by over 330 crews and were supported by over 10 million proactive customer communications. In addition to thanking our employees who participated in the storm response, I also want to highlight that we worked this multi-day restoration effort with an excellent safety record and provided PSE&G crews to help our neighboring utilities with their restorations. We support and welcome the upcoming review of our storm response by the New Jersey Board of Public Utilities, and we will be submitting a comprehensive post-event performance report to them tomorrow, August 5. During the heat wave, PSE&G reached a peak summer load of 10,446 megawatts, the highest level in 14 years, and activated demand response, part of our Clean Energy Future programs, during three separate events in early July, helping to keep peak energy costs down for customers. Our Clean Energy Future programs now generate more than $1 billion in annual customer savings, helping nearly 525,000 residential and business customers save energy and lower utility bills since we began the CEF-EE program back in October of 2020. Our EE investments have also supported approximately 9,300 jobs statewide over the past 6 years, including a network of more than 1,000 trade and union allies. We are proud of our strong performance to date in this program, including the success of our job programs, including the use of union labor for this work. We expect to file our proposal to implement the BPU's recently adopted framework for a one-year extension of the EE2 Triennium by September 30. And more good news for customers: This month, we are implementing residential bill credits consistent with Executive Order 1 and continuing the 12-month scheduled refund of approximately $166 million of the Zero Emission Certificate that started back in June. PSE&G has also filed with the BPU to lower residential gas bills by more than 5% beginning October 1, continuing to benefit our customers with the lowest gas utility bills in New Jersey and the region. We are also pleased to mention that PJM made a filing at FERC in June to implement a favorable prospective change to transmission cost allocation rules effective June 1, 2026. Based on public data from PJM, this prospective change will result in approximately $33 million benefit to our zonal transmission customers for the period running from June 1 through year-end 2026, with an expected prospective annual benefit of approximately $65 million. This is another example of how we continue to advocate on behalf of our customers. Since Governor Sherrill's inauguration, her administration has been focused on New Jersey affordability. The governor's first executive order directed the BPU to study modernizing the electric utility business model. And last month, the BPU released its consultant report, which also marked the conclusion of Phase 1 of this directive. While no formal recommendation was issued, several examples of promising regulatory frameworks from other states and multiple reforms were highlighted. These included multiyear rate plans, performance-based rates, performance incentive metrics, earnings sharing mechanisms, decoupling, and shared saving mechanisms, all of which can further alignment and transparency between the utility business model, state energy policy goals, and affordability in the state. The BPU will now proceed to Phase 2 of this effort, which is expected to focus on cost discipline, financing modernization, targeting incentives and shared savings, and stage performance-based ratemaking. PSE&G will fully participate in this proceeding, and we expect to file comments by September 18. We are encouraged by the report's balanced assessment of the extent to which the business model changes can address affordability, as well as the report highlighting the value of utilizing multiple criteria in its decision-making. As we prepare for these upcoming stakeholder proceedings, combined with the growing regulatory lag that comes from our historical test year and our robust capital program -- we believe there is an opportunity to bridge Governor Sherrill's call for greater accountability and transparency with our regulatory requirement to recover prudently invested capital and update our cost of service. PSE&G's last base rate case, settled in October of 2024, established a requirement to file our next base case no later than 2029. However, we have stated before that we could file sooner if conditions warranted. When you consider that we have added a significant amount of distribution rate base at a time when there have been fewer infrastructure investment programs, the alternative is more frequent base rate cases. As a result, PSE&G currently anticipates filing by year-end 2026 to update base rates. Now turning to PSEG Power. PSEG Nuclear also performed well during the quarter, supplying the grid with 7.8 terawatt-hours of carbon-free, 24/7 baseload generation and achieving a capacity factor of 92% that included the second consecutive breaker-to-breaker run at Salem Unit 2. As widely expected, PJM's latest capacity auction priced at $325 per megawatt-day, the upper end of the price collar, and fell 6.8 gigawatts short of PJM's targeted reliability requirement. This collar will remain in place during the upcoming December 2026 auction, covering capacity pricing into mid-2030. The uncapped price in the latest auction would have been $555 per megawatt-day, but the reserve margin still falls well below PJM's reliability requirement. We are continuing to review PJM's recent filings detailing the reliability backstop procurement and IRAS rules, the Interim Resource Adequacy Service, formerly known as Connect and Manage, including PJM's Friday submission to FERC. As part of the bilateral phase of PJM's RBP, PSEG Power recently submitted several project proposals throughout the region that may qualify as new dispatchable generation that could be paired with new large loads through bilateral contracts. Turning to long-term resource adequacy here in New Jersey, Governor Sherrill recently signed the Power New Jersey Act into law, establishing a new nuclear procurement process at the BPU to procure at least 1,100 megawatts through a state-backed program. As the only operator of existing nuclear generating facilities in New Jersey, PSEG Nuclear has been engaging in efforts to enable new nuclear development at our site in Salem County since 2016, when we obtained an Early Site Permit from the U.S. Nuclear Regulatory Commission, 1 of only 6 currently issued in the United States. We believe that new nuclear generation represents a compelling long-term solution to address New Jersey's growing resource adequacy needs and support economic development in South Jersey, and a successful framework for new nuclear will require an appropriate allocation of project risk. At the same time, PSEG Power is continuing discussions with interested parties that see value in our existing nuclear production, future nuclear upgrades and other generation opportunities. In summary, our teams delivered solid financial and operational results for the second quarter and first half of 2026, enabling us to maintain PSEG's full year 2026 non-GAAP operating earnings guidance. We are also reaffirming PSEG's 5-year non-GAAP operating earnings growth outlook of 6% to 8% through 2030 as we continue to pursue opportunities incremental to our long-term forecast, including the potential to contract our nuclear output under multiyear agreements. Importantly, our solid balance sheet enables the funding of PSEG's total 5-year capital investment program of $24 billion to $28 billion without the need to issue new equity or sell assets and provides the opportunity for consistent and sustainable dividend growth. I'll now turn the call over to Dan, who will review the quarter's results and then rejoin the call for the Q&A session.

Great. Thank you, Ralph, and good morning, everybody. PSEG reported net income of $0.67 per share for the second quarter of 2026 compared to $1.17 per share in 2025, and non-GAAP operating earnings were $0.86 per share in the second quarter of 2026 compared to $0.77 per share in 2025. These quarterly results bring first-half 2026 net income to $2.15 per share and non-GAAP operating earnings to $2.41 per share. We've provided you with information on Slides 8 and 10 regarding the contribution to net income and non-GAAP operating earnings by business for the second quarter and first half of 2026. Slides 9 and 11 contain waterfall charts that take you through the net changes for the quarter and year-to-date periods over the prior year in non-GAAP operating earnings per share, also by major business. Starting with PSE&G, which reported second quarter net income and non-GAAP operating earnings of $342 million for 2026 compared to $332 million in 2025. The utility's results were driven by ongoing investment in our energy efficiency and gas system modernization programs. Referring to the waterfall on Slide 9. Transmission margin was flat compared to the year-ago quarter as higher investment was offset by a prior-year true-up and our distribution margin increased by $0.05 per share compared to the year ago period, largely reflecting incremental gas margin from GSMP II extension roll-ins and higher investment in energy efficiency. Compared to the second quarter of 2025, distribution O&M expense was up by $0.01 per share, reflecting an increase in operational costs due to inflation, and depreciation and interest expense each rose by $0.01 per share due to ongoing capital investments and higher long-term interest rates. And utility taxes and other had a net favorable impact of $0.01 per share. Weather conditions during the second quarter, as measured by the Temperature Humidity Index, were 29% warmer than normal and 9% warmer than the second quarter of 2025. As a reminder, the Conservation Incentive Program, or CIP, mechanism decouples weather and other economic sales variances from a significant portion of our distribution margin while helping PSE&G promote the widespread adoption of energy conservation, including energy efficiency and solar programs. Under the CIP, the number of electric and gas customers drives margin, and residential customer growth for electric was about 1% and gas was flat over the past year. The CIP is also benefiting customers as higher revenues from last year's warmer-than-normal summer weather will continue to be refunded to electric customers, and PSE&G has a 5% decrease pending for residential gas customers, driven by the higher revenues from the colder-than-normal winter earlier this year. On the capital front, PSE&G invested approximately $1 billion during the second quarter and is on track to execute our full-year 2026 regulated capital investment plan of approximately $4.2 billion, focused on continued investments in infrastructure modernization, energy efficiency, electrification initiatives, and load growth. We have also maintained our 5-year regulated capital investment plan of $22.5 billion to $25.5 billion through 2030. We completed the GSMP II extension program in 2025, and we were approved to roll in $23 million effective April 2026, as planned. PSE&G continues to execute on the GSMP III program approved by the BPU last November. We expect to invest a total of $1.4 billion over a 3-year period, with approximately $1 billion of the total program receiving accelerated recovery, with the balance in stipulated base to be recovered in our next base rate case. And as Ralph mentioned earlier, we expect the cadence of more frequent base rate cases in the future as fewer clause-based IIPs cover our capital program. And since our last rate case concluded in 2024, PSE&G has made significant investments in distribution rate base to support the reliability of our system. We continue to explore the details of the E3 consultants report addressing Governor Sherrill's Executive Order 1 related to New Jersey's regulatory construct. Elements of the report provide opportunities to enhance the transparency of the regulatory model, which would be helpful for setting customer expectations, as well as the inclusions of performance-based metrics, which, based on our high level of service and customer satisfaction, we would welcome. Switching to transmission and following up on the potential earnings impact of the recent legislation that could eliminate the 50 basis point RTO incentive, we estimated in our 2025 10-K that loss of that incentive could represent an annual headwind of $40 million of net income, or approximately $0.08 per share. Last February, we considered the possibility that the RTO incentive earnings might be eliminated at some point when we rolled forward our long-term non-GAAP operating earnings guidance to 6% to 8% through 2030. I would also note that the effective date of this legislation is January 2027, so there will not be an impact on 2026 results. Moving now to PSEG Power and Other. For the second quarter, PSEG Power and Other reported a net loss of $8 million in 2026 compared to net income of $253 million in 2025, and non-GAAP operating earnings were $83 million in the second quarter of 2026 compared to $52 million in the second quarter of 2025. Referring again to the waterfall on Slide 9. For the second quarter of 2026 versus 2025, net energy margin rose by $0.08 per share, driven by higher generation volume, higher capacity prices, and higher gas operations, partly offset by the absence of both Zero Emission Certificates and the LIPA-related fuel and energy management fees. O&M was flat compared to the second quarter of 2025, and interest expense rose by $0.01 per share, reflecting incremental debt at higher interest rates. Lastly, taxes and other items had a net unfavorable impact of $0.01 per share in the second quarter compared to 2025. In July, PSEG Nuclear cleared approximately 3,600 megawatts of its eligible nuclear capacity in PJM's Base Residual Auction at $325 per megawatt-day for the energy year beginning June 1, 2028, and going through May 31, 2029. This latest result represents a modest decline from the $333 per megawatt-day price set in the prior PJM capacity auction. Touching on some recent financing activity. PSEG had strong available liquidity totaling $3.4 billion as of the end of June. This includes approximately $200 million of cash on hand. On the financing front, in June, PSEG issued $500 million of 4.8% unsecured senior notes due 2031 and used the proceeds to prepay $500 million of a 364-day term loan initiated in February of 2026. PSEG's level of variable rate debt represented approximately 3% of our total debt as of the end of June. Our variable rate debt consisted of the unhedged portion or about half of the $500 million 364-day term loan at PSEG Power maturing in December of 2026 and commercial paper. Looking ahead, our solid balance sheet continues to support the execution of PSEG's 5-year capital spending plan, dominated by regulated CapEx without the need to issue new equity or sell assets and provides the opportunity for consistent and sustainable dividend growth. In closing, we delivered solid operating and financial performance in the second quarter and first half of 2026, enabling us to maintain PSEG's full year 2026 non-GAAP operating earnings guidance of $4.28 to $4.40 per share. We're also reaffirming our 6% to 8% compound annual growth rate for non-GAAP operating earnings outlook through 2030 based on our confidence of executing our 5-year regulated capital investment plan that also supports a 6% to 7.5% compound annual growth in rate base over the same period. We continue to pursue nuclear revenue opportunities, competitive transmission projects and incremental utility infrastructure projects, including making incremental system investments to connect solar and battery storage resources to the grid to meet new demand, which could provide upside to our current growth outlook through 2030. That concludes our formal remarks, and we are now ready to begin the question-and-answer session.

[Operator Instructions] The first question is from the line of Nicholas Campanella with Barclays.

So I guess, Ralph, you said in your prepared just in regards to the base rate filing, you kind of talked about fewer investment infrastructure programs and the alternative is just more frequent base rate cases. Can you just maybe juxtapose that against this BPU report? And how much of the decision to file is on the back of the report versus, I guess, anything that's transpired from the RTO adder that you brought up or the EE spend? And then what parts of this report and recommendations do you think make it into this base rate review?

Yes. Thanks, Nick. So I don't expect a lot to make it in -- to this filing, and that's exactly why I think the timing of the filing aligns pretty well with the state's goals here. I think for all of us, as we look at the EO1 report, we see a state that's looking for a little more transparency, a little more performance-based ratemaking and potential for some multiyear rate plans. To be set up appropriately for that, you need a base rate case. And so the timing of that aligned with the fact that we haven't had anything on the electric side and upwards of 5 years for an IIP kind of puts us in a place where this makes a ton of sense for us right now. And I think it makes a ton of sense for the state. If you look across the utilities in New Jersey, most of the gas utilities have been in for a base rate case. And I think we heard from some of the others in New Jersey, the other electrics that they were planning to come in. And I think Orange & Rockland just settled. So if you look across the spectrum, we think this fits and it would keep us from being an outlier as we go into the next phase of EO1.

Okay. And then maybe just a lot has kind of changed since you gave the 6% to 8%, and I know you're reaffirming that today. But I guess you're maybe pulling forward a base rate review. There's the RTO adder that's out there that I know you addressed is not going to be really impactful until '27. Just taking into kind of account the moving pieces, just where do you kind of see yourself in this range?

Yes, Nick, we see ourselves in the 6% to 8%, as we've been saying. So that hasn't changed. We reaffirmed. We believe there's other opportunities that are presenting itself in the industry that we have opportunities to participate in. I think you talked -- we talked a little bit about the RBA, a few other things that are happening in PJM, our potential upgrades at our nuclear plant that we've talked about quite for a few different times on these different calls. So we remain confident in the 6% to 8% and the RTO adder was one of the scenarios that we had planned for.

The next question is from the line of Richard Sunderland with Truist Securities.

Picking up the RBA commentary there, can you speak a little bit more to the project proposals? And I guess, any way to frame the scale and type of opportunity that you're seeing for PSEG Power in that?

Yes. No, Rich, thanks for that. So look, I think people have -- in some degree, forgotten a little bit about the capabilities that we have inside the company as it goes to generation. We were one of the -- we built some of the last generation plants in PJM and certainly in PJM East when we completed Sewaren and Keys -- but we exited that because it was a market-based solution that really existed and was not something that we were -- we wanted to be part of. Now as PJM is moving into this RBA and there's more opportunities for long-term PPA type or utility-like agreements, we see an opportunity that might present itself. So we've got a few opportunities, we think, inside New Jersey, a few outside New Jersey that we're taking a look at. And I don't want to go much further than that right now because things are still changing at PJM, and we'll read the tea leaves on that just like everyone else is. I think even the load forecast is going to change. We saw some things on that as recently as yesterday. So as those opportunities present themselves, we'll look at it. But we have a skill set here that exists, and we kept the people. I just for those that may not recall, when we did exit the fossil business, we offered those employees an opportunity to stay along with us in the utility and many people did at all sorts of levels in the organization. So we think we've got the skill set to put that group back together, and we think that there's opportunities now that are more utility-like, which kind of align exactly with the investments we're looking to make.

Got it. That's super helpful. And then I guess turning to the PSE&G side, but in similar light to a few of the opportunities you outlined in terms of the 6% to 8% range and upside. Can you speak a little bit more to what you're focused on right now in terms of capturing some of that distribution investment upside or other areas of focus and kind of the time line to crystallize that and have a view on what may move into the plan over the next few years?

Yes. Look, we'll roll forward our CapEx at the beginning of next year as we have in the past couple of years. So that cycle is going to remain the same. I think our gas distribution business is focused, as it always has been, on replacement of cast iron. That's still something that I don't see changing. I think on the electric side, you've seen a lot from Governor Sherrill's administration about being ready for solar, more distributed energy resources, batteries, and so on. And I think that you'll see more alignment with our last mile conversations that we've had over the last few years and our -- they have a specific PSUP program that they've talked about at the Board of Public Utilities. And as the new Board President gets his feet under him at the Board there, I think you'll see a little more focus on driving the electric utilities in that direction. And any updates we'll have will roll out in the first quarter of next year.

The next question is from the line of Carly Davenport with Goldman Sachs.

Just two questions on the power side for me. One, could you provide any updates in terms of hedging activity beyond 2026, so where you are in '27 or '28 at this point?

Carly, there's nothing incremental for us to disclose. There's nothing in the materials that we have disclosed. We're working our way through the future years as we step through time.

Okay. Got it. And then I guess just as you're thinking about potentially getting towards more regulatory certainty in PJM, I'm curious if you have seen any inflections in interest from data center or other large load customers for PPAs at Power relative to prior quarters?

Yes, I wouldn't say there's inflections, Carly. I think there's been some continued interest and pursuit on some things. I think that continues. I think that the process in PJM is something that people have, I think, for the past few months, no one is out there. They've tried to figure out where it's going and what it's going to mean from the standpoint of new load. And I do think that this whole RVP and IRAS processes are going to help folks figure out what is going to be expected of them so they can work against that backdrop. And so I think really the only change we've seen is just maybe just a caveat in the discussions related to the fact that if something has to happen, they are not boxing themselves into any kind of an agreement to trouble that thing that they need to stay in compliance with. But I wouldn't call it inflections. I would just call it people reading the context of where we are with respect to PJM.

The next question is from the line of Michael Sullivan with Wolfe Research.

Ralph, on the BPU review that's ongoing, any sense to when that's just fully wrapped up? And then on the rate case that you're about to file, any sense of size of rate increase? Or could it potentially be a decrease to align with the governor? How should we be thinking about that?

Yes, Michael, I would say the next step is Phase 2. I think all that information is in the public, and I don't want to front-run anything at the BPU. I think they've got their own timeline. And as I mentioned, we've got a new President at the BPU who is getting up to speed, and we'll see what -- if he wants to make any changes to the timeline that was published, but I don't expect that to be the case. And then as far as our rate case goes, look, we haven't disclosed anything more on that. And I'll leave -- we wanted to signal to you all that we were getting aligned again with the state and the timing that was going to be required to adequately execute on EO1. And so put those two pieces together, and we wanted to make sure that we were transparent about that with the investment community. So we got that information out, but no more details than that at this time.

Okay. Great. And then on the power side, can you just give a sense of to the extent you're pursuing opportunities in the RBP, what sort of returns you'd be targeting and how the math works with the $555 price cap in there?

Yes. That's a great question, but I'm going to give that to Dan. Look, I think a lot of that is a TBD, Michael, but it's -- right now, the way that process is set up, you have to raise your hand first. And so we've raised our hand, and we wanted to, again, remind folks that we're in that business, but I'll give -- turn it to Dan for a little more.

Yes, Michael, we see potential in what is there to explore and determine whether something there is going to be attractive. It would be foolish to provide what an expectation would be of returns in a competitive situation. So I won't do that. But I do think that there's enough there for us to be interested in exploring, getting into the process and seeing if it meets the criteria, which what we've talked about is whether it's going to be utility-like or contracted enough to be attractive to us. And so all of those elements that I just talked about go into kind of risk and you're going to compare your return to the risk that you're taking. So obviously, it's more complicated than just providing a number to you with respect to what the return would be.

Michael, I just -- let me just double down on what Dan said regarding the risk profile in the utility-like. I just want to reinforce that. We said it to an earlier question as well, but that's really important to us. However, I do think that, as you said, there's some more clarity in the PJM regulatory construct they're putting together. I think it's getting closer to utility-like with at least some of these opportunities that exist.

Our next question is from the line of Jeremy Tonet with JPMorgan.

I just wanted to go back to the bilateral discussions as you touched on before. And sorry if you had already said this, but in these conversations for -- with bilaterals, is it interest in existing assets, new assets or both? Or how should we think about that?

Yes. I think it's both, but more interest in new, right? If you think about the entire tone, I think across the country with respect to new load coming on, you don't have discussions about new load coming on with at least a preference for having incremental generation to join that. So I think there's also an understanding that new generation takes a while to come on. And so I think there is a preference to have something new to kind of fit within that overall dialogue. But I would say there is not solely an interest in new is how I would describe it.

Got it. And so is there -- is it like kind of a 1:1, would you say? Or is there any ratio or is this all just kind of varies?

No, there's not a fixed ratio. It's just a preference, that's all.

Got it. One last quick one, if I could. Obviously, a lot of new supply needs. How do you think new nuclear could fit in here? Do you think it is possible or it's just too far off at this point? Just any thoughts there would be great.

I think, Jeremy, you as you kind of answered your own question there, is it potentially too far off, right? It depends upon the time line that you're looking at. I do believe that new nuclear makes sense, as we said in the prepared remarks. I think it's aligned again with the policies of the state. So we've always done that. And so we're trying to enable that as best we can. But whether or not those units, whether it's in New Jersey or across the country, come on quick enough for some of the load that's looking to connect. These are 12 years, 12-year long projects. I won't revisit what's happened in the past. So we need short-term solutions as well as long-term solutions. And I think that the new nuclear certainly falls in the long-term bucket.

And even if you take a look at what the RBP is talking about, they're talking about an in-service date of 2032. So that's half the time to get to the 12 years that Ralph just talked about. So I think there's near term, medium term and long-term nuclear is certainly on the longer term.

The next question is from the line of Rinny Singh with Bank of America.

I guess, first on the comments around the Phase I study, there's a pretty broad range of reforms that they propose. I guess how are you thinking about as we move forward, this negotiation and your input into the stakeholder process and what would have the most merit in New Jersey, both like as utility owners and then the conversations with the BPU?

Yes. I think, look, we see multiple paths. And you kind of said there's multiple things that they put forth in EO1. I thought they really just put forth a number of options, but not necessarily a number of reforms, right? There's multiyear rate plans, there's performance-based rates, but these are things we've seen before in the industry and that it will provide more transparency for our customers. So I welcome everything that's being discussed. I think more transparency for customers is helpful for us, especially when you have some of the billing cycles like we've gone through. I think one of the best things that came out of the report was the reference to only 25% of the bill is distribution. And I think that was a number that was quoted in the EO1. And so I look at that and I say, I welcome the transparency. I think that's very helpful for us as a company. And from a performance-based rates, we started the prepared comments as we do always with financial, but move quickly into operational because we are very proud of the operational results that we have as a company. And so from a performance-based rate standpoint, we welcome that. So I kind of tie those two pieces together. And I think the paths that we see are all positive. I think we have to all the devils in the details, and we'll work through that with policymakers. But I feel pretty good about where we are. And I think that our filing of a base rate case shows our willingness to be aligned from a timing standpoint with the next steps that we'll see in this process.

Okay. That makes sense. And then I think that kind of gets to my second question. Power is a big portion of the cost increases, and we have this RBP structure and the cost is kind of allocated down to the state basis. How do you think about the process there and the time line for states, I guess, specifically New Jersey to create this cost allocation basis? And what is it kind of favorable in that regard that it is down to the states? And then I guess on the flexibility procedures, how are you thinking about the mandatory flexibility down to the transmission owner tariff versus PJM just dictating it?

Yes. Look, I think that there's still -- again, we got to look for a little more detail. We got to see what comes out of FERC when they finally approve everything. But the state will be involved because the BPU will have some time lines that they'll have to meet. Right now, I think it's set up at 12 months, but we'll see how that changes over time, and I don't want to be locked into anything specific there until we see what comes out of FERC. But I do think that working together with the BPU, we can be very helpful here. And I'm going to point to something that recently happened, which is the transmission cost allocations process where we had -- I think it was again in our prepared remarks where we talked a little bit about how some of that cost allocation was done and working with the state, we now as recently as, I guess, the last 2 days, we saw that, that filing that we had made for the cost allocations was approved by FERC. And the result is going to be a $65 million a year savings going forward. That's not just a onetime, that's every year going forward for our customers. So we've proven we can work with the state in that particular case. That cost allocation was something we really advocated for strongly as a company ourselves. And then we worked with the state to get over some of the last-minute hurdles here. And I think we can do the same when we get into this -- into the RBA. I think we'll be able to figure out exactly the right way to do this to help from a customer cost standpoint as best we can.

Next question is from the line of Sophie Karp with KeyBanc.

It's been discussed already from several angles, but maybe let me try this one. Are you guys seeing attractive opportunities to contract bilaterally for new builds like outside of the PJM contract, like not as a part of the immediate bilateral auction, but on your own with customers to facilitate their large load build-out in the PJM footprint. Sort of like some of your peers are trying?

Yes. Sophie, I'm going to give that to Dan. I just want to just -- PJM isn't the only process that's being stood up right now to go through these bilateral contracts. So it's a great question, and I'll give it to Dan.

Yes. I think to the extent that you are new load, you're going to end up getting pushed into that. But I also think that there's states that are seeing their supply-demand balances not necessarily be where they want them and maybe looking to do something to prompt some generation there. And so I think that's got some potential as well. I think to your question, it sounded like are you seeing folks come in and, in particular, new load looking for new generation. I think that will get caught up into that RBP process, though. So I think there are other venues, and I think we've got one of the best sites that are out there with respect to the infrastructure in place. But we'll see what happens throughout as we go forward through a couple of different processes as they move forward.

And maybe just to build on that, like as you consider these types of investments, how do you think about the target IRR or return that you would need to jump on to that? Like what's your thinking process here?

Yes. Sophie, I'm going to, again, just kind of give -- reinforce something Dan said earlier. It all depends upon the risk, right? And we have said we don't want to be in a high-risk market. I would consider PJM marketplace to be high risk. We're looking for utility-like returns. So I think in saying that utility-like investments, we're saying utility-like returns because we're looking for utility-like risk. And I don't want to go much further than that other than just to reinforce utility-like, utility-like, utility-like.

The next question is from the line of Ryan Levine with Citi.

Given the New Jersey BPU and other PJM state level discussions around virtual power plants, how are you thinking about the opportunity for PEG?

Yes, Ryan, thanks. Listen, I think from a PEG standpoint, again, it's an opportunity for us to show alignment with the state policy. There's not a tremendous financial opportunity on the VPP side that we see. I think maybe nationwide, if you were in that game or you're doing some other things. But for our New Jersey customers, it's more about aligning with policy and enabling that policy than it is about a financial return.

Okay. But are there any initiatives that you have underway to address that alignment?

Yes, we have some -- I think we've worked with the BPU on a couple of different items where we've put forth some pilot programs. And I think they're going to initiate more of a process there. So again, we'd be front-running them if we got ahead of that curve. But we've done that more through the regulatory conversations than we have with actual implementation of programs. But we do have some pilots that we've proposed.

Next questions are from the line of Paul Patterson with Glenrock Associates.

Just wanted to sort of follow up on the expected rate case and what have you. And sort of get your -- and I apologize if I missed this, but the energy efficiency order that came out and how you see that -- what is that -- it seems a little unusual in terms of their return and what have you. I'm just wondering if you could sort of give me a better feeling for what -- how you see that in the whole context of the regulatory environment there.

Yes. Look, I look at that as a very specific piece of the regulatory process, not overarching. I think, again, the state is looking for affordability. So understand the goals that were put forth in that framework. But it is a framework. It's not mandated. So we have the opportunity to talk about how our programs differentiate from others. I think one of the biggest ones for us is our use of union labor and the percentage in which we use union labor to achieve the goals that were put forth for all of the -- for us by the BPU. So I do think there are some differentiating factors that are worth discussion. I also think that it's important to note that this is prospective from an asset standpoint. This is dealing with the extension assets, the dollars that we're putting forth to support that investment, not for all the investments. So that's also important. And I think it's also a reflection of the amount of, I'd say, the loan program, the on-bill financing that we're doing and the perceived risk around that specific part of the program. So there's a lot of specifics in what I just said to you, which makes it kind of unique, and it's consistent from an affordability standpoint, but it's unique from an investment standpoint as we think about it.

Okay. Great. And then just back on nuclear, I just -- I'm wondering if you could give a flavor for what stakeholders actually think or what their comprehension about what the affordability impact of nuclear might be? I mean, this is around the country. There seems to be bipartisan buy-in to this, and I understand its appeal. But I'm just wondering when you're speaking to policymakers, et cetera, or maybe you can tell me if there's been a big change in the cost of nuclear. I mean I know there is SMR technology, et cetera. But I mean, is there -- do you think there's a full understanding about -- I mean, with respect to this buy-in about what the cost of new nuclear might be? Do you follow what I'm saying?

Yes. Look, I think there's plenty of levelized cost of energy reports out there that give policymakers a clear line of sight into what the costs are going to be. I think there's a question about the timing of the projects coming online and when -- what the cost will be at that point, right? So that's always a conversation that you have with policymakers. I think the biggest open item for everyone is, while there's bipartisan support for building new nuclear, there's also bipartisan support to protect ratepayers from cost overruns. And so the question comes down to where do we -- how does that risk get adequately allocated amongst the players in any given project? And that's why whenever we've talked about it, we've talked about enabling new nuclear because of the concern that we have about how does that become utility-like if there's high risk associated with it. So more to come on that. I think we're, again, very well positioned. I think our site is very well positioned and we look forward to doing what we can to enable new nuclear in New Jersey. But I think to your specific question, is there a line of sight for policymakers on the cost? I think there's plenty of studies out there, and I think there's plenty of conversation about where these costs are and, more importantly, where they could go to.

Our final question is from the line of Travis Miller with Morningstar.

You answered most of my questions, a lot of details. I appreciate it. Just one quick follow-up on that. EO1 and the process from here. Is the ball now in your court in terms of putting together proposals, best ideas, stuff like that to present to the BPU? Or are you still waiting for some more guidance either from governor's office or BPU or some other entity before you start putting filings out?

Yes, Travis, there's a clear Phase 2 that the Board of Public Utilities will go through as the next step in this process. So we'll participate in that. We'll have comments. There's plenty of stakeholder meetings that have been scheduled by the Board that we will participate in and others. So it's more, at this point, still an open item that we wait for finalization of the orders from the Board of Public Utilities.

Okay. So you think in terms of putting together actual proposals and stuff that comes after the base rate case?

Well, no, I think, we said we file by the end of the year. There's a time line associated with that. If you kind of play it out, there'll be some sort of a framework that will come out for EO1. I would expect that to happen in the last quarter, beginning of next year, put that framework together and now you've got your base rate filing that's been recently approved or is about to be approved for any utility in the state. And then you can start to move efficiently into the next framework because you've got that base to work off of.

Okay. That makes sense. A lot of work to do in '27. Stay busy.

Thanks, Travis.

At this time, I'll turn the floor back to Mr. LaRossa for closing comments.

Well, thank you. Just a couple of things. I appreciate all the interest as always. I just want to reinforce the way we started, which was on the great work by the teams here in New Jersey and in Long Island to respond to the storms over the July 4 holiday season and just the fact that people were away from their families and from their barbecues and from everything that they wanted to be doing otherwise during that weekend. Without that operational excellence, we couldn't even be having conversations about what we can potentially do moving forward. And I think as I look forward, we've continued to get more regulatory clarity, both at PJM with some of the steps that they've taken and how that might play out on the generation side and here in New Jersey on the distribution side as we've moved through the EO1 process and ongoing conversations there. So regulatory clarity is starting to take place. And then I think on top of that, there's opportunity sets that remain in front of us that are presented both by the regulatory clarity at PJM and in New Jersey as it pertains to that last mile and getting the system ready for the solar and batteries that we know we need in the near term. So I put all those pieces together, and I feel pretty good about where we are. So I look forward to the next time that we're together. And I'll just end by wishing Carlotta a belated happy birthday for all of you that are on the call and interact with her all the time. When you give her a buzz next time, just make sure you say happy birthday. Thanks for dialing in.

Thank you. Ladies and gentlemen, this concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.