Prepared remarks
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. As a reminder, this conference is being recorded today, August 4, 2026, and will be available for replay as an audio webcast on 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. 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 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. Our operational results may have been even 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 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 more than 330 crews and supported by over 10 million proactive customer communications. In addition to thanking our employees who participated in the storm response, I want to highlight that we carried out this multi-day restoration with an excellent safety record and provided PSE&G crews to assist 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 as 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 in October 2020. Our energy efficiency investments have also supported approximately 9,300 jobs statewide over the past six years, including a network of more than 1,000 trade and union partners. We are proud of our strong performance to date in this program, including the success of our job programs and the use of union labor. 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. 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 began in June. PSE&G has also filed with the BPU to lower residential gas bills by more than 5% beginning October 1, continuing to provide our customers with the lowest gas utility bills in New Jersey and the region. We are also pleased to note 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 change will result in approximately $33 million benefit to our zonal transmission customers for the period from June 1 through year-end 2026, with an expected prospective annual benefit of about $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 focused on New Jersey affordability. The governor's first executive order directed the BPU to study modernizing the electric utility business model. Last month, the BPU released its consultant report, which marked the conclusion of Phase 1 of this directive. While no formal recommendation was issued, the report highlighted several promising regulatory frameworks and multiple reforms from other states. These included multiyear rate plans, performance-based rates, performance incentive metrics, earnings sharing mechanisms, decoupling, and shared saving mechanisms, all of which can better align the utility business model, state energy policy goals and affordability in the state. The BPU will now proceed to Phase 2, expected to focus on cost discipline, financing modernization, targeted incentives and shared savings, and staged 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 how business model changes can address affordability and by its emphasis on using multiple criteria in decision-making. As we prepare for these stakeholder proceedings, combined with the growing regulatory lag 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 2024, established a requirement to file our next base case no later than 2029. However, we have said before that we could file sooner if conditions warranted. Given that we have added a significant amount of distribution rate base at a time when there have been fewer infrastructure investment programs, the alternative would be 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 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 percent 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 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 working to enable new nuclear development at our Salem County site since 2016, when we obtained an Early Site Permit from the U.S. Nuclear Regulatory Commission, one of only six currently issued in the United States. We believe 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 five-year non-GAAP operating earnings growth outlook of 6 to 8 percent 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 five-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 consultant's 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 inclusion 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.
Questions and answers
The first question is from Nicholas Campanella with Barclays.
So, Ralph, you said in your prepared remarks regarding the base rate filing you talked about fewer investment infrastructure programs and the alternative being more frequent base rate cases. Can you juxtapose that against this BPU report? How much of the decision to file is driven by the report versus anything that's transpired from the RTO adder or the EE spend? And what parts of this report and its recommendations do you think will make it into this base rate review?
Yes. Thanks, Nick. So I don't expect a lot to make it into 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 aligns with the fact that we haven't had anything on the electric side and upwards of 5 years for an IIP, which 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. 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 a lot has changed since you provided the 6% to 8% outlook, and I know you're reaffirming that today. Given the moving pieces — you're pulling forward a base rate review, there's the RTO adder that won't be impactful until '27 — taking all that into account, where do you see yourself in this range?
Yes, Nick, we see ourselves in the 6% to 8% range, as we've been saying. That hasn't changed. We reaffirmed it. We believe there are opportunities presenting themselves in the industry that we can participate in. We talked a bit about the RBA and other things happening in PJM, potential upgrades at our nuclear plant that we've discussed previously. So we remain confident in the 6% to 8% outlook and the RTO adder was one of the scenarios we had planned for.
The next question is from the line of Richard Sunderland with Truist Securities.
Picking up on the RBA commentary, can you speak a little more to the project proposals? Is there any way to frame the scale and type of opportunity you're seeing for PSEG Power in that?
Yes. Rich, thanks for that. I think people may have somewhat forgotten the generation capabilities we maintain in the company. We built some of the last generation plants in PJM East when we completed Sewaren and Keys, but we exited certain market-based assets because those were market-driven. Now that PJM is moving into this RBA with more opportunities for long-term PPA-type or utility-like agreements, we see a potential opportunity. We have a few opportunities inside New Jersey and a few outside the state that we're evaluating. I don't want to go much further right now because things continue to change at PJM, and we'll be watching closely. Even the load forecast has been changing recently. As those opportunities present themselves, we'll assess them. We retained skill sets and people when we exited some fossil businesses — many stayed with us in the utility — so we believe we can assemble the team to pursue these opportunities, which look more utility-like and align with the investments we're making.
Got it. That's helpful. Turning to the PSE&G side, similar to the opportunities you outlined in the 6% to 8% range and upside, can you speak more to what you're focused on now in terms of capturing distribution investment upside or other areas of focus and the timeline to crystallize that and move things into the plan over the next few years?
Yes. We'll roll forward our CapEx at the beginning of next year, as we've done in prior years, so that cycle continues. Our gas distribution business remains focused on replacing cast iron, which I don't see changing. On the electric side, the administration's focus on solar and distributed energy resources, including batteries, points to increased alignment with our 'last mile' conversations over recent years and the specific PSUP program discussed at the BPU. As the new Board President settles in, I expect greater focus on driving the electric utilities in that direction. Any updates we have will roll out in the first quarter of next year.
The next question is from the line of Carly Davenport with Goldman Sachs.
Two questions on the power side. One, any updates on hedging activity beyond 2026 — where you stand for 2027 or 2028 at this point?
Carly, there's nothing incremental for us to disclose from what we've already provided. We're working through the future years as time steps forward, but there's nothing new in the materials to disclose today.
Got it. As you think about potentially getting more regulatory certainty in PJM, have you seen any inflections in interest from data center or other large load customers for PPAs at Power relative to prior quarters?
I wouldn't say there are inflections, Carly. There's continued interest and pursuit on certain opportunities. The process at PJM is something people have been watching over the past few months as they try to determine implications for new load. The RVP and IRAS processes should help stakeholders understand expectations so they can plan accordingly. The only change we've seen is some additional caveating in discussions: counterparties are cautious and not committing in ways that might jeopardize future compliance. But I wouldn't call this an inflection; it's more people reading context around PJM.
The next question is from the line of Michael Sullivan with Wolfe Research.
On the BPU review that's ongoing, any sense of when it's fully wrapped up? And on the rate case you're about to file, any sense of size of the rate increase? Or could it potentially be a decrease to align with the governor? How should we think about that?
Michael, the next step is Phase 2. All that information is public and I don't want to preempt the BPU's timeline. We have a new BPU President getting up to speed; if he changes timelines, we'll adapt, but I don't expect major changes. Regarding our rate case, we haven't disclosed details. We wanted to signal that we are aligning timing with the state's goals to execute on EO1, and we intended transparency to the investment community. Beyond that, no further details at this time.
Okay. On the power side, as you pursue opportunities in the RBP, what sort of returns would you target and how does the math work with the $555 price cap?
That's a great question, but I'll turn that to Dan. A lot is still to be determined. The process as currently structured requires participants to raise their hands first; we've raised ours. We're reminding the market that we are active in generation, but I'll let Dan provide more on returns.
Michael, we see potential worth exploring, but it would be unwise to provide an expected return for a competitive situation. We won't give a specific return target here. There is enough there for us to be interested in exploring and entering the process to see if it meets our criteria, namely whether it is utility-like or contracted enough to be attractive. Risk assessment will determine required returns, so it's more complicated than offering a single number.
Michael, to double down on Dan's point: the risk profile matters. We're looking for utility-like risk and returns. There is more clarity emerging in PJM's regulatory construct, and some opportunities are becoming more utility-like.
The next question is from the line of Jeremy Tonet with JPMorgan.
Going back to the bilateral discussions, are conversations around interest in existing assets, new assets, or both? How should we think about that?
I think it's both, Jeremy, but there's more interest in new. With new load coming on, counterparties generally prefer incremental generation to match that load. New generation takes time to come online, so there's a preference for new capacity to be part of those discussions. But I wouldn't say interest is solely in new assets.
Is there any sort of ratio, like 1:1, or does it vary?
No fixed ratio. It's simply a preference for new capacity in many discussions.
One last quick one: how do you think new nuclear could fit in here? Is it possible or too far off at this point?
Jeremy, it depends on the time horizon. New nuclear makes sense as a long-term solution — we've said that — and it aligns with state policy. We've been working to enable new nuclear at our Salem County site and hold an Early Site Permit. But new nuclear projects are long-lead items — roughly 12 years — so whether they can come on in time for some new load is uncertain. We need both short-term and long-term solutions; new nuclear sits in the long-term bucket.
If you look at the RBP, they talk about in-service dates around 2032, which is relatively nearer term compared to a full 12-year build. So nuclear is more of a longer-term solution.
The next question is from the line of Rinny Singh with Bank of America.
On the Phase I study, there are many proposed reforms. How are you thinking about input into the stakeholder process and what would have the most merit in New Jersey, both as utility owners and in conversations with the BPU?
We see multiple viable paths. The EO1 consultant report presented options rather than firm reforms — multiyear rate plans, performance-based rates, and other mechanisms we've seen in the industry. They can increase transparency for customers, which I welcome, especially given recent billing cycles. One useful point in the report was highlighting that only 25% of a customer's bill is distribution — that transparency helps. From a performance-based standpoint, we welcome incorporating operational metrics; we are proud of our operational performance and customer satisfaction. We'll work through the details with policymakers. Our planned base rate filing signals our willingness to align timing-wise with the state's next steps.
On the RBP and cost allocation, how do you think about the timeline for states, specifically New Jersey, to create a cost allocation basis? Is it favorable that allocation is down to the states? And on the flexibility procedures, how do you view mandatory flexibility being added to the transmission owner tariff versus PJM dictating it?
We need more detail and will see what comes out of FERC. The state will be involved and the BPU will have timelines to meet; currently it's set up around 12 months but that could change. I don't want to be locked into specifics until FERC acts. We have proven we can work with the state to achieve favorable outcomes — for example, the transmission cost allocation filing we pursued led to an expected $65 million per year prospective savings for our customers. We advocated strongly and worked with the state to overcome last-minute hurdles. We expect to bring that same approach to the RBP discussions and aim to minimize customer costs.
The next question is from the line of Sophie Karp with KeyBanc.
Are you seeing attractive opportunities to contract bilaterally for new builds outside of the PJM process — creating deals directly with customers to facilitate large load build-out in the PJM footprint, similar to peers?
Sophie, I'll turn that to Dan, but note that PJM is not the only process standing up for bilateral contracts.
To the extent new load exists, it tends to get pushed into mechanisms like the RBP, but some states are looking to prompt generation locally when supply-demand balances are tight. There are other venues beyond PJM, and we have one of the better sites with existing infrastructure. We'll see how processes evolve and how opportunities develop across different state and regional paths.
As you consider these investments, how do you think about target IRR or return thresholds to pursue them?
It depends on the risk. We do not want high-risk market exposure. We consider the PJM marketplace to be higher risk and are seeking utility-like returns commensurate with utility-like risk. So the guiding principle is utility-like risk and returns.
The next question is from the line of Ryan Levine with Citi.
Given New Jersey BPU and PJM state-level discussions around virtual power plants, how are you thinking about the opportunity for PSE&G?
From a PSE&G standpoint, it's primarily an opportunity to align with state policy. We don't see a significant direct financial opportunity from VPPs in New Jersey at this time. It's more about enabling policy and alignment than near-term financial return.
Are there initiatives underway to address that alignment?
Yes, we've proposed pilot programs and engaged with the BPU on a couple of items. More formal processes are expected from the BPU and we'll participate, but many efforts have been regulatory and stakeholder-focused so far rather than broad implementation.
Next questions are from the line of Paul Patterson with Glenrock Associates.
Following up on the expected rate case and the energy efficiency order that came out, it seems somewhat unusual in terms of the return structure. How do you see that in the broader regulatory context in New Jersey?
I view that as a specific piece of the regulatory process rather than an overarching change. The state is focused on affordability, and the framework is prospective rather than mandatory in all respects, which allows us to show how our programs differ. A key differentiator for us is the use of union labor in our energy efficiency programs. The framework deals with extension assets and the dollars associated with them, not every investment. It also reflects concerns around on-bill financing and perceived risk. There are many specific elements that make it unique, and we will continue to discuss and engage with stakeholders about how our programs align with affordability objectives.
On nuclear, do stakeholders understand the affordability impact of new nuclear? There's bipartisan support, but is there a full understanding of the potential costs and timing?
There are many levelized-cost studies available that provide policymakers visibility into expected costs. The timing of projects and potential cost movements are always part of the discussion. Policymakers support new nuclear but also want to protect ratepayers from cost overruns — the allocation of that risk is a central issue. That's why we emphasize enabling nuclear development and discussing how risk is allocated so projects can be utility-like. Our site is well positioned and we're working to enable projects, but discussions about cost and risk allocation will continue.
Our final question is from the line of Travis Miller with Morningstar.
On EO1 and the process from here, is the ball now in your court to put together proposals and ideas for the BPU, or are you still waiting for more guidance from the governor's office or the BPU before you file?
There's a clear Phase 2 that the BPU will pursue and we will participate. We'll file comments and participate in stakeholder meetings the Board schedules. At this point it's an open process and we await finalization of orders from the BPU. We plan to participate actively and will submit proposals and comments in response to the Board's process.
Do you think putting together actual proposals comes after the base rate case filing?
We expect the Board to publish a framework likely in the last quarter or early next year. If you align that with our planned base rate filing by year-end, you'd have the base case available to work from as stakeholder discussions progress. So yes, putting forward detailed proposals will come as the framework and filings align.
Okay. That makes sense. A lot of work to do in '27.
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 weekend and the sacrifices our employees made during that period. Without that operational excellence, we couldn't even be having conversations about what we can potentially do moving forward. As I look ahead, we've continued to get more regulatory clarity both at PJM and in New Jersey through the EO1 process and ongoing conversations. Regulatory clarity is starting to take place. And on top of that, there are opportunity sets presented by that clarity — both on the generation side at PJM and on the distribution side here in New Jersey for last-mile readiness to connect solar and battery storage resources we need in the near term. I put those pieces together and feel good about where we are. I look forward to the next time we're together. And I'll just end by wishing Carlotta a belated happy birthday — for those of you who interact with her regularly, when you speak with her next, be sure to wish her a 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.