Ladies and gentlemen, thank you for standing by. My name is Jesse, and I'm your event operator for today. I'd like to welcome everyone to today's conference entitled to Public Service Enterprise Group Third Quarter 2021 Earnings Conference Call and Webcast. At this time, all participants are in a listen-only mode. As a reminder, this conference is being recorded today, November 2, 2021, and will be available as an audio webcast on PSEG's Investor Relations website at investor.pseg.com. I'll now turn the call over to your moderator for today, Carlotta Chan. Ma'am, you may go ahead.

Thank you, Jesse. Good morning. PSEG has posted its third quarter 2021 earnings release, attachments and slides detailing operating results by company on our website at investor.pseg.com, and our 10-Q will be filed shortly. The 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 and non-GAAP adjusted EBITDA, which differ from net income or loss as reported in accordance with generally accepted accounting principles 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 earnings material. I'll now turn the call over to Ralph Izzo, Chairman, President and Chief Executive Officer of PSEG. Joining Ralph on today's call is Dan Cregg, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions.

Thank you, Marla, and to all of you for joining us on our call this morning. As you have seen, PSEG reported non-GAAP operating earnings of $0.98 per share for the third quarter of 2021 versus $0.96 per share in the year ago quarter. GAAP results for the third quarter were at $3.10 per share net loss related to transition charges at PSEG Power, and they compare with a $1.14 per share of net income for the third quarter of 2020. In this year's quarter, PSEG Power recorded a pretax impairment loss of approximately $2.17 billion to reflect the announced sale of its fossil generating fleet that includes $13 million of other related costs. Results for the third quarter bring non-GAAP operating earnings for the first 9 months of 2021 to $2.96 per share. The 6.5% increase over non-GAAP results of $2.78 per share for the first 9 months of 2020 reflects the growing contribution from our regulated operations and continued derisking at PSEG Power. Slides 12 and 14 summarize the results for the third quarter and the first 9 months of 2021. The third quarter of 2021 was one of the most significant in recent PSEG history. Since July, we've announced the sale of Power fossil fleet and reached the transmission rate settlement that will help lower customer build. In addition, at our recent investor conference, we announced an increase in our 5-year capital spending plan by $1 billion, a $0.12 per share increase to the common stock dividend for 2022, a $500 million share repurchase program expected to be implemented upon the close of the fossil sale and initiated a 5% to 7% long-term earnings growth projection over the 2022 to 2025 period. On the ESG front, we advanced our decarbonization efforts with the elimination of coal in our fuel mix this past June. Our participation in the New Jersey Wind port and ongoing consideration of regional offshore wind opportunities in generation and transmission, demonstrates our alignment clean energy agenda. And our Clean Energy Future program was recently named a star of energy efficiency recipient in . Of critical importance, we have staked out a leadership position in the industry by accelerating our net 0 vision to 2030 and joining the UN-backed Race to Zero campaign that will put us on a test to establish science-based targets to all of our missions across Scopes 1, 2 and 3. Later this week, I will be attending the conference of parties referred to as COP 26 to engage with policymakers and further support emissions reduction goals. This includes advocating for climate action now and advancing the case for preserving existing nuclear generation. This month, we issued a combined sustainability and climate report that outlines our progress to date and commitments for the future. We intend to continue taking meaningful climate action in response to the increased frequency and severity of extreme weather in our service area. Speaking of extreme weather, tropical storm Ida soaks parts of New Jersey was nearly 9 inches of rain within a 24-hour period and caused extensive flooding throughout the state. Our past and current Energy Strong investments that hardened flood-pro energy infrastructure brought tremendous benefit to customers during Ida, minimizing the damage to adaptive substations and switching stations and keeping them operational. That said, the extreme weather did read Havoc throughout our service area and our thoughts go out to the families who lost loved ones to the storm and to the community still recovering from flood damaged homes and businesses. To continue these enhancements and bring them closer to the customer, we are expanding our reliability improvement programs to the last mile of work we will propose in our upcoming infrastructure advancement program, which we plan to file with the BPU in a few days. This proposal, if approved, would direct approximately $848 million of investment over a 4-year period to improve the reliability of our electric distribution system, addressing aging substations and gas metering and regulating stations and electric vehicle charging infrastructure at PSE&G facilities that will support the planned electrification of the utility fleet, all of this while serving the dual purpose of creating important high-quality jobs and helping to further stimulate the New Jersey economy. The foundation of results for the quarter was the solid operating performances by both PSE&G and PSEG Power. This summer, the third hottest on record contributed to the hottest first 9 months we've ever recorded, pushing a number of total hours with temperatures exceeding 90 degrees or greater, nearly 65% higher than the same period in 2020 and versus normal, thereby increasing peak demand. The conservation incentive program effective since June 1 for electric and October 1 for natural gas provides recovery for variations in customer usage due to weather, economic conditions and energy efficiency, thereby enabling the utility to promote maximum customer participation in energy efficiency programs without the loss of margin from lower sales. This also has a stabilizing effect on our margins more broadly. The continued reopening of the New Jersey economy is unwinding some of the shift in sales experienced during most of 2020. Residential electric sales declined adjusted for weather as more people return to work, school and other activities outside the home, partly offset by higher commercial and industrial sales. Due to the warmer-than-normal summer weather and the lifting of COVID-19 restrictions, the daily peak load for the quarter topped out at 9,620 megawatts compared to last year's third quarter daily peak, which was slightly less at 9,557megawatts. Our peak load for the year remains the 10,064 megawatts we hit on June 30, which exceeded the 10,000 megawatt mark for the first time since 2013. Moving to the Zero Carbon and infrastructure side of PSEG. We recently announced that we have submitted several joint proposals to New Jersey's competitive state agreement approach, open window to build offshore wind transmission infrastructure. These joint proposals submitted with Orsted are collectively named the coastal wind link and leverage the experienced partnership of PSEG and Orsted in New Jersey energy infrastructure, our commitment to diverse suppliers and our mature working relationships with local building and construction trades. The proposals cover onshore upgrades, new onshore transmission connection facilities, new offshore transmission connection facilities and a networked offshore transmission system in any stand-alone configuration or combination. PJM is providing the technical analysis and recommendations to the New Jersey Board of Public Utilities, who will make the final decisions based on an evaluation of reliability and economic benefits, cost, constructability, environmental benefits, permitting risks and other myriad New Jersey benefits. A BPU decision is not expected before the third or fourth quarter of 2022. FERC has granted PJM's request to delay the next capacity auction covering the 2023, 2024 energy year to late January 2022. This revised time line places the 2024, 2025 auction into August of 2022 and the '25-'26 auction into February of 2023. These upcoming capacity auctions will provide additional surety to the gross margin of our nuclear fleet in the outer years of our 2021 to 2025 planning horizon. Nuclear Power's economic struggles are a national challenge that call for a broad federal solution so that individual states like New Jersey aren't shouldering more than their share of the loan. We are continuing efforts to secure support for existing at-risk nuclear plants in the federal tax code, the House version of the build back better infrastructure legislation currently contains an 8-year production tax credit for existing nuclear at $15 per megawatt hour, with the value of the credit declining as market revenues increase. The proposal has support in the Senate and from the Biden administration. While passage is not assured , this would be an impactful provision for the nation's nuclear fleet, and we are hopeful that commerce can enact this fall. You may recall that the New Jersey's ZEC law contained considerable customer protections and specifically requires that state 0 emission certificate payments that I just referred to a moment ago as ZEC payments, be offset by any out-of-market payment compensating nuclear for the same 0 carbon attribute. Specific to the nuclear production tax credit, the value of the PTC for our New Jersey units would reduce the ZEC payment up to the maximum $10 per megawatt hour. However, the ZEC would not reduce the value of the PTC and our share of the 2 Pennsylvania peach bottom units would benefit from the full production tax credit. Moving forward, there needs to be broad recognition at both the state and federal level of the value of nuclear 0 carbon attributes both for the quality of air today and the climate tomorrow. To avoid backsliding for decades to come, we need to ensure that the long-term viability of New Jersey's nuclear generation is preserved as we bring more clean energy resources into the mix. Turning my attention to guidance. We are raising our forecast for full year 2021 non-GAAP operating earnings to a range of $3.55 per share to $3.70 per share from the prior range of $3.50 to per share. And this is based on results in the first 9 months of the year. Results for the third quarter and the first 9 months incorporate the planned August 1 implementation of PSE&G's transmission rate settlement. In addition full year forecasted results also reflect PSEG Power cessation of depreciation expense on the fossil assets based upon the move to held to sale accounting treatment in August while otherwise continuing to contribute to consolidated results. We are also reaffirming PSEG's 2022 non-GAAP operating earnings guidance of $3.30 to $3.60 per share. We remain on track to execute on PSE&G's 2021 planned capital spend of $2.7 billion. This spend is part of PSEG's consolidated 5-year $15 billion to $17 billion capital plan, which we still intend to execute without the need to issue new equity offer the opportunity for consistent and sustainable growth in our dividend. Following the close of the peak of the fossil sale, PSEG will be a 90% regulated and predominantly contracted platform of stable carbon-friendly businesses. As we continue to execute on this strategy as well as on the significant financial announcements made in our recent investor conference, we remain fully dedicated to providing our shareholders with the premier opportunity to pursue sustainable growth in earnings and dividends with an industry-leading ESG platform. I'll turn the call over to Dan for more details on our operating results, and we'll make sure -- make myself available for your questions after his remarks.

Great. Thank you, Ralph, and good morning, everybody. As Ralph said, PSEG reported non-GAAP operating earnings for the third quarter of $0.98 per share versus $0.96 per share in last year's third quarter. We provided you with information on Slides 12 and 14 regarding the contribution to non-GAAP operating earnings by business for the quarter and the year-to-date period, and Slides 13 and 15 containing corresponding waterfall charts that take you through the net changes in non-GAAP operating earnings by major business. So now I'll review each company in more detail starting with PSE&G. PSE&G reported net income of $389 million or $0.77 per share for the third quarter of 2021 compared with net income of $313 million or $0.61 per share for the third quarter of 2020. PSE&G's third quarter results rose by $0.16 per share over third quarter 2020 and reflect revenue growth from ongoing capital investments as well as one-time items. Growth in transmission rate base added $0.01 per share for third quarter net income even after incorporating the August 1 implementation of PSE&G's transmission rate settlement, which FERC in October return on equity and our formula rate can 9.9%. Electric margin added $0.02 per share to net income compared to the year ago quarter as the conservation incentive program, combined with energy strong to roll ins more than offset a reduction in weather-normalized volumes. Gas results were $0.04 favorable compared to the year ago quarter, reflecting the absence of the gas weather normalization clause reversal in the third quarter of 2020. O&M expense was $0.01 per share favorable compared to the year ago quarter and nonoperating pension expense was $0.02 per share favorable compared to the third quarter of 2020. Lastly, tax expense was $0.06 favorable compared to the third quarter of 2020, driven by the timing of taxes to reflect PSE&G's lower estimated annual effective tax rate due to higher tax flowbacks in 2021. This impact is expected to reverse next quarter when PSE&G finalize its actual tax rate for the year. Moving to sales for the quarter. The weather for the third quarter of 2021 was 4% warmer than the year ago period and 22% warmer than normal, with significantly higher than normal number of hours at 90 degrees or greater. On a trailing 12-month basis, weather normalized electric sales were flat and gas sales were up nearly 2%. Growth in the number of both electric and gas customers rose by approximately 1.5% each versus the third quarter of 2020. Ralph mentioned earlier, the stabilizing impact of the conservation incentive program, now fully in effect for both electric and gas margins, resetting those margins to a baseline level. Going forward, about 95% of our electric distribution, 90% of gas distribution will be stabilized via this mechanism, which will still pass through the variation in the actual number of customers. PSE&G's capital program remains on schedule. PSE&G invested approximately $670 million in the third quarter aggregating to $1.95 billion year-to-date through September. This capital is part of 2021's $2.7 billion electric and gas capital program to upgrade transmission and distribution infrastructure, enhance reliability and increase resiliency. We continue to forecast that over 90% of PSEG's planned capital investment will be directed to the utility over the 2021 to 2025 time frame. We have raised PSE&G's forecast of net income for 2021 to $1.430 billion to $1.480 billion from $1.420 billion to $1.470 billion. Now moving to Power. Power reported a net loss of $1.933 billion or $3.84 per share for the third quarter of 2021, non-GAAP operating earnings of $119 million or $0.23 per share and non-GAAP adjusted EBITDA of $237 million. This compares to the third quarter 2020 net income of $254 million or $0.51 per share, non-GAAP operating earnings of $167 million or $0.33 per share and non-GAAP adjusted EBITDA of $349 million. Non-GAAP adjusted EBITDA excludes the same items from non-GAAP operating earnings measure as well as income tax expense, interest expense, depreciation and amortization expense and the benefit of net operating loss purchases, which are included in net income. The earnings release on Slide 23 provide you with a detailed analysis of the items having an impact on PSEG Power's non-GAAP operating earnings relative to net income year-over-quarter. We've also provided you with more detail on generation for the quarter and for the year-to-date 2021 on Slide 24. Power's third quarter non-GAAP operating earnings were $0.10 per share lower than third quarter 2020 results. The recontracting and tire market impacts reduced results by $0.11 per share as the seasonal shape of hedging activity and higher cost to serve load versus the year ago quarter lower gross margin. The sale of the solar source portfolio earlier in the year also lowered gross margin results by $0.02 compared to the year ago quarter. The retirement of Bridgeport over 3 on May 31 and Power's last call unit lowered New England capacity revenues by $0.01 per share versus the third quarter of 2020. And gas operations were lower by $0.02 per share, reflecting the absence of a pipeline recon received in last year's third quarter. O&M expense lowered results by $0.01 per share compared to the year ago quarter as higher nuclear costs were partly offset by lower solar expenses and lower depreciation expense associated with fossil assets moving to held-for-sale accounting status and the sale of the solar source portfolio and the early retirement of Bridgeport Harbor, combined with lower interest expense to add $0.08 per share versus the year ago quarter. Lastly, taxes and other items were paying per share unfavorable compared to the third quarter of 2020. Gross margin in the third quarter of 2021 was $28 a megawatt hour compared to $33 a megawatt hour for the last year's third quarter. This decline reflects the seasonal price impact of recontracting, including the third quarter's anticipated higher portion of the $2 per megawatt hour annualized price decline in the hedged portfolio. We expect recontracting results in the fourth quarter of 2021 to moderate from Q3 levels. Now let's turn to PSEG Power's operations, with total generation output of 14.9 terawatt hours matched the output of third quarter 2020. Power's combined cycle fleet produced 6.8 terawatt hours of output in response to higher market prices. The nuclear fleet operated at an average capacity factor of 94.8% for the quarter, producing 8.1 terawatt hours, which represent 54% of total generation. For the balance of '21, total baseload and combined cycle generation is forecasted to be 12 to 14 terawatt hours, hedged 85% to 90% at an average price of $32 per megawatt hour. Power's third quarter activity included the announcement of the fossil sale to ArcLight in August of this year. As previously mentioned, PSEG fossil's assets have been reclassified to held for sale as of the date of the sale of the announcement. This change has prompted the cessation of depreciation and amortization expense for these held-for-sale units and resulted in a favorable impact to GAAP and non-GAAP operating earnings through the close of the sale and contributed to the increase of our 2021 full year non-GAAP operating earnings guidance. Power has raised the forecast for its non-GAAP operating earnings for 2021 to $365 million to $440 million from $350 million to $425 million. Our estimate of non-GAAP adjusted EBITDA has also been raised to $870 million to $970 million from $850 million to $950 million. Now let me briefly address operating results for Enterprise and Other, where for the third quarter, we reported a net loss of $20 million or $0.03 per share compared to net income of $8 million or $0.02 per share for the third quarter of 2020. The non-GAAP operating loss for the third quarter was $13 million or $0.02 per share compared to non-GAAP operating earnings of $8 million or $0.02 per share for the third quarter of 2020. Results this quarter reflected higher tax and O&M expenses at the parent versus the year ago period. For 2021, the forecast of Enterprise and Other is unchanged at a non-GAAP operating loss of $20 million. From a financial standpoint at September 30, we had approximately $3 billion of available liquidity as well as cash and cash equivalents of $1.8 billion and debt represented 58% of our consolidated capital. PSEG Power had net cash collateral postings of $999 million at September 30 related to out-of-the-money hedge positions resulting from higher energy prices during the third quarter of 2021. It's been several years since the sustained rise in power prices has caused collateral postings of this magnitude. Our liquidity and cash position are ample and capable of accommodating additional cash collateral postings if necessary. Overall, our ratable hedging program remains an effective risk management tool that we implement over a rolling 3-year period, which smooths volatility in earnings through the averaging of forward sales and importantly locks in gross margin. Turning to financings during the quarter. In August, PSE&G issued $425 million of 1.9% secured medium-term notes due 2031. Also in August, PSEG entered into a $1.25 billion 364-day variable rate term loan agreement. In September, Power and after retirement of its 3 senior notes totaling $1.4 billion on October 8. These remaining notes were retired at a redemption price that included a make-whole premium of approximately $294 million. Following the retirement of all of its debt, PSEG Power's 8.625% senior notes due 2031 were delisted from the New York Stock Exchange effective October '18. Because PSEG Power no longer has any registered securities outstanding, we'll go through a process to terminate status of the SEC registrant. In October, Moody's lowered the credit ratings of PSE&G, PSEG Power and PSEG. The current senior secured ratings of PSE&G, are A1, A at Moody's, S&P, respectively, with stable credit outlooks from both agencies. PSEG's senior unsecured credit ratings and PSEG Power's issuer credit ratings Baa2, BBB at Moody's and S&P, respectively, also with stable outlooks from both agencies. As we outlined during the investor conference, we raised PSEG's 2021 to 2025 capital program by $1 billion to a range of $15 billion to $17 billion. We continue to anticipate execution of this 5-year capital program without the need to issue new equity as we continue to offer a compelling shareholder dividend, with the opportunity for consistent and sustainable growth. And as Ralph mentioned, we've raised our 2021 guidance of non-GAAP operating earnings for the full year to $3.55 to $3.70 per share based on solid results year-to-date and the benefit from cessation of depreciation on fossil assets. We also accounting the initial 2022 non-GAAP operating earnings guidance of $3.30 to $3.60 per share that we provided at the investor conference on September 27. That concludes my remarks, and Jesse. Ralph and I are ready to take questions.

Speakers, our first question is from Jeremy Tonet of JPMorgan.

Just want to start off with the nuclear PTC, if I could. Just wondered if you might be able to talk a little bit more about the type of support you're seeing there, confidence that it makes it through to the end. And if it does, maybe just kind of the impact on your business helping derisk. And if there's any possible benefit the agencies could see could have a positive reaction here if this does go all the way through.

Jeremy, yes, so I feel very good about the bipartisan nature of the support from PTC. I would be less than candid if I didn't express some concerns and hesitation about the overriding piece of legislation to which it's attached. So the debate that's taking place, as you know, is around 2 separate pieces of legislation. One is a roughly $1 trillion bipartisan bill. So the PTC is not part of that then there's, depending upon what price accounts you believe, a $1.75 trillion to $1.85 trillion bill that is not bipartisan that is requiring reconciliation rules and full Democratic party support to get through. But the nuclear component has not attracted any controversy whatsoever. I believe the estimates in that bill is that there's about $550 billion of that legislation dedicated to climate mitigation. And it's widespread recognition that if we're going to make progress, it's got to be based upon the existing nuclear fleet still being around upon which to build that progress. So the House version has an 8 year PTC. Roughly speaking, it targets all-in $15 per megawatt hour of tax credits starting with energy prices of $25 per megawatt hour or less. And then there's a declining scale of the PTC benefit as market revenues climb above $25 per megawatt hour where every dollar above that level, $0.80 of PTC is removed. It kind of gets you to a $40 per megawatt hour or so outcome. There's a pre and post tax adjustment that needs to be mixed in that but for simplicity's sake. So it's really, I think, great news. And I think just today, for example, President Biden announced an SMR development project in Romania that's going to be done with new scale. You should check the press accounts on that. I don't want to speak for others. But it's just indicative of the support that nuclear is gaining in recognition of the pretty aggressive carbon reduction goals that need to be achieved.

Yes, Jeremy, the other part of your question was how the rating agencies will look at it. And clearly, longer term support for nuclear is going to be much more valuable and much more stabilizing than something on a shorter term basis. And that's something that we've been pretty vocal about for quite some time. And so I think that's a positive as well. The number of years that's been tied into the PTC has moved around a little bit, ralph mentioned earlier, 8-year period. So we'll see where it goes. But I do think that what you have seen is increasing support, I think, universally, both we saw it initially in New Jersey as we went through the ZEC process and I think folks are getting on board in Washington as well.

I don't want to beat it to death, Jeremy, but in addition to the emphasizing our forward looking statements, I would just remind you what the history of ITC and PTC have been. They've all had 5- and 10-year life spans that have been renewed for multiple decades. So I'm not at all worried about the 8-year PTC. By the way, I do want to add one other thing that's happening at COP26 right now that's great news for us is that there is a growing consensus around a 30% reduction in methane by the year 2030. There's an article written today by Fred Krupp of EDF in the Wall Street Journal highlighting the importance of methane reduction. And that is just incredibly supportive of our Gas System Modernization Program and continued funding for that and expansion of that. So I think between nuclear, offshore wind and methane reduction, we're really quite well positioned for some important investments going forward.

Got it. That's very helpful. Maybe switching gears here a bit. As we look to the 4Q update and kind of the narrowing of the 22% range, can you give us a little bit more color on some of the items that have been coming in kind of ahead of plan this year and how to think about those items if they're sustainable into 2022, and this is excluding the Fossil sale impact?

Yes. I think rather than sort of front running our own guidance, just by way of reminder, we do expect to narrow that and the real variability is around the pension. Equity markets have been strong. Interest rates have been low. They work against each other in terms of our projected benefit obligation at year end. But I don't think we want to go further than that at this point in time, Jeremy.

Got it. Just wanted to try. Appreciate that. And maybe last one, if I could here. Just thinking through the potential changes at FERC and returned to a full commission. Can you frame some of your expectations moving forward both as we think about the transmission items out there in the future of the MOPR?

Yes. Well, in terms of future of the MOPR, that's -- that candidly become less of a concern for us if they announce sale. I mean energy revenues are really the primary consideration for nuclear plants. That's not to say that were completely disregard capacity revenues for our nuclear fleet. Having said that, our units have not needed to be mitigated according to the IMM. So they should be able to compete in that capacity market whatever that ends up being in the future. I'd say the other changes at FERC that we're eagerly anticipating is the recognition of the importance of transmission investment to carbon mitigation. That's a little bit of a head scratcher when you think about some of the mentioned earlier this year, about reducing the RTO adder for a transmission ROE, which seems to have quieted down right now and has given way to the ANOPR, the Advance Notice of Proposed Rulemaking, which is looking at transmission planning on a much more comprehensive basis. So I just think at a high level, the things that are being discussed and taken up are favorable to our business, both in terms of nuclear being able to participate in capacity markets, states being able to make renewable energy decisions, free of penalties from the prior version of the MOPR, which is important to state like New Jersey, where people otherwise would have been paying twice for offshore wind capacity, which would have significant crimping of the headroom on the utility bill, which now we don't have to worry about as much.

Next question is from Julien Dumoulin-Smith of Bank of America. Julien Dumoulin-Smith: If I can keep going with Jeremy's thought process here on reconciliation and prospects. I wanted to just focus a little bit more on some of the complementary nature of nuclear and specifically hydrogen here. I mean as you see the magnitude of that potential subsidy here and the opportunities afforded therein, how are you thinking about that being a complement to your current nuclear portfolio and strategy, understanding there's all sorts of different nuances here, but would be curious to hear these as you stand here today and assuming there is something that stays the course, how could or does this fit into a future strategy?

So we're closely monitoring the progress of hydrogen, Julien, but to your point, I mean, the value of it, to nuclear would be the ability to avoid any cycling of the nuclear plants and being able to then yield to the lack of dispatchability of renewables and then to just continue the base load operations in nuclear, where in some cases, the offtaker might be an electrolysis project or some other hydrogen creation. And there's a hearing, I think, this week or next week in the Senate on alternate sources of nuclear power in terms of its applicability to the health sciences and medical fields. So I think there's just a growing recognition of nuclear as a carbon mitigant and the multiple ways that we need to act to keep it around and keep it vibrant, whether it's a PTC or source for hydrogen creation or medical science. I no means want to be a skunk in the party, though I do think that there needs to be much more conversation around the safety of large scale hydrogen generation than we're seeing right now in various forms. That's an engineering challenge. But as with other engineering challenges, I'm sure there are solutions, but that does need to be discussed much more prominently than it's getting attention right now. Julien Dumoulin-Smith: And maybe related to this, if I can, how are you thinking about just hedging? I heard your comments on collateral postings earlier, but how are you thinking about taking advantage of the current commodity deck and/or, frankly, any other, should we say, long term contracting opportunities that might be arising, whether that's crypto or data centers looking above and beyond hydrogen opportunities. I mean, certainly, we haven't seen this robust, as you say, a commodity environment in sometime.

Yes. Julien, I think some of the crypto stuff is a little bit more niche opportunities. I think you should think about what we're doing as being aligned with what we've talked about in the past. I mean we still think that a multiyear hedging program for baseload power, such as nuclear, does make sense. What you saw within some of the numbers that we provided aligned very closely to if you were to just step back over time and take a look at where forward prices have been for the years that we've hedged and take a look at those hedge prices. It's consistent with exactly what we have told you that we have done on that front. That said, we have always talked a little bit too about the fact that while that's a general range, there is a little bit of a range around what we can hedge as we go through those times. And so in times like what we've seen more recently, there's been a little bit more activity to try to capture some of those prices. But if you think about it over the long run and over a 3-year hedging period, you're not going to be able to move the needle that much with respect to what's been done on the nearer term. And as you step out, while prices are a little bit backwardated, there's maybe a little bit less of an opportunity, you're into a little bit of a challenge on liquidity. So will we seek to capture some of these higher prices? Absolutely. But should you anticipate that it's going to have a very big move on the needle? I think, against the backdrop of a base of hedges that we have and the backwardation and some liquidity challenges on the back end, it will be more moderated of an impact.

Next question is from Shar Pourrez of Guggenheim Partners.

So Ralph, just not to beat a dead horse, but just starting on the nuclear side for SEC. And you obviously, you highlighted the PTC opportunities and potential upside from federal nuclear incentives. I'm just curious, over the long term, right, as you're thinking about the portfolio, could sort of federal policy, can that change your view on keeping these assets over the long term? Or could there still be a better steward of your nuclear capital as you move towards becoming essentially a pure wires business with offshore wind optionality?

Sure, sure. No, it's a fair question. And it's really TBD. I think the more we can make the nuclear fleet look like a regulated asset, some combination of predictable cash flows. My sense then is that would be something that investors would view more consistently within the predictable earning streams of our regulated business. But I think what we'll do is we'll let investors tell us, right? We'll -- I've not been quiet about the fact that I think given our strength of our balance sheet, the security of our dividend, the lack of a need for equity, the growth in our rate base, the regulatory relations we have, I think we're premium utility. It's not showing up in our valuation yet. So we'll get there. And then the question will be, is nuclear an adder to that ESG profile, which further enhances our premium status or not? And we'll be guided by how our investors view that. But our number one objective is, first of all, safe nuclear operations. We've achieved that. Our #2 objective is long term economic viability of those plants. I think we're on the cusp of that. And then we'll be able to better answer the important question that you raised. I'm not trying to duck it. I just rest assured, it's foremost in our thinking too.

No, no, I think that's a fair point. I mean that's a paraphrase. It's obviously more to come and you are sensitive to help, I guess, investors ascribe value to these assets and whether there is a terminal. Okay. Perfect. That was the first question. And then just lastly, as we're thinking about the strong performance in '21, are you starting to see some O&M flex being carried into '22, i.e., do you have sort of that ability to prefund some of the work going into the tail end of '21 that creates some contingency to execute in '22 as we're thinking about bridging from '21 being a relatively strong year into '22?

Well, so there's always a little bit on the margin, but it's not. I mean, the last thing you want to do to massive work management plans is uphand them and stand them on their head, right? So you would not change a nuclear fueling outage plan. You wouldn't change major maintenance on large transmission assets. Can you move some tree trimming up because the first frost hasn't hit? Yes, you can, but you're still on a 4-year cycle. So there's some incremental stuff you can do, but not big items.

Next question is from Durgesh Chopra of Evercore ISI.

Just you mentioned -- I just want a little bit more clarity on the proposals that you submitted with the BPU and PJM in conjunction. Are those transmission solutions? Or is it a combination of some offshore wind with transmission?

So they're both. They're primarily offshore wind to, first of all, create a grid out in the ocean that connects the 7.5 gigawatts that are planned. Secondly, to bring that on to land. And third is the upgrades that are needed on land to support this injection of new supply. But it's dominated by the assumption that there will be an additional 4 gigawatts of off-shore wind developed in New Jersey.

But just for clarity to guess that they are both on land and at sea, but the proposals are not both generation and transmission. It is only a transmission solution. And so New Jersey is about halfway through the awards that they've had towards their goal of 7,500 megawatts of the actual generation of the turbines. And so this is essentially an effort to seek -- getting that power back to shore. So it is not incremental generation that this effort that the BPU in conjunction with PJM is pursuing. It is just a transmission solution, but it's both at sea and on land.

Perfect. I appreciate that clarity. So it is regulated transmission, but it's a combination of onshore and offshore. Can you size that for us? How, again, in -- Ralph, you've previously talked about a 9-figure number in terms of transmission investment opportunities. What are we talking about in terms of size with these proposals? And when could we see you layer these projects into your CapEx plan, if approved?

Yes. So it's no longer 9 figures, it's now 10. And the schedule has not been carved in stone, but what's been said by PJM is that they would expect to make their technical assessment known to the New Jersey BPU sometime late in Q1, early Q2 next year. The BPU said that they will probably take 6 months to evaluate that. And therefore, it would not be decided prior to Q3, but they are motivated to try to make a decision before Q4 because the next solicitation of offshore wind farms as the supply piece are due at the end of next year. So the hope would be that whoever is bidding an offshore wind farm for the next tranche would have the benefit of knowing what transmission resources would be available to them.

Got it. So it sounds like Q4 -- and then any sort of guidance on capital dollars or rate base we might be looking at with these opportunities or these initial opportunities rather?

They range in size. And as I said, it is 10 figures. It doesn't round to 11. It would stay in the 10-figure range. But it really does depend on which or how many. If that were the case of our proposals, the BPU and PJM were to embrace.

Yes. The only other thing I would mention, too, that may be helpful, Durgesh, is that if you think about the timing for the capital, this would run towards the back half of the decade from an in-service perspective. So if you're kind of in the 2028, 2029-ish kind of a time frame for in-service, you're going to see some of that capital come in over a somewhat longer period of time.

Next question is from Paul Patterson of Glenrock Associates.

Just to sort of follow up on those questions. With respect to the CapEx, as I recall, there was a potential for AFUDC. Is that not still the case for the offshore wind transmission projects?

Yes, there absolutely would be, Paul. Sure.

And so -- and I just was wondering, you got a number of projects, and I realize that it's all sort of very early, but when you've talked about the range, could you give us maybe possibly quantify just a little bit more what the range from the low end to the high end might be? Or is that just too early?

Are you talking about from the standpoint of investment potential?

Yes.

Yes. I mean I think it is a little hard to tell by virtue of a couple of things. One, it's just recently submitted and Ralph gave you the time line for when we'll start to get a determination. We feel very good about our proposals, but it's unknown exactly what's going to come back. And on top of that, there are a series of different proposals that are out there. And so the prospect of all of them actually being part of the solution is unlikely. And so you're going to get piece parts and you don't know what they're going to do from the standpoint of magnitude of bidder. So I think it's early. It's just a little bit tough to gauge. I do think -- as I said, I think we have a solid position with respect to what we have submitted. But that said, it's tough to tell exactly where they're going to go with the solutions they see and how wide they may distribute.

Have you seen proposals from other parties so far?

We have not seen other's proposals. What we have seen is that the magnitude of proposals that are in, if I'm not mistaken, I think the number was 79 proposals, 79 players that are involved, we submitted ourselves 9 different proposals. So that gives you just an indication as to there's a lot of potential different ways to get at what the problem that they are trying to solve is. And so they will have to analyze all that, both from a technical, from a cost, from an ongoing operations standpoint to make their determination.

And then with respect to the technical assessment that PJM is going to be making, do you know if that's going to be just simply given to the BPU? Or is that going to be more widely provided to people like us?

I suspect it will be just given to the BPU because the BPU is a decision maker here. And whether or not to be BPU makes that public or not remains to be seen. I mean, typically, the Board doesn't reveal the detailed scoring of its assessment of projects, they just announce the winners.

Next question is from David Arcaro of Morgan Stanley.

Let's see, posted a good customer growth this quarter, 1.5% in electric and gas. I was wondering if you could remind us kind of how that compares to your longer term assumptions for the increase in customer count over time?

It's comparable. I think we're in that range. We may be just a hair below that on an ongoing basis. I think it's kind of been around 1%. It's something that we do update on a regular basis based upon the data that we get regularly. But certainly, it's a little bit lower than that, but we do see customer growth going on into the future.

Okay. Got it. That's helpful. And then I was wondering if you could just talk about heading into the winter here for the gas business with what we've seen in natural gas prices do. Could you talk about the pressure on the customer bill heading into the winter, maybe how you have been hedged into the winter heating season? And anything, any kind of relief or strategy that you're pursuing for managing that customer bill increase here over the next couple of months?

Yes. So David, I think that the mechanisms that are in place are there and do protect the customer pretty well, both on the electric and the gas side because obviously, when gas prices go up, you see the effect on the electric prices. And so what we have and we actually referred to within our remarks is an ability to put forth a 5% increase on the commodity component of the bill 2x during the year. And so there's a -- because of some timing and some kind of a technical aspect to work through, the utilities in the state are looking through the ability to do that. So you can think about that on the gas side has been 5% and 5% is on just the supply side of things that you may end up seeing. And then most customers, I think on the electric side, the best model to think about is the provider of last resort contract for BGS. And so what folks are paying now are prices that were established this past February, the February before and the February before that, on a 1/3, 1/3, 1/3 basis. And so nothing will change from the residential standpoint until we get to next year. and the auction that will come this February will get put in place next June. What will get put in place is for 1/3 that will roll off and the remaining 2/3 will be sticky from the prior 2 auctions. So that has a mitigating effect as well. That mechanism has a mediating effect as does the fact that if you think about some of the most current prices on the electric side, they are higher for the current year, for the upcoming year than they are for the following couple of years. We've got a backwardated curve. And so that auction in February will cover 3 years forward, which will have a higher price year for 2022, if you just look at the forwards and then lower as you go into '23 and '24. All to say that, that also has a very moderating effect how this stuff will ultimately flow through to the customer bill. So if we are in a position where prices like we're seeing now are sustained for the longer term. Obviously, that would all work its way down to the retail customer. But if anything is shorter lived, you're going to see less of an impact because of those mechanisms that I described.

Next question is from Michael Lapides of Goldman Sachs.

I want to come back to the transmission for offshore wind. Your proposal is both for an offshore and onshore component, I think, I'm not entirely sure I understand that. When I think about the onshore component, does the utility where the substations are -- where the plants are being landed effectively where the -- the substation where the capacity is first hitting onshore. Is that the utility that probably has a competitive advantage for the approval or the grant to build out the onshore transmission?

Yes, Michael. So we put forward a series of proposals that can be used in a comprehensive manner. They wouldn't need all of our proposals as there are alternative options that are in there, and they can also be mixed and matched with proposals made by others. So we tried to create as robust of options for PJM and the BPU as was possible. Now the short answer to your specific questions, yes, there are some onshore advantages to being the landing point from a right of way point of view as an example. But beyond that, it's really just a question of what are the path lengths, what are your relationships with suppliers and your ability to manage the work and be cost competitive. And what those right of ways look like with respect to environmental permits and other issues that will come up. So I guess, technically, the short answer is yes, there are some advantages, but they, by no means, assure victory for whoever is at substation .

Next question is from Jonathan Arnold of Vertical Research.

Quick hedging question. In the disclosure, you say that 90% of the gross margin for '22 is locked in via energy capacity in ZEC's. I'm just curious whether then the percentages and prices that you then give for '22, '23 and '24 are on that basis? Or is that just energy?

From ...

When you then say 90% 29 -- for '22, 75% to 80% for '23. Are those sort of on a full gross margin basis? Or are those just the percentage of the base load output?

Now I got it. Yes, yes. They are energy based, Jon, energy based ...

We don't have the capacity options for some of the outer years, right.

That number is really just a look at energy rather than energy and capacity? Is that ...

You got it. That is correct, yes.

Thank you, participants. That is all the time we have for questions. Mr. Izzo, Mr. Cregg, you may now continue with your closing remarks.

Great. Thank you, Jesse. So thanks, everyone, for joining us today. I know that we'll see a bunch of you in the EEI, Dan and Carlotta, Brian and Ralph LaRossa will be with you in warm and sunny Florida. I am off to chilly and drizzly Glasgow, although I'm looking forward to. I think there's some important things to be done there. We'll be arguing and helping the administration argue for significant reductions in carbon and significant support for all the things that we are advocates of from energy efficiency to offshore wind and nuclear and a variety of other things, including methane reduction. So I will miss you there, but I catch up with many of you at upcoming virtual conferences. So thanks again for joining us today. Take care.

Ladies and gentlemen, that concludes your conference call for today. Thank you all for participating. You may now disconnect.