公共服務電力與天然氣 (PEG) 2022 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by. My name is Ludy, and I am your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group First Quarter 2022 Earnings Conference Call and Webcast. (Operator Instructions) And as a reminder, this conference call is being recorded, today, May 3, 2022 and will be made available 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 thank you for participating in our earnings call. PSEG's first quarter 2022 earnings release, attachments and slides detailing operating results by company are posted on our IR website located at www.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, which differs from net 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 will now turn the call over to Ralph Izzo, Chair, 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, Carlotta. Good morning, everyone, and thanks for joining us for a review of PSEG's first quarter results. PSEG reported a GAAP net loss of under $0.01 per share, resulting predominantly from mark-to-market adjustments related to higher energy prices versus our existing forward sale contracts. We exclude these items in calculating PSEG's non-GAAP operating earnings, which were $1.33 per share for the first quarter of 2022. For the first quarter of 2021, PSEG reported $1.28 per share for both net income and non-GAAP operating earnings. And just a reminder that first quarter 2021 included the results from our divested Fossil Assets and Solar Source.

Our non-GAAP results for the first quarter of '22 reflect solid utility and nuclear operations. That foundation, combined with rate base growth from regulated investments, as well as lower costs resulting from the completed sale of PSEG Fossil, offset lower capacity and re-contracting this quarter. Regulated operations at PSE&G continue to benefit from our ongoing investments in energy infrastructure and clean energy, increasing first quarter '22 earnings per share by over 7% above first quarter 2021 results.

And following the February fossil sale close, we are reporting results from our nonutility activities under the heading Carbon-Free Infrastructure and Other or CFIO. For the first quarter of 2022, CFIO reported a net loss of $1.02 per share, driven by these same mark-to-market adjustments and non-GAAP operating earnings of $0.32 per share. This compares with $0.34 per share for both net income and non-GAAP operating earnings for the first quarter of 2021, which once again included results from the divested fossil assets.

Slide 11 details these results for the quarter. PSE&G's customer satisfaction scores reflect our commitment to safe and reliable service, achieving top quartile performance in all 6 factors of measurement among large utilities in the East in the JD Power first quarter 2022 residential electric study. The statewide moratorium on shutoffs for residential electric and gas service was lifted in mid-March.

In late March, New Jersey passed legislation that provides protection from shutoffs to customers who have applied for payment assistance programs by June 15, 2022. Customers who apply for assistance will be protected from shutoffs while awaiting their application determination. PSE&G in partnership with the New Jersey Board of Public Utilities and Community Groups has stepped up the efforts to help customers in arrears enrolled in the readily available payment assistance programs, such as USF and Lihuap, as well as providing deferred payment arrangements. We recognize the continued economic strain that the pandemic has brought to many of our customers and we will continue to work with empathy as we conduct our collection efforts.

We continue to make progress on our infrastructure advancement program, a proposed 4-year investment in the last mile of our electric distribution system to address aging substations and gas metering and regulating stations and to integrate electric vehicle charging infrastructure at our facilities to support the electrification of PSE&G's vehicle fleet. The discovery phase responding to inquiries from BPU staff and Rate Counsel is coming to a conclusion and confidential settlement discussions are scheduled to begin within the next week. We continue to expect based on the current procedural schedule that final BPU action will take place this fall.

With the Fossil sale completed on February 23, PSEG will continue to focus on regulated growth, empowering a future where people use less energy, it's cleaner, safer and delivered more reliably than ever before. As you know, last September, PSEG committed to the United Nations backed Race to Zero campaign, pledging to develop and submit our emission reduction goals consistent with the objectives of the Paris Agreement to limit global temperature increases to 1.5-degree Celsius or less, what are known as science-based targets.

Slides 5 and 6 detail our 5-year $15 billion to $17 billion of capital spending program and show the spending in various categories, the majority of which supports our business ambition for 1.5 degrees either through direct carbon emissions reductions, energy efficiency or climate adaptation. The business ambition for 1.5 degrees includes our net zero by 2030 goals as well as keeping our emissions targets across all 3 scopes within the 1.5 degree limit consistent with the Paris agreement.

Essentially, the business ambition for 1.5 degrees C will use science to validate PSEG's net zero commitments to inform needed investments and our resulting growth opportunities. We are fully engaged in developing our plans, staff with technical advisers and internal teams that are preparing to submit our targets to the science-based target initiative by the end of this year, which is well ahead of the fall '23 timeframe required. Based on our initial carbon inventory, our Scope 1 and Scope 2 emissions comprised roughly 15% of our total carbon emissions. Our challenge, one that we embrace, is to address our largest emissions category, which falls under Scope 3, the largely downstream customer use of our energy products that also includes the emissions profiles of our upstream suppliers.

Our various capital programs support our Climate Vision and net zero 2030 goals by addressing decarbonization with gas infrastructure replacement, expanding our energy efficiency programs, which can also lower customer bills, integrating climate adaptation and resiliency design into our systems, supporting the electrification of transportation, preserving carbon-free nuclear generation and investing in offshore wind infrastructure in addition to our base spending.

With an improved business mix and an already compelling environmental, social and governance profile, we are confident that we are creating shareholder value by growing our rate base in alignment with New Jersey's clean energy goals as well as our business ambition for 1.5 degrees Centigrade, helping to enable a lower carbon and competitive New Jersey economy.

Over the past several weeks and months, energy prices have risen to levels not seen or sustained in many years. Utility customers around the country have been experiencing commodity price increases in their electric and natural gas bills for the first time in a decade. PSE&G's customers have benefited from the price moderating effects of New Jersey's electric and gas default supply mechanisms, better known as Basic Generation Service or BGS and Basic Gas Supply Service or BGSS.

On the electric side, PSE&G contracts with its expected BGS load on a 3-year rolling basis. And each year, one-third of the load is procured for a 3-year period. When the new BGS rate goes into effect this June 1, electric bills will actually decline by 2.8%, owing to a significant reduction in actual versus assumed PJM capacity costs. On the gas side, the BPU permits PSE&G to recover the cost of natural gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Each June, we make a filing for our anticipated BGSS cost to go into effect in rates before the upcoming winter season. And that filing will be driven by market prices at that time and then chewed up for actual costs over time.

On the nuclear side of the business, we are essentially fully hedged in 2022 and 2023 and approximately 50% hedged in 2024. While the energy price increase is helpful to nuclear in the long term, we continue to monitor pricing together with impacts from rising interest rates, adverse financial market conditions impacting future returns for our pension trust, as well as general inflationary pressure in the broader economy covering labor and supply chain materials. Collective of these factors, we remain confident in our multiyear 5% to 7% EPS CAGR to 2025.

On a related note, we have seen a positive shift in public sentiment in support of nuclear power and its carbon-free energy security attributes since the Russian invasion of Ukraine. And we remain hopeful that a tax incentive to preserve the economic viability of nuclear generation can be passed in Washington that provides a floor price needed to sustain these carbon-free resources over the long term.

The Department of Energy recently opened its first funding window to help struggling nuclear plants with the civilian nuclear program. None of our nuclear units qualified for DOE funding under the initial criteria. We will endeavor to obtain the maximum benefit for our nuclear units from the DOE program should we qualify in future rounds. However, we do not believe that the DOE grant program provides sufficient revenue stability or visibility needed to make longer-dated fuel and license extension decisions.

In late February, the Nuclear Regulatory Commission, the NRC, reversed the previously granted subsequent license renewal for peach bottom units 2 and 3. The NRC is requesting an updated environmental review that addresses the impacts of extending the operating licenses by 20 years. In the interim, the NRC has rolled back the license expiration dates for peach bottom units 2 and 3 to 2033 and 2034 respectively.

Moving to offshore wind. The New Jersey BPU hosted a series of 4 public meetings in March and April as part of its ongoing evaluation of bids submitted in its offshore wind transmission solicitation, better known as the state agreement approach or SAA process. The meeting solicited public input on topics, including integration with offshore wind generation projects, environmental effects, permitting and rate payer protections and cost controls.

We participated in each of the 4 public meetings to advocate for our submissions and submitted our formal comments to the BPU on April 29 in support of our coastal wind link partnership with Orsted. The solutions we submitted range from single collectors at various landing points to a linked transmission network out in the ocean and could range in an investment opportunity for us from $1 billion to $3 billion if selected.

Now let me turn my attention to guidance for 2022. Our regulated investment programs are producing predictable utility growth and the Conservation Incentive Program or CIP, as we often refer to it, is effectively minimizing variations on electric and gas revenues from the rollout of our energy efficiency programs and other impacts, including weather. We are on track to execute PSE&G's $2.9 billion 2022 capital spending plan, which is part of PSEG's 5-year $15 billion to $17 billion capital plan through the year 2025. Over 90% of this capital program is directed toward PSE&G and is expected to produce a 6% to 7.5% compound annual growth rate in rate base over the '22 to '25 period, starting from a year-end 2021 rate base of approximately $25 billion.

While the first quarter results reflect a lower regulated contribution than the 90% we outlined at our September 2021 investor conference, this is due to the favorable first half of 2022 cost comparisons at CFIO operations from divestiture activity. Dan will go into more detail on those drivers during his review. Nonetheless, we continue to see the full year shaping up consistent with our 2022 non-GAAP operating earnings guidance of $3.35 to $3.55 per share, and for each of PSE&G and CFIO. As I said a moment ago, we continue on track for our multiyear EPS growth rate of 5% to 7% from the 2022 guidance midpoint to 2025.

Now let me wrap up my comments by mentioning to you what you've all heard by now that I will be retiring as CEO and President of PSEG on September 1, but I will stay on as Executive Chair of the Board until the end of the year. As part of a planned leadership succession, the PSEG Board of Directors has elected Ralph LaRossa to be the next President and Chief Executive Officer, effective September 1, and Ralph will then assume any additional responsibilities of Chair of the Board in the new year. Most of you are familiar with Ralph and his incredible operating experience that has guided PSE&G and our generating business over the course of my tenure as CEO. I have every confidence that the other Ralph, as we often refer to him, will continue the strong heritage of this 119-year-old organization and lead its bright future.

I'll now turn the call over to Dan for more details on our operating results and we'll be available for your questions after his remarks.

Thank you, Ralph, and good morning, everyone. As Ralph mentioned, for the first quarter of 2022, PSEG reported a net loss of under $0.01 per share, primarily related to the mark-to-market adjustments and non-GAAP operating earnings of $1.33 per share. We provided you with information on Slide 11 regarding the contribution to non-GAAP operating earnings by business for the first quarter of 2022 and Slide 12 contains a waterfall chart that takes you through the net changes quarter-over-quarter in non-GAAP operating earnings by major business.

Let's start with PSE&G. PSEG's first quarter 2022 non-GAAP operating earnings improved by $0.07 per share over the prior year's quarter, reflecting rate base additions from our investment programs in the gas system monetization program and the implementation of the conservation incentive program. Compared to the first quarter of 2021, transmission was $0.03 per share unfavorable reflecting the implementation effective August of 2021 of the settlement agreement of our transmission formula rate, including a lower return on equity, partly offset by growth in rate base.

For distribution, gas margin improved by $0.08 per share over the first quarter of 2021, half of which was driven by the scheduled recovery of investments made under the Gas System Modernization Program with the balance reflecting growth in the number of gas customers and the true-up from the conservation incentive program. Electric margin rose by $0.02 per share compared to the first quarter of 2021, also reflecting a higher number of customers and the implementation of the CIP mechanism. The CIP was not in effect in last year's first quarter for either gas or electric distribution.

Other margin primarily related to appliance service was $0.02 per share favorable compared to the first quarter of 2021. Higher O&M expense was $0.02 per share unfavorable compared with the first quarter of 2021, reflecting timing and various costs. Higher depreciation expense reduced results by $0.01 per share, reflecting higher plant and service. Lower pension expense added $0.01 per share compared to the first quarter of '21. In addition, the impact of PSEG's $500 million share repurchase had a $0.01 per share benefit in the first quarter of 2022.

Flow through taxes and other items had a net unfavorable impact of $0.01 per share compared to the first quarter of '21, but was more favorable than we will see over the remainder of the year, driven by the use of an annual effective tax rate. Winter weather in the first quarter of 2022, measured by heating degree days, was slightly colder than normal. As a result of implementing the CIP, variations in weather, positive or negative, now have a limited impact on electric and gas margins, while enabling the widespread adoption of PSE&G's energy efficiency programs.

For the trailing 12 months ended March 31, weather-normalized electric sales reflected lower residential sales, lower by 4.8% and 3.2% respectively, and higher C&I sales higher by 3.3% and 2.8% respectively as more people return to work outside the home. Growth in the number of electric and gas customers remain positive by approximately 1% during the trailing 12-month period. PSE&G invested $656 million during the first quarter and is on track to execute its planned 2022 capital investment program of $2.9 billion, which includes infrastructure upgrades, transmission and distribution facilities, as well as the continued rollout of the Clean Energy Future investments and energy efficiency, energy cloud or smart meters and the electric vehicle charging station infrastructure. PSE&G's forecast of net income for 2022 is unchanged at $1.51 billion to $1.56 billion.

Moving out to carbon-free infrastructure and other or CFIO, we reported a net loss of $511 million or $1.02 per share for the first quarter of '22 and non-GAAP operating earnings of $163 million or $0.32 per share. This compares to first quarter 2021 net income of $171 million or $0.34 per share and non-GAAP operating earnings of $173 million or $0.34 per share, which included the results of the divested fossil assets. For the first quarter of 2022, electric gross margin declined by $0.27 per share, primarily due to the completed sale of the 6,750 megawatt fossil portfolio in February 2022 and the sale of Solar Source.

This reduction in gross margin also includes re-contracting approximately 8 terawatt hours of nuclear generation at a $3 per megawatt hour lower average price. Higher margins from gas operations of $0.04 per share compared favorably with the year earlier quarter. Year-over-year cost comparisons were better by $0.21 per share due to the divestitures, driven by lower O&M, depreciation and interest expense that will mainly benefit first half 2022 results. The third and fourth quarters of 2021 reflected the sale of Solar Source in June, the cessation of fossil depreciation due to held-for-sale status from August onward and the retirement of PSEG Power's outstanding debt in October.

Taxes and other was favorable to the tune of $0.01 per share versus the first quarter of 2021 and parent activity was $0.01 per share unfavorable, reflecting higher interest expense. I also want to make one point on the NRC decision to revert the peach bottom 2 and 3 licenses to 2023 -- 2033 and 2034 respectively, that Ralph mentioned earlier. Because the NRC anticipates that it will complete its environmental analysis before 2033 and we believe the licenses will be updated to the previously extended lives of 2053 and 2054, PSEG has not adjusted the useful lives of the units and we'll continue to depreciate the assets through that period.

On the operating side, nuclear generating output increased by over 2% to 8.4 terawatt hours, reflecting the absence of the coast down to Oak Creek Spring 2021 refueling. The full availability of Hope Creek during the first quarter of 2022 helped the nuclear fleet operate at a capacity factor of 100% for the first quarter. PSEG is forecasting generation output of 21 to 23 terawatt hours for the remaining quarters of 2022 and has hedged approximately 95% to 100% of this production at an average price of $28 per megawatt hour.

For 2023, PSEG is forecasting nuclear baseload output of 30 to 32 terawatt hours and has hedged 95% to 100% of this output at an average price of $30 per megawatt hour. And for 2024, PSEG is forecasting nuclear-based load output of 29 to 31 terawatt hours and has hedged 50% to 55% of this output at an average price of $31 per megawatt hour. The forecast of non-GAAP operating earnings for carbon-free infrastructure and other is unchanged at $170 million to $220 million for 2022. And this guidance excludes results related to the fossil assets sold in February 2022 as all free cash flow generated in 2022 from the fossil operations prior to closing were translated into an adjustment to the final purchase price.

With respect to financing, in March of 2022, PSEG and PSEG Power consolidated their revolving credit agreements into a master credit facility with total borrowing capacity of $2.75 billion with an initial PSEG sublimit of $1.5 billion and an initial PSEG Power supplement of $1.25 billion. The PSEG sub limit includes sustainability-linked pricing mechanism with potential increases or decreases depending upon performance relative to targeted methane emissions reductions.

In addition, PSE&G expanded its existing revolving credit agreement to provide for $1 billion of credit capacity. Both facilities are extended through March of 2027. As of March 31, PSEG's total available credit capacity was $3.2 billion, in addition to approximately $1.6 billion of cash and short-term investments on PSEG's balance sheet, inclusive of $910 million at PSE&G. As of March 31, our liquidity position reflects the repayment of a $500 million PSEG term loan at maturity in March, repayment of a $750 million PSEG term loan due in May of 2022 and $500 million of capital being returned through share repurchases.

PSEG Power had net cash collateral postings of $1.5 billion at March 31 related to out-of-the-money hedge positions from higher energy prices during the first quarter of 2022. Collateral postings have continued to increase subsequent to March 31 as power prices have continued to rise. At the end of April, PSEG Power had net collateral postings of approximately $2.6 billion. The majority of this collateral relates to hedges in place through the end of 2023 and is expected to return to PSEG Power as it satisfies its obligations under those contracts.

In March of 2022, PSEG Power closed on a $1.25 billion variable rate 3-year term loan to re-lever power after redeeming all long-term debt outstanding prior to the sale of our fossil fleet. At PSE&G, we issued our first green bond in March of 2022, consisting of $500 million of secured medium-term notes due 2032 under PSEG's new sustainable financing framework. And subsequent to March 31, PSEG entered into a $1.5 billion variable rate term loan and PSEG Power closed on LC facilities totaling $200 million.

Lastly, we have successfully implemented our $500 million share repurchase through $250 million of open market purchases, completed earlier in 2022 and an accelerated share repurchase program for the remaining amount that will be completed no later than June of 2022. We are reaffirming PSEG's 2022 non-GAAP operating earnings guidance of $3.35 to $3.55 per share, with regulated operations contributing approximately 90% of the total. For the full year 2022, PSE&G's net income is forecasted at $1.51 billion to $1.56 billion. Non-GAAP operating earnings for CFIO was forecasted at $170 million to $220 million. PSEG's 2022 earnings guidance excludes financial results from the divested fossil assets and includes the additional interest expense related to the recent financings.

That concludes our formal remarks. And with that, we are ready to take your questions.

(Operator Instructions) The first question comes from the line of Nicholas Campanella from Crédit Suisse.

Congrats to Ralph and Ralph. So just on the higher energy prices, great to see customers well insulated via BGS. And I guess just as it translates to your unregulated nuclear business, you're partially open on 24, power prices are higher than where the current hedges are today. I think you mentioned in your prepared remarks that this is helpful to nuclear over the long term. So I'm just curious, like has this changed your thinking or your calculus at all and how you're thinking about the long-term ownership of the nuclear fleet?

No, Nick. So we're sticking by the 3-part plan that we've had in place, which is that what we really want to see is action in Washington or failing net in New Jersey that provides more stability over the long term to the revenue stream that nuclear can expect either through a production tax credit or an emissions credit along the lines of our ZEC. And at that point in time, we'll reach a conclusion as to what the logical long-term positioning of those assets should be, are we the logical owner or somebody else is the logical owner. But we do think current markets might make it easier candidly in Washington to score a production tax credit in terms of the impact on the federal budget. And certainly, that would be helpful in New Jersey to reduce the pressure on New Jersey customers. But we're still right now in that Phase 2 of trying to assess how we can get the long-term solution and eliminate some of the volatility that I know our investors and our fans of in terms of the wholesale power market.

That's great. I appreciate that color. And if I could just shift to offshore wind quick and just the New York Bight auctions, we definitely saw some impressive comps out there now. And just thinking about your unused lease beds, specifically the Garden State JV with Orsted. It's our understanding that the Skipjack award is out there and those lease areas might be potentially used for Skipjack. But I'm just -- a question on just overall kind of commitment to the offshore program in excess of Ocean Wind 1 at this point and how you're thinking about your unused lease bed, if at all?

So we're having multipronged conversations with Orsted. As you know, we still have one more step to go on Ocean Wind 1 in terms of an FID decision. We're waiting to hear back from the BPU on Coastal Wind Link, which we talked about in our remarks. You're right that Orsted cannot build out its expansion of Skipjack without making use of our share or part of our share of the Garden State Offshore Energy lease that we own. When we signed up Ocean Wind 1, we said we weren't going to do that if it was going to be one and done that we wanted to take a look at this market opportunity, which New Jersey is committed to doing 7.5 gigawatts of this and Maryland probably a couple of gigawatts, I think, is their target at this point in time.

But we're looking at the due diligence associated with all these projects and what that means from a return point of view and how that compares with our alternative uses of capital. And rest assured that unless they exceed what the demands are in the regulated utility on a risk-adjusted basis, then we wouldn't go forward. But if they do, then we do think that this is going to be something that policymakers are committed to do, and we want to be able to participate in that.

Got it. That's helpful. I'll leave it there.

The next question comes from the line of Shar Pourreza of Guggenheim Partners.

Ralph, I just want to -- just a quick follow-up on Nick's question around the viability or the longevity of the assets within sort of the portfolio. I guess, I'm trying to get a sense on why would the outcome of a federal PTC or is ZECs kind of be a deciding factor if these assets are logical for you to own them or not? I mean is it -- or is it more of a function of trying to cement the value of the assets post sort of any kind of policy initiatives? I guess, how do we sort of think about these kind of bookends here? That would be helpful because I'm just trying to get a sense on timing and if there's any sort of discussions happening.

I mean so these are really highly performing assets from an operational point of view. If you can come up with an economic construct that makes them look regulated. And by that, I mean, you're basically in the federal PTC, you've essentially set a price of $44 per megawatt hour for the output, right, as it was originally designed. It could be higher than that. Hopefully, people wouldn't complain about that. And it could considerably be lower than that if power prices drop below $15 a megawatt hour, which we haven't seen, you never say never.

So then the question becomes, if you've achieved that kind of earnings or margin stability, you've done 2 things, you've either convinced the market that you are a legitimate and natural owner of the plants and it reflects -- it gets reflected in the valuation, which would be great or you haven't come into the market that you're a natural owner, but you've enhanced the value of those assets for whoever its natural owner is. So since nuclear has gained so much favor in international markets and domestic markets and certainly in New Jersey, why would you lose patience and do something sooner than otherwise and leave value on the table if you're not the natural owner or realize that value if you are the natural owner.

So I pride ourselves on running this company not for the next few weeks, but for the next few decades. And I think we're going to know a lot in the next couple of months in Washington. And then we'll turn our attention to New Jersey, if Washington proves that it's unable to act. But the situation in Ukraine has heightened, concern over natural gas markets and what that means for us is domestic users and what that means for us is LNG exporters. And that has huge implications for the nation's fuel mix for electricity and nuclear has to be a vital part of that. So I think we have some opportunities here, right, to maximize the value of those assets.

Got it. So just -- not to paraphrase, but the topic is really around value accretion for another owner versus trying to emulate a regulated type of return within PSEG with this asset.

No, I think that's the question on the table. Can we fashion a regulated return on those assets through whatever construct we come up with, and I think PGC gives you a shot at that, but we won't be the ones to determine that, that'll be decided in Washington. And failing that, I still think by giving it the kind of predictability and long-term floor price that's envisioned in that, you maximize the value of those plants to whoever the natural owner is.

Got it. Got it. Okay. So a little bit more to come here on that. And then, just maybe a little bit minor, but from sort of the fourth quarter to the 1Q, the volumes, terawatt-hours for the assets, the generation volumes went from 31 to a range of 30 to 32 for '23. Is there kind of a reason there, Ralph, that you're providing a range now versus kind of an absolute number?

We would have thought obviously the plants would be running around the clock except for like a refueling outage. So is there any changes in the planning assumptions there? And then, can we -- let me just get a quick update on the operating strategy for the assets in light of the commodity price moves and the policy uncertainty. So what sort of hedge profile is appropriate to kind of maybe maximize value with these externalities?

So there's 0 change in the expected operating performance of the assets. We kind of thought 31 to 33 was a pretty narrow range that has a target midpoint that shouldn't be a surprise to anyone. And in terms of the hedging profile, we do the 3 years pro ratable and we do give our folks some flexibility depending upon market moves that seem to be a little bit of an outlier or maybe deviating from what the fundamentals might predict. And that's why we're a little bit more heavily hedged than we would normally be 2 years out.

But Dan, I don't know if you want to supplement that, but I'd say no massive change.

Yes, sure. There's no change. I guess, if you think about even in my prepared remarks, I talked a little bit about overall volumes. And as we go into an outage, if we have run very well, as has been recent history throughout the entire run since the last refueling outage, you end up coasting down on the way in. And so, it's those kind of things that can add a little bit of change between what's there, but I think your question was, we said 31, now we said 30 to 32, 31 is dead in that midpoint. So there's really no difference at all. And we're going to operate to be able to continue to have those units on round the clock to be able to capture what's there.

Now we're hedged upfront. And as Ralph said, we look at it over 3 years. These have a little band around that, and if we like where prices are, we can move up a little bit. So we're a little bit north of that if you take a look at where we are in hedges, but don't read anything into a change that says 31 turns to 30 to 32, it's the same midpoint and it just has a little bit of that variability that exists. But it's still -- frankly, it's as much about strong operations and coasting into a refueling outage than anything else.

Okay, terrific. And then, Ralph and Ralph, congrats on Phase 2.

Your next question comes from the line of Jeremy Tonet of JPMorgan.

Sound chipper.

I just want to start off on results here. You talked -- I think you mentioned them being on track. And just wondering if you could walk us through 1Q results to your full-year guidance here, particularly for CFIO. Are you trending toward the high end of the range here at least for that segment? Results seems a bit better than maybe we would have expected there.

Yes, Jeremy, I mean, I think the one thing that I would look at is some of the shape that we have as you look at the year as a whole. We'll have a shift in capacity revenues as we go through the year and those will come off based upon the auctions that we've already seen. We have another auction coming up in about a month or so, we'll get back to a regular process there. But there's that, there's a little bit of tax moving that you see throughout the year as we book to an annual effective tax rate and some of the re-contracting has a little shape to it. So I would say that we reiterated guidance for CFIO and kind of hold just to that [blanket] statement.

Got it. And now that settlement discussions are active for the IAP, how do you see prospects for reaching a broad agreement among stakeholders at this juncture?

Jeremy, the temptation is always to give you a play-by-play, but they are confidential settlement discussions. And I would simply say, look, we go out of our way to pick things that are essential from a reliability point of view and consistent with state policy. But those discussions have just started, and I want to be respectful of the rate council and the BPU staff that they've asked us to treat those confidentially, and I owe that to them.

The next question is from Julien Dumoulin-Smith from Bank of America.

Congratulations on the call at Ralph Square at this time rather than Ralph and Ralph. Congratulations.

There's no end to the abuse we take on this. I just want you to know how hard it was to find another Ralph.

Absolutely. You just had to. But to that point, listen, in the messaging that you just threw out there, with the EPS CAGR range through '25, still intact at 5% to 7%, how do you reconcile that with the current '24 and '25 wholesale forwards given your likely open position in that time period? I mean, what are the offsets here? I mean, are the headwinds from inflation and pension that real to offset this magnitude of upside in what we've seen in the power price environment?

Julien, believe it or not, we actually expected that question. So look, we try to get into the cadence and not change our earnings guidance with every quarterly call for the long-term. So what we'll do is, we'll fill you in on our hedge position. If you want to predict where the market will be tomorrow, that's okay. We just try to ratably hedge in. And in September, we'll have an investor conference, and we'll give you '23 guidance and multi-year guidance at that point. And you'll have the benefit of a few more months of market purchases. But yes, we'd rather not start adjusting our 4-year CAGR or 5-year CAGR with every quarterly call. So -- that's how we justify it.

Completely appreciate that.

I was just going to say, Julien, our sales will kind of be what they are. We'll keep giving you that update. And just a reminder, because as you take a look at some of the prices that you're seeing, you've got some significantly higher prices in the very near-term than you do further out. And so, if you take a look at where the overall complex is, you've got the balance of year '22 and '23 are significantly higher than '24 and '25. And '22 and '23, we are hedged, right? So really the opportunity is with, yes, those higher prices that you've seen in '24 and '25, but not nearly as high as you see in '22 and '23.

Yes. No, I appreciate that anyway. And perhaps related here, if we can speak to it, I mean, how are you thinking about your conversations with the BPU and others in an effort to sort of effectuate a longer term solution? I mean, it seems like a particularly opportunistic moment here to take advantage of the environment to kind of engage in a more wholesome discussion with the state and stakeholders on something that might be more sustainable in the long-term and help provide some derisking to the upside for customers.

I absolutely agree with you, Julien. I just think that forward prices in the market do afford us an opportunity to think about, okay, well, the market on its own sustain nuclear units. And is there an opportunity to move away from this 3-year cycle that really does impair our ability to make any major long-term decisions about capital improvements or license extension or anything of that nature. So the production tax credit type of solution at the federal level, of course, has the tremendous benefit of stabilizing margin while removing the burden on New Jerseyans.

And I do think it's perfectly normal for the state to say, well, let's sort that out, because absent action at the federal level, then we know we have to address the long-term stability of the assets. But what we do in the state could vary depending upon what happens at the federal level. So we don't have to be sequential and wait for an infinite amount of time for the federal government to act. But as you know, there is talk in Washington right now of a climate-only provision and there's talk of that happening sooner rather than later. But you're spot-on, the robustness of the forward price that we're seeing in the market does create an opportunity to stabilize the nuclear units for the long-term.

Right. And I think if I hear you right, the key -- the linchpin here is for the state recognize that you all don't have the visibility you need for the subsequent license extension, which is obviously something that the state would likely be keen towards, but you can't emphasize -- you can't invest given the construct at present?

Yes, that's exactly it. We can't and nor would I expect anybody else could -- if somebody else were to be the logical owner. And it's broader than that, right? I mean, these nuclear plants are terrific, but every once in a while something happens and it's really tough to do a discounted cash flow over 3 years and convince yourself that it's going to pay itself off. So you have to prepare for that possibility.

So -- and there was another study came out recently by Princeton University, which we funded, but their demands for academic independence, I assure you were at the highest level and they clearly articulated that continued operation of those nuclear units was amongst the lowest cost pathways to achieve the state's carbon targets. So I've lost track of how many studies have verified the need for the ongoing operation of those plants beyond their current license life.

The next question is from Durgesh Chopra from Evercore ISI.

My congratulations also to Ralph and Ralph. Just -- I want to go back. I have 2 questions, 1 on offshore wind generation and then a follow-up on the transmission piece of it. Just, Ralph, can you remind us if there's on the Skipjack and Skipjack 2 opportunity, I guess the partnership, the Garden State Offshore Energy partnership, is there sort of a time line or expiration date as to sort of when can you make that decision in terms of whether you're going to have ownership stake in the project or not?

There was no hard date, I guess. We've been telling people, you should expect that to be measured in months rather than weeks. Obviously, Orsted has an obligation to meet the deadlines that they have in Maryland, and they're going to continue in that path. But we don't have a hard and fast deadline for making our decision. It would be nice to make an integrated decision, right? So we have an FID decision on Ocean Wind 1 coming up probably Q1 of next year, late this year, and it would be wise to kind of come up with a bundled approach. The BPU will give feedback on the Coastal Wind Link in October of this year, so it would be months.

Dan, do you want to add to it?

Yes. Just recall Durgesh that the -- on Skipjack, that was an Orsted bid. And so, upon the success of that bid, the opportunity was put to us. So we kind of began our due diligence on the other side of the acceptance of that bid and the winning component of that solicitation, so that the time line that really started after that bid was successful.

Got it. So I guess, in terms of months, like you mentioned the September investor conference, Analyst Day, would you have a sense of where directionally you're headed here or is that still kind of -- you'll still be in the decision making phase, Dan?

Yes. If we do it in September, it would -- that would be before we know what's going to happen in Offshore Wind just because the BPU was saying they'll give a decision on transmission in October. And they've been really good about sticking to their promised deadlines on Offshore Wind. But you always have to assume that there's a potential for some slippage there. And I don't think in any of our thinking is there an FID decision that would happen as early as September. So probably we'll know more, but we won't have decided things by that point.

Got it. And then, just 1 quick follow-up, Ralph. I mean, you've said previously roughly over $1 billion in the transmission offshore opportunities. And I heard you saying in your prepared remarks about $1 billion to $3 billion. Is that just -- obviously that's a pretty large number from the $1 billion. But is that just confidence in your sort of -- in your bids or sort of what's driving that $1 billion to $3 billion versus sort of roughly $1 billion previously?

Yes. So first of all, the BPU working through the state agreement approach has categorized the transmission investments in really 4 ways. As kind of an offshore backbone, there's the connection of the backbone to land and that connection to land could be an existing facility or a new facility. And then there's the upgrades to the existing grid that need to be made because of those first 3 pieces. The BPU can decide to give all of that to 1 bidder, they can decide to give some of that to 1 bidder, some of it to another bidder, or the BPU can decide, we're going to stick with generator leads. We don't need to build the transmission network.

So they have such tremendous flexibility and latitude in terms of how they want to design transmission for offshore wind, that we, by definition, have to be pretty broad in our range of what's possible. We put $1 billion to $3 billion in terms of -- if we got the smallest of our projects versus some of the larger projects. But don't misunderstand me, the bottom end of the range could be 0. So we're not guaranteed anything in that solicitation. We happen to think we're the best bidder in the lot. So -- and I trust the wisdom of the BPU and PJM to recognize that, but that's by no means a guarantee.

Yes. I just think that there's, I guess, the open nature of the solicitation was such that a lot of different solutions could come about. And whether or not it is a series of winning bidders within the solicitation is also something that could end up moving the number around a little bit. So we did put in a series of different values and thus the range of different potential outcomes within Net Zero was certainly a possibility.

The next question comes from the line of Michael Lapides from Goldman Sachs.

This one may be more for Dan. Dan, can you talk to us about the cash outflows required for collateral postings and how we should think about kind of what happens cash-wise once those postings reverse? How much actual cash has gone out the door for postings versus given your strong credit rating, or is it not really a cash posting or something else? And how should we think about the timing of if there's cash going out the door when that cash comes back in?

Yes. So I alluded a little bit to it within my remarks, and we have some data within the slides as well. And so, right now, the number for the amount of cash out the door at the end of April was $2.6 billion. And those are mostly for exchange trades. And very simply, the way to think about it is that it's covering the positions that we have hedged and reflective of the delta between the price that we put the hedge on, that we put the sale on and where prices are now. And so, if you think about the nature of our overall hedging program, most of the volume for those hedges is within 2022 and 2023. So most of that cash would come back to us as we deliver that power across 2022 and 2023. And so that's one way it comes back to us is by the delivery of that power. The other way it comes back to us is to the extent that you see price declines and the escalation that we've seen in prices coming off, some of that would end up in bringing some cash back to us. So that's the amount that's what's posted and that's how it would end up coming back to us.

So if I think about the balance sheet as of the quarter and maybe April, because you've posted more in April and you get $2.6 billion of cash inflow roughly ballpark between now and the end of the year 2023, so call it a 30-month, 32-month timeframe, something like that, what do you do with that money? Right? Where does that money go? That's a lot of money.

Yes, it is a lot of money. And I think the simple answer is that it goes back largely where it comes from. And so, we would normally tap the commercial paper program to put some of those postings in place. We've recently put some term loans in place to have that flexibility with respect to the funding. And so, that is where you would end up seeing that reversed, literally where it came from, from those areas.

And the next question comes from the line of Paul Fremont from Mizuho.

And I want to wish both Ralphs all the best in terms of their next move. I guess, if you were to be successful on the $1 billion to $3 billion, would that change your past discussion on no equity needs through '25?

No. No, not at this point, no.

Sorry, I don't mean to be overly succinct, but that was something that we've envisioned.

Yes. And another thing is, if you think about it, Paul, you're going to end up with that in-service date going out into the latter half of the decade as well, so that the spending in earnest is going to be on the back end of the decade.

Also when I look at sort of the first quarter nuclear fuel cost per megawatt-hour, it looks to be a little bit lower than it was last year. I guess we've sort of seen inflation in uranium prices and sort of other components of nuclear fuel cost. What's driving sort of the lower nuclear fuel cost per megawatt-hour?

I don't know if Dan has a specific answer to that component. But remember, nuclear fuels purchased over a multi-year period in [multiple] components, some of these contracts are done 6 years in advance of enrichment and the conversion. But Dan, do you know what...

Exactly. And for our facilities, if you kind of break it apart unit by unit, it's a little bit more on the Peach Bottom side, but Ralph's exactly right. If you think about the actual uranium and the conversion to fabrication, those are contracts that are put in place over a long period of time. So what we are amortizing now is many years in the making, taking out of the fuel that that you're seeing on the P&L.

Great. And over -- so, I mean, the hedges on average run for 6 years. Is that sort of a fair assumption?

On a different component of the fuel cycle, yes, that's correct.

And then, you talked about sort of the remaining $250 million of share repurchase being completed by June. How much of that second $250 million has already been completed?

About 80% of it, Paul, is predominantly completed. It's an ASR, so the accelerated nature of it is such that the upfront piece is the most of it, and then you just drew it up as you finish the overall purchases. So most of it is behind us.

And last question for me, the date of your next planned New Jersey GRC filing?

The GR -- the General Rate Case filing?

Right.

Has to be by the end of '23.

Yes. Fourth quarter next year, yes.

And the next question is from Paul Patterson of Glenrock Associates.

Congratulations. I wanted to touch base with you guys on -- I'm sorry, you guys mentioned the life extension and that it wasn't in numbers, but I'm just sort of wondering what the potential depreciation benefit might be if that were to come about?

Well, so, are you talking about the Peach Bottom life extension or the potential for a sale on the Oak Creek life extension?

Both.

On the Peach Bottom depreciation benefit we already took, that was, what, like $2 million a month or something, and we wouldn't dream of a depreciation benefit on sale on the Oak Creek until we had a long-term solution for nuclear fully baked and determined that we were the logical owners of that. So I don't even -- Dan, do you...

I don't have a number. That's a long number of years away, Paul.

Well, I mean, I'm just wondering if you were to get legislation that would enable you guys to go forward with it, different companies do it differently, but often, if you apply for a license extension for the most part, in other words, often you have companies that will take that -- will adjust the depreciation based on just the ability to file for license extension. Do you follow what I'm saying?

Yes, I do. I would anticipate that we would extend the lives when we have the license extension in hand.

Okay. Like I said, it varies from company to company, so -- okay. And then, with the -- could you just remind us what the book value is on a GAAP basis for those plans? If you don't know, it's okay. I don't need to push on this one.

Yes, I don't have it handy. But I mean, the other thing I would say is, if you're thinking about a license extension, you're getting to the point where you're going to make that commitment, which is after you have some long-term certainty, then you're going to put the filing together, then you're going to make the filing and then you're going to get the response for the filing. So really what would matter would be the book value at that time. And there's a lot of daylight between now and then.

Okay. And then, the appliance, the $0.02 positive, could you just elaborate a little bit more with what's driving that and what the outlook might be associated with that?

Client services?

Yes.

Yes, I'm sure it was some combination of what we call, -- oh my gosh, it's called [APSO], which is people call us up because their heating system broke and they didn't have a contract and we go out there and fix that. But I don't have the details in front of me right now. Paul, we can get that for you. The other possibility is that part of your client services contract. And if the weather was mild enough where we didn't have to go out and service folks with normal frequencies that we might have had a better top-line with a lower cost of goods sold in that business, but we can get that specific for you.

I expect it to be a major driver as we go through the balance of the year.

Okay. Awesome.

Thank you. And ladies and gentlemen, that is all the time we have for questions. Mr. Izzo, Mr. Cregg, please continue with your closing remarks.

Thank you, Ludy. And thanks, everyone, for joining us today. So we're not going to hide Ralph, the other Ralph. He is going to be joining Carlotta, Dan and me for a bunch of upcoming industry conferences, and he'll also be on the next quarterly call. And then I can't count my quarters. I think the one after that, he's going to just run with that and Dan on his own. But we do look forward to seeing all of you in person again, and thanks for joining us today. Take care.

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