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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Ladies and gentlemen, thank you for standing by. My name is Kyle and I am your event operator today. I would like to welcome everyone to Today's Conference, Public Service Enterprise Group's Second Quarter 2022 Earnings Conference Call and Webcast. At this time, all participants are in a listen-only mode [Operator Instructions].
As a reminder, this conference call is being recorded today, August 2, 2022, and will be available for reply as an audio webcast on PSEG's Investor Relations website at http://investor.pseg.com.
I'd now like to turn the conference over to Carlotta Chan. Please go ahead.
Thank you, Kyle. Good morning, everyone. PSEG's second quarter 2022 earnings release, attachments and slides detailing operating results by company are posted on our IR Web site located at www.investor.pseg.com, and on 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 or GAAP in the United States. We include reconciliations of our non-GAAP financial measures and a disclaimer regarding forward-looking statements on our IR Web site and in today's earnings material.
On today's call are Ralph Izzo, Chair, President and Chief Executive Officer of PSEG; Dan Cregg, Executive Vice President and Chief Financial Officer. And following their prepared remarks, Ralph LaRossa, currently our Chief Operating Officer and our next CEO, will join Ralph and Dan to take your questions. Ralph?
Thank you, Carlotta. Good morning, everyone, and thanks for joining us for a review of PSEG second quarter 2022 results. For the second quarter, PSEG reported net income of $131 million or $0.26 per share compared to a net loss of $177 million or $0.35 per share in the second quarter of 2021. Non-GAAP operating earnings for the second quarter of '22 were $320 million or $0.64 per share compared to non-GAAP operating earnings of $356 million or $0.70 per share in 2021 second quarter. And just a reminder and I'll repeat this several times throughout this call that the second quarter 2021 included the results from our divested Fossil assets and Solar Source. PSEG is on track to achieve our 2022 non-GAAP operating earnings guidance of $3.35 to $3.55 per share based on results through the first six months of 2022. This is largely driven by ongoing rate based growth from regulated investments and lower costs due to the already mentioned sale of generation assets on the carbon free infrastructure side of the business.
Utility earnings for the first half of 2022 are up 4% over the last year. At carbon free infrastructure, the year-over-year comparisons are skewed by our asset sales. Also, the majority of 2022’s earnings at the carbon free infrastructure and other side of the business have been realized as of June 30th. So for the balance of 2022, the utility will continue to be the main driver of PSEG's growth profile, which results squarely within our guidance range. I'm very encouraged by the revised climate compromise contained in the proposed Inflation Reduction Act that includes production tax credit provisions for existing nuclear and new offshore wind resources. We hope to see it move on to the Senate's floor this week, but more on that later.
I know many of you have been following the potential for an impact to our pension results in 2023 due to the significant declines in equity and fixed income markets since the beginning of the year. Should market conditions remain stressed on our December 31st measurement date, we would anticipate noncash pension headwinds related to these market declines. December 31st is the single date that will determine the pension impact for 2023. So instead of continually updating a number as our dynamic market changes on a daily basis, we would rather simply assure you that in the interim we are actively developing plants to counteract the potential near term headwinds to the extent they remain at year end. I want to emphasize that our pension remains very well funded and does not, I repeat, does not require any cash contributions for the foreseeable future. From a funding perspective, our pensions were approximately 95% funded at year end 2021, and the increase in the discount rate year-to-date has kept the funding ratio in a comparable place to year end. Rest assured that we will work tirelessly to mitigate the potential future headwinds including pension, supply chain and general inflationary pressures.
I hope you will see through these near term challenges and recognize what we see that the underlying fundamental utility growth story of PSE&G remains intact, and that our valuation will reflect the improved business mix and overall derisking that continues, all of which gives us the confidence to reiterate our multiyear 5% to 7% EPS CAGR from the midpoint of 2022 non-GAAP operating earnings guidance to 2025. We remain focused on improving our system reliability and resiliency, further derisking the business overall and maximizing affordability for our customers. The statewide moratorium on shutoffs for residential electric and gas service was lifted in mid-March 2022 and collections and shutoffs have since restarted. However, New Jersey did passed legislation after the moratorium ended that provided protection from shutoffs to customers who applied for payment assistance programs by June 15th of '22. We applicants for assistance are protected from shutoffs while awaiting their application determination. As a result, PSE&G continues to experience higher accounts receivable aging, which we expect will take the next several years to reset to historical levels. PSE&G's electric distribution bad debt expense is recoverable through its societal benefits clause mechanism and has deferred as incremental gas distribution bad debt expense, as well as other incremental COVID-19 costs to future recovery, which will likely take place in our next distribution base rate case.
Our regulatory framework in New Jersey continues to be constructive. Working with the BPU staff and Rate Counsel, we reached the settlement to begin work this quarter on the infrastructure advancement program. The BPU approved the settlement in June. And over the next four years, we will invest $500 million to extend reliability improvements, inclusive of the last mile of our distribution system as we prepare the grid for the rapid transition to electric vehicles and enable a greater integration of renewable energy resources. Turning to our efforts on the environmental, social and governance or ESG front, we are continuing our internal preparations to finalize company wide emission reduction goals, and we will be submitting those targets to the United Nations backed Science Based Targets initiative for validation that they are in fact consistent with the objectives of the Paris Agreement to limit the global temperature increase to 1.5 degrees Celsius or less. We have until September of 2023 to finalize and submit our targets for validation, although we're aiming to present our pathways before that, which will address all three scopes of PSEG's emissions reduction goals.
Let me turn now to commodity markets, where we've seen a continued increase in electric and natural gas prices during the second quarter. And although some PJM prices have moderated recently, prices remain at high levels. With gas and electricity supply costs, which are a pass through at PSE&G, comprising approximately 40% to 45% of a typical residential gas and electric bill, we are keenly focused on controlling costs to minimize the impact of rising commodity costs on these customer bills and maximizing affordability. On the electric side, PSE&G contracts for its default BGS, basic generation service, as we often refer to it, requirements on a three year rolling basis, and each year, one third of the load is procured for a three year period. New BGS rates went into effect June 1st. And despite what I just said a moment ago, but due to a decline in actual versus assumed capacity costs, electricity bills actually declined. On the gas side, PSE&G is permitted to recover the cost of hedging up to 80% or roughly 115 Bcf of its annual residential requirements through the BGSS tariff. We recently filed for our anticipated BGSS costs to go into effect in rates before the upcoming winter season that will reflect current market prices at the time and be trued up for actual costs over subsequent time periods.
On the nuclear side of the business, we remain fully hedged in 2022 and 2023 and a little more than half hedged in 2024. With our ratable base load hedging program in effect, we should begin to see higher prices layer in as we continue to incrementally sell power forward into 2024 and 2025 assuming that prices remain at today's higher levels. The uncertainty of power prices highlights the critical need for longer revenue visibility to safeguard the economic viability of existing nuclear plants, which are increasingly recognized as a irreplaceable source of carbon free domestic energy supply. I might add, this is also taking place at the international level in terms of the recognition as an irreplaceable source of carbon free energy supply. We continue to observe a positive shift in public sentiment and support preserving these nuclear plants. Most recently as part of what I mentioned before, the proposed inflation Reduction Act of 2022, as our country invests in energy security and climate change solutions, which can help to stabilize rising electricity prices. This proposed legislation agreed to last Thursday by Senate Manchin and Schumer includes the nuclear production tax credit we have advocated for over the last two years, and would be in effect from January 24 through 2032.
This pricing floor for nuclear generation squarely addresses our need for a longer term framework within which we can continue to own and operate our fleet with extended revenue visibility beyond the current three year zero emission certificate cycle. The bill also includes transitioning to a technology neutral ITC, PTC beginning in 2025 for new carbon free resources. And there is a 15% corporate minimum tax on net book income that would impact us and our customers. We are analyzing all aspects of the bill, including the many provisions that will help address climate change. We are hopeful that these provisions will pass Congress. Senate Majority Leader Schumer indicated his intention to bring the bill to the Senate floor this week. But there is a review process involving the Senate parliamentarian that could take a week by itself to complete. If the Senate is able to approve the measure, the House would likely return from the August recess to vote on it. In the meantime, we continue to have policy level discussions with New Jersey state legislators who are currently in summer recess to discuss a longer duration alternative to the current zero emission certificate framework for nuclear should the price floor contained in the reconciliation bill for prove elusive.
Now let me turn to an update on our offshore wind opportunities, which we continue to advance on a number of fronts. On the transmission partnership, Coastal Wind Link, the timing of New Jersey's decision on its state agreement approach to transmission offshore is still expected this October. On Ocean Wind 1, development efforts are ongoing as we approach the upcoming FID date in the coming months, while the Bureau of Motion Energy Management will continue public hearings on the draft environmental impact statement later this summer. As related to the opportunity to co-invest with Ørsted, we continue to have conversations on a variety of fronts, and in fact, due diligence continues in earnest in this regard. As I step down from my CEO duties on September 1st, PSEG is well positioned to enter its 120th year of serving New Jersey with essential energy services that help to power the economic engine of the state and advance its energy policy leadership. In my role as Executive Chair of the Board through the end of '22, I will continue to advocate on behalf of PSEG in key policy arenas.
Now later, you'll hear from Ralph LaRossa, and I must say he is the most well prepared, ready CEO elect in the history of our company. And with Ralph at the helm, PSEG will further advance its powering progress vision of a future where people use less energy and it's cleaner, safer and delivered more reliably than ever. PSEG's dedicated workforce will continue the public service heritage that recently earned us the 2022 Edison Award from The Edison Electric Institute, the Electric Utilities highest industry honor and recognition of PSEG's infrastructure monetization programs focused on protecting our customers and communities from extreme weather conditions. I think that's our second Edison award in the last 10 or 12 years or so. I will now turn the call over to Dan for more details on our operating results. Then Dan, Ralf and I will be available for your questions.
Thank you, Ralph. Good morning, everybody. As Ralph mentioned, for the second quarter of 2022, PSEG reported net income of $0.26 per share and non-GAAP operating earnings of $0.64 per share. We've provided you with information on Slides 9 and 11 regarding the contribution to non-GAAP operating earnings by business for the second quarter and year-to-date periods ended June 30th. Slides 10 and 12 contain waterfall charts that take you through the net changes quarter-over-quarter and first half 2022 over first half 2021 and non-GAAP operating earnings by major business. We'll start with PSE&G, whose second quarter net income was relatively flat compared to the second quarter of 2021, reflecting rate base additions from our investment programs and our gas system monetization, Energy Strong programs and the implementation of the SIP, which was largely offset by IRLM in the quarter, much of which was timing related.
Compared to the second quarter 2021, transmission margin was flat as growth in rate base and other positive [TRIP] adjustments were offset by the August 2021 implementation of a new transmission formula rate, including our base return on equity moving to 9.9% plus the 50 basis point add. For distribution, gas margin improved $0.02 per share over the second quarter of 2021, reflecting the scheduled recovery of investments made under GSMP and a true-up from the SIP. Electric margin rose $0.02 per share compared to the second quarter of 2021, driven by the scheduled recovery of Energy Strong 2 investments and the SIP. Other margin primarily related to [appliance] service also added $0.01 per share compared to the second quarter of 2021. O&M expense was $0.04 per share unfavorable compared with the second quarter 2021, reflecting higher costs from the resumption of customer settlement proceedings as courts reopened and higher electric operation expense and gas tariff work. Interest expense was $0.01 per share unfavorable, reflecting higher investment. In addition, the impact of PSEG's $500 million share repurchase program had a $0.01 per share benefit on second quarter 2022 results.
Flow through taxes and other items had a net unfavorable impact of $0.01 per share compared to the second quarter of 2021, driven by the use of an annual effective tax rate that will reverse over the remainder of the year. Summer weather during the second quarter of 2022, measured by the temperature humidity index, was warmer than normal but cooler than temperatures during the second quarter of 2021. With the SIP in effect, variations in weather, positive or negative, have a limited impact on electric and gas margins, while enabling the widespread adoption of PSE&G's energy efficiency program. For the trailing 12 months ended June 30th, weather normalized electric and gas sales reflected lower residential sales, both electric and gas lower by approximately 3% and higher commercial and industrial sales, higher by 2% and 3%, respectively as more people return to work outside the home. Growth in the number of electric and gas customers remain positive by approximately 1% over the trailing 12 month period. PSE&G invested approximately $741 million during the second quarter and approximately $1.4 billion year-to-date through June 30th, and we are on track to execute our planned 2022 capital investment program of $2.9 billion. The 2022 capital spending program includes infrastructure upgrades to transmission and distribution facilities, as well as the continued rollout of the Clean Energy Future investments in energy efficiency, energy cloud and smart meters, electric vehicle charging infrastructure and the new of [Technical Difficulty] investments that will begin this quarter. PSE&G's forecast of net income for 2022 is unchanged at $1.510 billion to $1.560 billion.
Moving on to carbon-free infrastructure and other, where we reported a net loss of $174 million or $0.35 per share for the second quarter of 2022, driven by our nuclear decommissioning trust and mark-to-market impacts and non-GAAP operating earnings of $15 million or $0.03 per share. This compares to a second quarter 2021 net loss of $486 million and non-GAAP operating earnings of $47 million, which included the results of the divested fossil and solar assets. For the second quarter of 2022, electric gross margin declined by $0.25 per share, primarily due to the sale of the 6,750-megawatt Fossil portfolio this past February, and the sale of the Solar Source portfolio in June of '21. This reduction in gross margin includes recontracting approximately 8 terawatt hours of nuclear generation at a $3 per megawatt hour lower average price. In addition, ZECs added $0.01 per share due to the absence of the Hope Creek refueling outage in the year earlier quarter. Separately, lower margins at gas operations resulted in a $0.01 decline in gross margin versus the second quarter of 2021. Year-over-year, second quarter cost comparisons were better by $0.22 per share due to the divestitures, driven by lower O&M depreciation and interest expense that will mainly benefit first half 2022 results. You will recall the third and fourth quarters of 2021 reflected the solar source sale in June, the cessation of fossil depreciation from August onward, and the retirement of PSEG Power's outstanding debt in October.
Current activity was a $0.01 per share unfavorable compared with the second quarter of 2021 as a result of higher interest expense, and taxes and other were $0.01 unfavorable compared to the second quarter of last year. Nuclear generating output increased by over 3.7% to 7.5 terawatt hours in the second quarter of 2022, reflecting the absence of a refueling outage at Hope Creek in the year earlier quarter. The capacity factor for the nuclear fleet for the year-to-date period through June 30th was 95.1%. PSEG is forecasting generation output of 14 to 16 terawatt hours for the remaining two quarters of 2022, and is hedged approximately 95% to 100% of this production at an average price of $28 per megawatt hour. For 2023, we're forecasting nuclear baseload outlook of 30 to 32 terawatt hours with 95% to 100% hedged at an average price of $31 per megawatt hour. And for 2024, we're forecasting nuclear baseload output of 29 to 31 terawatt hours, which is 55% to 60% hedged at an average price of $32 per megawatt hour. The forecast of non-GAAP operating earnings for carbon-free infrastructure and other is unchanged at $170 million to $220 million. And this guidance for 2022 excludes results related to the Fossil assets that were sold in February of this year.
With respect to recent financing activity and collateral postings, PSEG remains on solid financial footing. As of June 30th, the PSEG money pool, including PSEG and Power, had available liquidity, including cash on hand of $3.7 billion. In April and May of 2022, we entered into a 364 day variable rate term loan agreement totaling $2 billion. Also in the quarter, Power entered into two $100 million letter of credit facilities expiring April '24 and April '25 respectively. And in July of ‘22 PSEG repaid a $1.25 billion short term loan that was due later this month. Our net cash collateral postings of $2.5 billion at June 30th related to out-of-the-money hedge positions as energy prices rose during the second quarter of 2022. Collateral postings have increased subsequent to June 30th and at the end of July, Power had net collateral postings of approximately $2.5 billion. Most of this collateral is associated with hedges in place through the end of 2023, and is expected to be returned to PSEG Power once it satisfies its obligations under those contracts, or sooner if market prices decline in the interim. As Ralph mentioned, 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 of 2022, PSE&G's net income is forecasted at $1.51 billion to $1.56 billion, $1.51 billion to $1.56 billion. The non-GAAP operating earnings for CFIO is forecasted at $170 million to $220 million. PSEG's 2022 earnings guidance excludes financial results from the divested fossil assets and includes an additional interest expense related to recent financings.
Looking beyond 2022, regarding the pension item Ralph referenced earlier. Slide 19 in the webcast deck highlights some pension disclosure contained in our current 10-K annual report. We outlined several items that will influence the pension impact in 2023, including updating the discount rate and interest costs, setting the expected return on planned assets for 2023, calculating the actual gain or loss on the funds and determine the fair value of the funds at year end. As many of you know, we do not smooth, we apply the fair value of the fund balances to next year's expected return. As such, asset values and discount rate on December 31st will determine the impacts for next year. Lastly, we've completed our $500 million share repurchase through open market purchases at an accelerated share repurchase program in May of 2022. That concludes our prepared remarks. And with this being Ralph's last earnings call as CEO, I'll give him an opportunity to make some closing remarks before taking your questions.
No. Actually, Dan, I think I'll wait until later, sorry about that. Why don't we go right to the questions, Kyle?
[Operator Instructions] The first question is from Shar Pourreza with Guggenheim Partners.
So Ralph, let me just, if it's okay, start on the pension side. Can we maybe just get a little bit more details on the potential offsets that you're sort of thinking about implementing? I mean everyone has estimates out there on what the drag could be, so whether it's $0.20, $0.30, $0.40, whatever it ends up being. Do you feel like you could offset that kind of a drag and how does that potentially factor into a rate case filing in '23?
So Shar, of course, we like to think of the fact that we're always mindful of our O&M expense. But you can always do more, there's a cost versus quality consideration that we'll have to take into account. So there's no doubt we can offset some of the headwinds. We're just not going to get into a conversation today about how easy it is to offset $0.05 versus $0.30 versus $0.20. And believe me, we've seen numbers dance around that whole range over the past six years. And we're not going to do anything that compromises the long term service quality of the customers. We're going to look at every part of our cost structure to see what is a good short term decision, what's the good long term decision. And then, of course, as you correctly pointed out, the utility does have a rate case that starts January 1, 2024. So we view this as a short term headwind that's not quantifiable on August 2nd and can only be quantified on December 31st, but we're looking at a whole litany of potential cost reductions, and each one of them comes with some risk. And we'll draw the line where we feel comfortable that the short term risks are manageable, but we do nothing to jeopardize the long term health of the company. I know that's not a quantitative answer to your question. But I think it's just going to drive people crazy to every day look at what markets are doing and what congressional leader is visiting, what island nation and what that's doing to equity markets and things that are simply not within our control over the next few months.
And then just, Ralph, on the strategy side with generation sort of with the inflation reduction not gaining traction. There's obviously improved visibility on nuclear, which is one of the things you mentioned would be a trigger point potentially to assess whether you want the assets within the portfolio or not, so any updates there. And then just around offshore wind, there's obviously some very healthy valuation marks on the land lease values, with your neighbor looking to provide another maybe data point soon. Any thoughts there on whether you would reassess value here as well? So I guess, how are you thinking about potential trigger points to exit the remaining generation business you have?
I think you hit the nail on the head in terms of important data points, Shar, coming in. Look, if the inflation reduction Act passes as is proposed, there are some technical amendments that we're working with bill sponsors to make sure are considered because of some language that is inconsistent with what people have told us they're trying to achieve. I mean you basically have nuclear energy price of $44 a megawatt hour, give or take a few pennies as long as power prices in the market don't drop below $25, and as long as power prices in the market don't go above $44. So the nuclear assets begin, to me at least, to look a lot like a rate base rate of return and piece of infrastructure with a steady and attractive cash flow that makes them economically viable. Now there's a whole lot of wood that needs to be chopped between now and making that something that President Biden puts his pen to. And then there's the need to see what investor reaction will be, if it's interpreted the same way that we interpret it, which is, as I said, essentially a very predictable earnings stream with a very solid cash flow generation that I think serves the state of New Jersey very well, serves the company very well, serves the planet very well.
On offshore wind, we do have an important data point coming up, and you alluded to it. There is another company that is in a strategic review process and we'll carefully monitor the outcome of that while pursuing with all the due diligence efforts as I spoke about before from Coastal Wind Link to Ocean Wind 1 and some other possible opportunities with Ørsted. Look, it should be obvious to everyone. New Jersey is going to build 7.5 gigawatts of offshore wind. I think half a dozen states are going to build 30 gigawatts of offshore wind. That's going to have a significant impact on tower markets, bill headroom and opportunities to grow earnings per share for companies. So it's something that we want to make sure we are taking a long view in terms of the role we should or shouldn't play in that. So more to follow and some of it we’ll be following in the next few months.
What was the test year for the rate case that you guys are going to file, is it '23…
July of '23 to June '24, so it does include ‘23 -- it gets filed on January 1 of '24.
Our next question is from Nick Campanella with Credit Suisse.
Just acknowledging that you kind of -- you reiterated the long term 5% to 7% EPS CAGR. When we kind of take into account the mitigation strategies you're targeting, and this 5% to 7% CAGR. Is this a long term CAGR or do you still have kind of visibility on 5% to 7% growth in '23?
So Nick, as you know, in a regulated world, with test years and rate cases, one does not -- and even though -- I guess, it's almost 90% of our CapEx has some form of trackers, some of that is delayed six months, some of that's delayed one year. We've never told people that the 5% to 7% CAGR is every year to be applied that it was -- you think the midpoint of the '22 guidance and you look at where we are in '25 and the CAGR over that time frame is 5% to 7%, and we never gave what '23 would be or what '24.
And then just other aspects of the [IRA], just like the minimum 15% tax. How does that kind of play into affecting your business, if at all, and what are the offsets there?
I think what's laid out right now, Nick, is pretty simple to what's in the build back better. And so I think your first screen you're going to go through is the size of the earnings from the company to determine whether or not you're subject to it, and then you're going to work your way through essentially will deemphasize things like depreciation and give you a lower rate in exchange. And so that trade off I think as an industry, we're going to go through and take a look and see what that means from a cash flow basis. To the extent that, that does kick in, you'll have a higher cash flow upfront coming out the door for taxes. But whatever excess you do have, that's going to be carried forward indefinitely, and so we will work our way through. And ultimately, to the extent that, that happens, you have a deferred tax asset or probably more appropriately stated a smaller deferred tax liability, which comes into play and the balance of your rate making as well. So I think we're all exploring where this is going to go to the extent it does get across the finish line as is. I know that there are some in Washington who had challenges against this type of increase in the first go round. But right now, as it's played out, it looks pretty similar to what was in build, back, better.
And if I can just squeeze one more in, I think folks are wondering, so I’ll ask. Just any thoughts on an Analyst Day this year?
So Ralph, go ahead, do you want to…
Nick, right now, we're planning to do an Analyst Day in the first quarter of '23. I think Ralph has laid out a bunch of mile posts that would lead us to say that there's enough moving parts that it makes sense for us to have that conversation in the first quarter of '23.
Our next question is from Steve Fleishman with Wolfe Research.
Ralph, I just want to wish you the best in case this is your last earnings call. So first of all, just on the pension, how should we think about how the pension is maybe roughly split between regulated and nonregulated parts of PEG?
You probably have 75%, 80% of it that's going towards the regulated piece.
And then when you -- obviously, you don't know what returns are going to be the next three years. But when you think about your confidence in the 5% to 7% to [25%]. Is most of that just because this just gets all trued up in the rate case no matter what happens to the pension performance, can you just go to a normal return or is it that you're expecting the market to bounce back, and the offsets? Is it more that this is just part of the rate case ups and downs?
Think about it more of the latter, Steve. Well, obviously, you're going to have the effect of markets, both your equity and debt markets for your asset return for the assets within the trust as well as what the discount rate is going to look like. But ultimately, with a bigger part of the pension being on the utility side of the house that you're going to have a regulatory aspect of it that's going to be important as well.
So it's not like you're counting on the markets to come back or anything like that?
Right.
And then Ralph Izzo, unfair question to end things up. You've been very involved in working on this IRA law. Just curious your best judgment on the likelihood it passes.
I was a little bit worried about Senator Sinema, but the tax provisions, the carried interest provisions don't seem to be a big number. So I find it hard to believe that, that would really result in having to worry about one more Renegade Senate vetoing the bill. And as we head into the midterms, there's a really good chance, it looks like the Senate could retain a Democratic majority. And a lot of them feel like if they could get this over the finish line, that would cement that prospect. So I give it a high probability of success. My bigger worry was whether or not when we [reduce] a $2 trillion piece of legislation to $0.5 trillion if you lose the folks that were part of it on the house side, but some of the more visible and outspoken members of the left wing of the Democratic party have said this is a critically important climate change initiative and the most important thing we've done in this regard. So I've gained a little bit of confidence there as well. So I put its odds at pretty strong. I mean with the Senate majority leaders saying he's going to bring it to the floor on Thursday, even before the parliamentarian is likely to rule, I'd say the odds are looking quite good at this point.
I had one last question I forgot about. Offshore wind transmission, the bidding for that. Is there any update on the process there?
The RFP, I think, is going to come out first quarter of next year, for the next round. Is that the question…
It’s an October date, Steve, for when we're supposed to be hearing back -- there's been a little bit of -- there's been work that's been ongoing on it. I know PJM put out a piece related to some of the risks and the constructability, and different elements. And so I know folks have had some comments back on that. But ultimately, it sits within the BPU's jurisdiction with PJM providing some technical support. So October is still when we're supposed to hear back what the answer is on that.
The next question is from Durgesh Chopra with Evercore ISI.
Just on the pension topic. One of the discussions that we've had with investors relates to your earned ROEs versus authorized. Obviously, pension has been sort of a tailwind past few years, and it looks like it's going to be a going forward. Can you comment on, Dan, just your earned versus authorized returns at the utility currently? And then how are you modeling that going forward in your 5% to 7% target? I'm interested in your returns versus the authorized levels.
I mean, I think, I guess, if you want to think about what we would anticipate on a go forward basis, it would be earning our allowed return. And so yes, you're going to have some tailwinds and headwinds from various items, pension certainly is one. And you're right, if I think about it in the immediate term, you've got some more -- the potential for more headwinds. And if you look backwards, there's been some tailwinds, but there's other items that have offsets and also come into play. But I think if you want to think about what we're anticipating as we look at '25, I think it's -- we're anticipating earning our allowed return.
And Dan, I mean, 40% of rate base is transmission, which is basically trued up exactly every year. If I'm not mistaken, doesn't the conservation incentive program have a range where we fall outside that range. We're either not eligible. So we stick to that a long return basically on both the [energy] side…
Yes, exactly. The way that, that mechanism works, it has kind of balance related to your earned returns. So we are pretty close to that level throughout.
I mean I guess the forward-looking plan has you earning close to the authorized, is the key takeaway here. Just Ralph, I wanted to go back to sort of the strategic review on offshore, how critical -- and this is -- how critical is being involved with the offshore generation side to winning some of these offshore transmission opportunities. Obviously, you previously indicated like roughly, I think, over $1 billion in opportunity, and we'll hear about it in October. But how critical it is from a strategic standpoint to be in the generation to get some of these transmission awards, or you think those are two independent things.
I think those are two independent things. I don't think it's critical at all. Dan, did you want to answer that?
I'd just reinforce that.
The next question is from David Arcaro with Morgan Stanley.
Could you talk a little bit as to the hedging environment for 2024 right now for Power? Is there any update on your ability to take advantage of the current commodity backdrop to accelerate some hedging from here, and what's the liquidity looking like?
There's more liquidity out there, David. We couldn't close out the entire position in a very short term. But there's liquidity to be able to continue to do what we anticipate doing, which is staying on a ratable path. I mean I think we've got a market environment, which has higher pricing than what we have seen historically. But by the same token, we've got a fairly backwardated curve. And so those two items, I think, are a little bit at odds with respect to where things may be going. So we're moving along related to our ratable hedging program kind of within the bounds that we set, I anticipate that general construct to remain.
And it's early, but just wondering as you think about some of the strategic considerations over the next year or so. Any early thoughts on how you'd redeploy capital and kind of use of proceeds as some of these strategic endeavors might unlock cash flow?
I mean I think one of the things that is really important about the infrastructure advancement program is the recognition to the credit of the Board of Public Utilities of the under investment or let's just say the lack of investment that has followed the last mile because there was so much to do with the higher voltage part of the system. And all the good work we did in transmission and inside plant that actually resulted in our second Edison award and just an outstanding outcome in what was a devastating flood event in Hurricane Ida. All of that work that went so well at the high notes now needs to go towards the lower voltage part of the system. And [IAP] was a recognition of that, and getting $500 million plus of the $800 million ask approved, I think, shows that we're entering a new era, people working from home, losing power at the home is not just knowing, blinking lights on, the microwave oven, you can't charge a car and you can't do your work, you can't call your neighbor, you can't find out where the kids are and that level of resiliency and reliabilities is something that customers are demanding.
So I think that there's a lot of opportunity in that last mile that we're just beginning to explore and touch upon. So as we've often said in the past, David, there's a long runway of utility investment needs. I mean we still have a lot of aging infrastructure we have in place, that's to get with a little track of what the runway is on the GSMP program at the current spend rate, if you see the 20 or some odd years, I think. So the number one gating function has been, is, and will be, just making sure that we have customer affordability and we're always mindful of that. But in terms of opportunities to redeploy, that's on the [10] things that used to keep your awake at night that were somewhere around number 20.
Our next question is from Julien Dumoulin-Smith with Bank of America.
I'm just going to keep going here on the theme here on the 5% to 7%. And I want to come back to -- I know we asked you, I think, even last time here, but Dan, the expectation of this persisting beyond '23 on the 5% to 7%. Does that include the latest net pension headwinds in Power mark-to-market, where do you stand on reflecting that? And just -- again, just again, I get that this moving around, I get is rate case extension -- what is your expectation? And related to that, if you can, what is the current asset performance year-to-date? You kind of implied a comment in your prepared remarks, but if you can quantify that, that would be great.
Julien, I think it's consistent with what we've been saying. I think we're not going to know exactly what that number is going to be until 12/31. That is the nature of how we do our accounting and that's where we're going to stand. And so I think we're going to have that part of the puzzle determined at that time. And given the variability we've seen in markets, you could see some movement there. I would argue that if you take a look at how we are invested with kind of in the mid-50s on the equity side and then some real assets and the balance being on the debt side, you can kind of make a determination that we're -- if you use just the benchmarks, I think you're going to be in the right ballpark. Against that backdrop, we're going to do exactly what Ralph talked about. We're going to go through. We're going to drive through all the initiatives that we've started to lay out, made determinations on some. We'll continue to make determinations on other and trying to make sure we strike the right balance between running the business right and managing our way through some near term headwinds. And the magnitude of those and what we see by virtue of doing the things that we've identified is going to be what's going to determine where we end up in 2023. So it's a little bit dynamic right now but that's going to drive ultimately where we land within 2023, and that guidance will be forthcoming.
And maybe implicitly within this, you expect the utility to grow 5% to 7% specifically, right?
Say again?
So you expect the utility to grow 5% to 7% specifically as well, right?
So we give you a rate base CAGR on the utility, we don't break each business separately in terms of the CAGR. But as you know, Julien, given 90% of our CapEx get some type of contemporaries return, the utility earnings should equal rate base minus O&M minus regulatory lag, plus any new customer growth which is not part of the SIP. And those last three pieces are pretty small but they can change things faster the first decimal point. But we don't break out each company separately in terms of the CAGR. But the…
Actually, just going back to the last question, very briefly here. Why only hedge 5 percentage points of '24 at this point, is it just about the prospects on federal support here that hold you back just to make sure?
Say your question again, Julien?
Just on the only adding about 5 percentage points on '24 hedging, I would have thought intuitively, maybe you would layer in more. Again, question is more, is the federal support and uncertainty from a legislative perspective, hold you back?
I mean, I think, frankly, it's just more consistent with respect to how we're thinking about the ratable program. We are a little bit higher than what a ratable three year would have you have the math turn out to be. And then so we have some of those ranges but we want to stay within a bit of a ratable band identifying as well the backwardation that exists within the curve. And so I think that we'll continue to move forward, continuing to hedge at the prices that we're seeing as we go forward. But I think you'll -- I wouldn't anticipate us to be outside of that ratable range in the near future.
The next question is from Ross Fowler with UBS.
So I just wanted to go to Slide 22 and make sure I understand the dynamic here between the potential, let's call it, potential because it's what it is, a nuclear PTC at the federal level and the ZECs in New Jersey. So if I think about the 55% to 60% that you've hedged to 32 hours a megawatt hour out to ‘24. Right now, status quo I would add the $10 ZEC to that and get a price on that hedge piece of about $42 a megawatt hour. But if I were to get the nuclear PTC, that would be somewhere between $42 and $44, a megawatt hour, and that would actually be upside to that pricing, because the ZEC would go away of New Jersey, if I understand it correctly, it would be replaced essentially by the nuclear PTC at the federal level. Have I got that right, is that the right understanding of how that would come in…
You're absolutely right.
And then the non-hedged piece would come back to the nuclear PTC price if -- well, it would basically be either the current price if it were over the $44 or would be the [$42 to $43] at the nuclear PTC, if that's what we get, or it would be whatever you hedge at plus the ZEC, if that's where we stay. So am I thinking about that correctly?
Yes, I think that's right. Ross, if you think about what they're doing in Washington essentially is a floor, and to the extent that realized exceeds that then the PTC basically just drifts away as your realized goes up and New Jersey [Multiple Speakers] with plus 10%.
So as you look to hedge a further piece of that and following on Julien's question here where you go through your ratable hedging, if hedging were to move up above that $32, it would be above the nuclear PTC. But if you lose the $10 ZEC, you have to come back to the nuclear PTC level. Is that how I should think about that? I guess I'm trying to say if you're hedged at $35, you get a credit for the PTC up to that $44 level in the federal PTC case or if you're hedged at $34, you would have -- or $35, it would actually be $45 in the ZEC case. Am I thinking about that correctly?
Well, the ZEC does not have to -- the state does not, it could be $10.
Through to '25 is what we -- and the crisp definition with respect to the realized that you apply in determining what the PTC is to get you to that $44 is going to be finalized within the details, but that's our expectation.
I just wanted to make sure I was getting the into out correctly as we potentially change what applies to the power side in New Jersey for the nuclear…
The next question is from Michael Lapides with Goldman Sachs.
My question is probably more for Dan. Dan, you talked a little bit about collateral postings and being a little over -- right around $2.5 billion at the end of July. That cash, if I understand correctly, it comes back over the next 18 months, between now and year end 2023. So how should we think of -- what does that mean, does that mean that it's simply a reduction in maybe your draws on your credit facility that shows up, so short term debt on the balance sheet will actually go down by that amount by the time we get to 2023 -- end of '23, if we leave all else constant?
You're thinking about it exactly right, Michael. So there's -- think about it as incremental draws to fund that. And as that comes back, we would just take out the source that was used to fund in the first license.
And the source that's being used to fund it is simply short term debt or credit facility up top at the holding company level?
Yes, that's exactly right.
And if I were to apply -- my follow-on question relates to the Inflation Reduction Act. If I were to apply that to the minimum tax requirement to 2022, how big of a cash flow impact would that be on this year using your guidance for this year, how material?
I wouldn't give you like a single year look because you can have onetime items that would come through. So if you think about this year, we closed the fossil sales, so you're going to have some kind of disruptions in what it normally looks like. I think if I would try to do the math, and it's going to depend year-over-year over the longer term, but you're going to basically take a look at what your delta is within your accelerated depreciation, what the delta is within the rates. There's going to be other pieces that are going to move, but I think those are the two biggest moving pieces that you have. And how much does that 6% buy you going from 21% to 15% compared to the magnitude of what you're getting through the tax benefits that will be taken away that are in your book income. So that's the trade-off and it's going to vary a little bit by year depending upon what capital you're deploying and where you are within the accelerated depreciation [scheme].
I hate to sound really big picture here, but I'm going to try and do it. Big deal, medium deals, small deal.
I think it's probably somewhere in between. I think to the extent that you're going to see an incremental payment, you're going to end up having an indefinite carryforward on your credit and basically, that's going to reduce deferred taxes. And so to the extent that deferred taxes end up reducing your rate base when you have a deferred tax liability, it seems like you'd have the potential that -- from a regulatory perspective, you'd have an incremental rate base component on the regulatory side of the business, and that's where most of the capital is. So I think it's still going to play out and see where we end up in the final determination, but somewhere in between.
The next question is from Jeremy Tonet with JPMorgan.
Best of luck to Ralph and Ralph. And I just wanted to kind of pick up on the last point a little bit there, if I could, as it relates to the IRA, and it passed as it is. How would this impact your financing strategy and agency thresholds if passed?
Well, I think ultimately, there's the potential for a lot of pieces, Jeremy. So it's kind of tough to give a really crisp answer. You've got some -- if I think about just a couple of pieces that are going on, you're going to have a PTC on nuclear that's either going to kick in into certain magnitude or not kick in a certain magnitude because you're above or below that floor. So you've got some cash variability there. I think you've got offshore wind, you've got some PTC potential versus ITC and you're going to make your trade off there, which has a different impacts for cash and for book. And then you've got this minimum tax item, which could be an incremental draw on cash. And so I think having the balance sheet strength that we have, we have the ability, obviously, to work through these issues. But I think the incremental financings around the edges would be changing based upon the timing of some of these things when we see any potential minimum tax incremental payments reversing and the timing of any of these credits that come through. So those are the things you would look to. But I think you've got a lot of time between now and final passage to actually figure out what the actual impacts are going to be.
And just one little point there. Is it fair to say PTC visibility for nukes would change agency view there versus three years at?
Certainly, a favorable item, magnitude of that change to be determined. I think you've -- like we talked about, it could be incremental dollars, it could be a floor which provides stability, which reduces risk, which the agencies would like. So either way, if I think about both the flexibility on the offshore wind as well as the PTC for nuclear, I think both of them are value additive from the standpoint of both of these options that we have on the generation side.
Just a last one if I could. As it relates to the IAP process, are there any takeaways from this process this time, particularly as it relates to how you might view future extensions of CEF and GSMP programs?
I think less on CEF and GSMP and more on last mile. So I think this was the first proposal that we put in front of the BPU to start the long runway of work that we have on the last mile. And we were very pleased with the acknowledgment of that need and the work that we have ahead of us. So I think more than anything else, I would look to the IAP, if it's a signal for anything, it's the acknowledgment of the work that does need to be done on the last mile of the system on a more proactive basis rather than just run to failure.
Great. So look, it's been mentioned a couple of times. This is my last quarterly earnings call, and it's something of a cliche, but I have to tell you, it's been just a genuine honor and privilege to be with this company for 15 years. And for those of you who are still on the call or listening to the webcast, I want to extend to you and hope you'll accept my sincere thanks for all the conversations, all of the probing questions you've offered over those years. And I'm not kidding, I mean it served to make us a better company and hopefully, it serves to make me a better CEO. I'll genuinely miss those interactions. But I cannot overemphasize the company is in great hands with the new Ralph, with Dan and the entire senior team. We've worked side by side for a long time, and I have just 100% confidence that they will do a far better job than I was able to do on my own, certainly, in the early stages.
Now I know that you're all eager to learn more about pensions and nuclear economics and ownership and offshore wind prospects, and you will, and you will. But I'm encouraging our leadership team to continue our proud tradition of taking a long term view and gathering important information before rushing into decisions that might have short term appeal but long term consequences. And I think we're literally talking about weeks and maybe months before we get some really important data points that come our way. So with that, it's now my pleasure to turn the call over to Ralph.
Thank you, Ralph. I just have a few items I wanted to touch on. First, I want everyone to know how excited I am for our future. We are very well positioned by our Power and Progress vision, and I look forward to continuing the work that we have started. Second, I wanted to thank all of you on the call for the kind and supporting words I've received from so many of you since the announcement in April. And I look forward to meeting with you throughout the remainder of 2022. But finally, I wanted to thank you, Ralph. Thank you for all you've done for this great company, our customers and our employees. Thank you for the industry leadership and specifically your leadership on addressing climate change issues. And last but not least, I thank you for all the time and effort you've given to me personally. And with that, Kyle, I think we’re ready to close the call.
Ladies and gentlemen, this concludes today’s teleconference. You may disconnect your lines at this time. Thank you for your participation.