Matthew Fallon:

Good morning and thank you for joining us. I am Matthew Fallon, Eversource Energy’s Director for Investor Relations. During this call, we’ll be referencing slides that we posted yesterday on our website. As you can see on Slide 1, some of the statements made during this investor call may be forward-looking. These statements are based on management’s current expectations and are subject to risk and uncertainty, which may cause the actual results to differ materially from forecasts and projections. We undertake no obligation to update or revise any of these statements. Additional information about the various factors that may cause actual results to differ and our explanation of non-GAAP measures and how they reconcile to GAAP results is contained within our news release, the slides that we posted last night and in our most recent 10-Q. Speaking today will be Joe Nolan, our Chairman, President and Chief Executive Officer; and John Moreira, our Executive Vice President, CFO and Treasurer. Also joining us today is Jay Buth, our Vice President and Controller. I will now turn the call over to Joe.

John Moreira:

Thank you, Joe, and good morning, everyone. This morning, I will discuss our second quarter earnings results, provide a regulatory update and review our financing activity. As shown on Slide 9, our GAAP and recurring earnings for the second quarter were $0.95 per share as compared with GAAP earnings of $0.04 per share in the second quarter of 2023 and recurring earnings of $1 per share in the second quarter of last year. You will recall in the second quarter of 2023, we recorded the first of two impairment charges associated with our offshore wind investment of $331 million, or $0.95 per share. We also had other nonrecurring charges of $6.2 million, or $0.01 per share, in the second quarter of 2023. Both items are included in our GAAP earnings results for 2023. Breaking down the second quarter earnings results by segment, starting with electric transmission, which earned $0.54 per share compared with earnings of $0.46 per share in 2023. Electric transmission earnings increased due to rate base growth. Our electric distribution earnings were $0.42 per share for the quarter compared with earnings of $0.47 per share in 2023. The earnings decrease was due primarily to higher O&M expense, driven by higher storm restoration costs and the absence of a favorable prior year regulatory adjustment in New Hampshire, partially offset by higher revenues driven by NSTAR Electric's base distribution rate increase effective January 1 of this year. Electric distribution earnings are expected to be higher in the second half of the year, driven by capital cost recovery and New Hampshire's $61 million interim rate increase effective August 1. Our natural gas distribution business earned $0.08 per share for the quarter compared with $0.03 per share last year. The earnings increase was due primarily to higher revenues from NSTAR Gas' November 1, 2023 rate increase and lower O&M partially offset by higher depreciation, interest and property tax expenses. The Water Distribution segment contributed $0.02 per share for the quarter compared with $0.03 per share last year. The decrease in earnings was primarily due to higher O&M and interest costs. Eversource parent and other companies lost $0.11 per share in the quarter compared with recurring earnings of $0.01 per share last year. The main driver of this decrease was higher interest expense. Overall, our second quarter earnings results were in line with our expectations, and we are reaffirming our 2024 EPS guidance range of $4.50 to $4.67 as well as our longer-term 5% to 7% EPS growth rate. Turning to our regulatory update on Slide 10, starting with Massachusetts, as you may recall, we filed our electric sector modernization plan with the DPU in January, which is a roadmap to address growth from electrification needs. We expect a decision on our plan later this month. As a reminder, our electric sector modernization plan calls for $600 million of distribution capital investments for interconnection of clean energy resources and resiliency initiatives through 2028. This $600 million is incremental to our $23.1 billion five-year capital forecast we announced back in February. Next, I'm pleased to report that in early June, the DPU approved four additional capital investment projects to enable the interconnection of large-scale distributed generation resources on our system. Combined with the first project approved in December of 2022, these projects represent approximately $1 billion of total capital investment with $600 million of distribution investment and approximately $400 million of transmission investment. This $1 billion of investment is included in our five-year capital plan. In May, as per our settlement agreement related to the acquisition of EGMA, we filed our first rate base reset for rates to be effective November 1st of 2024. This filing reconciles our rate base, which has increased from $770 million to approximately $1.7 billion as of the end of 2023. This rate base reset is subject to a cap on the revenue change. With the application of this revenue cap, the proposed revenue increases are $78.7 million this year and $67.5 million effective November 1st of 2025. Closing out the Massachusetts regulatory items, we were pleased to receive final approval from the Massachusetts Energy Facility Siting Board for the Cambridge substation project. This is a $1.6 billion investment, of which $1 billion of investment is included in our five-year capital plan and the remaining balance in 2029 and 2030. This project consists of a new underground substation that will address the growing electricity needs of the city of Cambridge and the surrounding area. Turning to New Hampshire. PSNH filed a rate case in early June to recover more than $765 million of investment since our last rate case in 2019. The filing requests a rate range of $182 million in base distribution rates. That will take effect in two steps. The first rate adjustment will go into rates today, reflecting an increase of $61 million, with the remainder to go into effect on August 1st of next year. Interim rates will provide enhanced cash flows to the company until we receive a final rate decision next year. The filing proposes to recover investments made to improve reliability and includes recovery of increased costs associated with storm response and vegetation management due to the more frequent and more intense storm events. On blue sky days, the company's reliability investments in New Hampshire have certainly paid off for our customers. For example, banks in large part to investments in distribution automation technology, the percentage of New Hampshire customers restored in non-storm events in less than five minutes has improved from 30% in 2018 to over 50% in 2023. In addition, the company has rigorously controlled O&M costs since our last rate case. We have also proposed to implement a four-year performance-based ratemaking plan, including our capital support mechanism that would adjust rates annually to be approved by the commission. This mechanism enhances cash flow supports resiliency investments, replacement of aging infrastructure and investments for the integration of customer distributed generation while maintaining the additional transparency that comes with PBR. We anticipate a final decision in this case in 2025. In Connecticut, discovery is underway under storm cost prudency review for $634 million. We are also preparing to file for storm prudency review later this year for storm restoration costs related to events in 2022 and early 2023. As Joe mentioned, we received a decision from PURA allowing us to continue supporting the electric vehicle charging program for customers under a constructive cost recovery framework that will enhance our cash flow position. I'll now provide an update on some of the items shown on Slide 11 that will enhance our FFO to debt ratio from 2023 to 2025. First, the 2024 annual rate adjustment in Connecticut became effective July 1 of this year, recovering approximately $900 million of several costs, including public benefits related costs. The July 1st rate adjustment is recovering under collections from 2023 and has reset rates to a level matching recurred cost that we expect in 2024. Public benefit costs include the cost of energy supply contracts with the Millstone and Seabrook nuclear power plants and uncollectible hardship costs. Second, with the closing of our sale of Sunrise Wind to Ørsted, we received net proceeds of $152 million that will be used to pay down debt. Third, the closing of our sale of Revolution and South Fork Wind to Global Infrastructure Partners, we anticipate receiving gross proceeds of approximately $1.1 billion, subject to adjustments for capital expenditures. These proceeds will also be used to pay down debt. As a reminder, there is no impact to our financing plan from these capital expenditure adjustments. In addition, the filings for distribution rate increases at PSNH and at EGMA will provide additional cash flow enhancement. And lastly, regarding our equity issuances, we have raised approximately $250 million of equity through our ATM program and issued approximately 819,000 treasury shares in the first half of this year. We continue to anticipate equity means of up to $1.3 billion over the next several years, as shown on Slide 12. We are making progress on our effort to sell Aquarion Water Company. I'm happy to report that we have recently launched the initial phase of this process. All of the above actions give us a clear roadmap for improvement of our FFO to debt ratio in 2024 and give us confidence in achieving our 14% to 15% FFO to debt target at S&P in 2025. In summary, as you can see on Slide 13, we have a proven track record of earnings and dividend growth, and we are confident that our robust $23.1 billion five-year capital forecast and our forecasted financing plan will enable us to drive our 5% to 7% EPS growth rate through 2028 based off of our 2023 recurring EPS of $4.34. I'll now turn the call back to Matt for Q&A.

Operator:

Absolutely. . We will now begin the question-and-answer session. [Operator Instructions] The first question comes from the line of Shah Pourreza with Guggenheim Partners. Your line is now open.

Joe Nolan:

Good morning, Shah. Good morning.

Joe Nolan:

Yes. Well, thank you. As you know, I had committed to folks that we will work diligently on our relationships in Connecticut. This is one of the areas of focus. As you know, we talked about our exit from wind. I think you're seeing that we've successfully executing that strategy, working on Connecticut, the sale of Aquarion. With regard to Connecticut, I wish I could say that I had a high degree of comfort right now, the jury is still out. We are grateful for Governor Lamont's leadership. I think he's done a good job, and we'll continue to work at that. You have my commitment that I will continue to work on that relationship so that we get a stable regulatory environment for us to make any investments down there, especially on AMI because I've got to tell you, what's taking place in the energy markets, AMI today is more important than ever that we have a system that allows customers to make informed decisions around their use of energy. I think it saw what took place in the PJM markets, and this is the type of technology that we're going to need to deploy in our states in order to allow our customers to make those decisions around spending their dollars on energy.

Joe Nolan:

Yes, sure. So the governor is now at 4, but it will go down to 3 in January. I think the governor is committed. I mean, certainly, any discussions I've had with him, he wants to strike a balance, and that's what he has told me that he wants to strike a balance in Connecticut. So yes, he may go to 5. I think he's going to continue to work at it. It's a work in progress to make sure that he brings stability and regulatory certainty to the state of Connecticut. But again, it's -- we're taking a wait-and-see approach.

Joe Nolan:

Yes. Well, I got to tell you, first, in terms of the legislative process, and there was a lot of discussion on that. That one particular piece of legislation was designed to allow a bidder that in the absence of that legislation would not have been able to participate in our sale process. So it doesn't give them any more of a leg up than anybody else. We have a very robust group. So that was encouraging that this is a player that wanted to be there. They are a known entity in Connecticut. So the process will move forward. And we -- John, if you want to talk about with respect to timing?

Shah Pourreza:

Okay, guys, excellent. Thank you so much. We will see you soon. Appreciate it.

Operator:

Thank you. The next question comes from the line of Jeremy Tonet with JPMorgan. Your line is now open.

Joe Nolan:

Good morning, Jeremy.

Jeremy Tonet:

Hi. I just want to go back to the FFO to debt slide, if I could. I just want to make sure that I've seen that right, specifically on the under recoveries in the bridge. It looks like the $600 million is listed twice. So I just want to kind of clarify what's happening there.

Jeremy Tonet:

Got it. And…

Jeremy Tonet:

Got it. That's helpful there. And then I just want to go back to the offshore wind sale timing. Could you just update us there on, I guess, when everything would close? And I guess the time line shifted a little bit just wondering if there's anything to note there.

Jeremy Tonet:

Okay, I understood. I will leave it there. Thank you.

Operator:

Thank you. The next question comes from the line of Nick Campanella with Barclays. Your line is now open.

Joe Nolan:

Good morning. Yes.

Nick Campanella:

Hi. Yes. So I just wanted to -- just to follow up on Jeremy's question on the offshore wind. Just can you just maybe give us a state of the construction status on Revolution, where you stand on those costs and capital expenditures? And then just how much does Eversource actually incur an offshore wind CapEx for this year before you sell the assets to GIP? Thank you.

Nick Campanella:

Okay, no problem.

Nick Campanella:

And you guys still feel good about that underlying IRR that you have to kind of deliver to GIP as per the contract?

Nick Campanella:

I appreciate that. Thank you. I appreciate it. And Jeremy and I are friends, so that's totally okay. So just on storm cost recovery, the $200 million that you have in the FFO to debt enhancements, I know you're in the discovery phase right now, and there's been some shift in that proceeding over the last year. But just mechanically, do you have to file a rate case to get that cash recovery ultimately back and get that regulatory asset wind down? Or what's the rate case outlook in Connecticut for you currently? Just maybe you can walk us through that. Thank you.

Nick Campanella:

That's super helpful. I appreciate the clarification, and thanks for the time.

Operator:

Thank you. The next question comes from the line of Steve Fleishman with Wolfe Research. Your line is now open.

John Moreira:

Good morning.

John Moreira:

As of right now, I mean, we always continue to work with Ørsted on further updates. But as of right now, yes.

John Moreira:

That's correct. That's correct, Steve.

John Moreira:

Sure. Sure, sure. So I think you just nailed the answer to that question. We do have a lot of things in flux. Our forecast -- our financing forecast when we pulled it together and disseminate it as part of our guidance in February, had a lot of puts and takes. I had a lot of assumptions and we're still navigating our way through that. So I think it's a bit too early to give further guidance on our equity needs. Where we are today, as we stand here, $1.3 billion is the right number until certain things reach closure.

John Moreira:

What was the guidance that we've said over the next several years.

John Moreira:

Thank you, Steve.

Operator:

Thank you. The next question comes from the line of David Arcaro with Morgan Stanley. Your line is now open.

John Moreira:

Good morning.

John Moreira:

Yes. These are the major, I would say, headlines, right? However, things always change -- one of the items that's not included in the slide that has materially developed is some of the tax benefits that we've been able to harvest has generated some cash refunds. So that -- the 2024 alone we had an inflow of tax refunds of about $120 million.

John Moreira:

And the other thing that's noted that has not been quantified. But in my formal remarks, I did give you a lot of intel is the rate increases. We have EGMA going in with -- with a very sizable increase to start recovering the significant level of investments that we've made to that utility. And then we have the normal PBR rate mechanisms kicking in. And just yesterday, we got the approval to increase rates at PSNH, $61 million of interim rates. And within the next 12 months, we hope to have the final decision with another rate change effective August 1st of 2025. So that quantification would be further upside to this table that's shown, David.

John Moreira:

Correct. That would enhance the numerator and enhance our operating cash flows.

John Moreira:

Yes, we do expect to hit the cap. And I would say what gives us comfort is the fact that this was all assumed as part of our settlement agreement when we acquired the company. We worked through with the regulators, the key stakeholders as to what that -- the investments that, that entity needed, and that's why we needed this rate base roll in. This is the first of two rate-based roll-ins that will kick in. The first one is we -- as I just announced on the call this morning, kicks in November 1st of this year and then the second one will kick in November 1st of 2027.

John Moreira:

Thanks, David.

Joe Nolan:

Julien, welcome back.

Julien Dumoulin-Smith:

Thank you guys very much. I appreciate it. It's nice to chat with you guys again. It's -- look, let me follow up on a couple of the things have been flagged here speaking of returns here. How do you think about the green shoots in Connecticut? I want to talk a little bit more on that thesis for a quick second. I suppose, of the Yankee Gas filing at some point here, maybe late this year in December. How do you think about that foreshadowing any elements of that, call it, 4Q 2025 CL&P case? Anything that you'd be watching? Any items there? Again, I get it electric versus gas, but curious on that front. And then related, any items that you'd be watching on the PBR front, right, given that that's been kicked out here a little bit presumably a year or so. How do you think about the items that you'd be looking there for those presumed green shoots as well? So, thank you guys very much. Nice to chat.

Julien Dumoulin-Smith:

Excellent. All right. Fair enough. I hear you on that one. And then maybe related here, how do you think about just the amortization period, to the extent which you get that 600 change in Connecticut here, presumably in the next rate case, how do you think about the time period that, that recovery would entail? Again, I'm thinking with the FFO to debt to head on as you roll in out of that case.

Julien Dumoulin-Smith:

Okay. So about $100 million a year of uplift after you get that approved…

Julien Dumoulin-Smith:

Exactly. And presumably, that would be also trued up in the next case such that, that would be incremental for kind of a 2026 run rate?

Julien Dumoulin-Smith:

Okay, excellent. Thank you. Hey, see you guys soon, all right?

Julien Dumoulin-Smith:

See you.

Joe Nolan:

Good morning, Paul.

John Moreira:

Great.

John Moreira:

Yes. I think the -- and we're glad that it did get pushed out -- it allows -- and we've been pushing for this. It allows for us to bring in key stakeholders and collaborate with these key stakeholders in Connecticut to reach a very constructive PBR structure. We are very familiar with the PBR, what we have in Massachusetts. And recently, as I mentioned on the -- in my formal remarks, we're looking to introduce the same type of structure in New Hampshire.

Joe Nolan:

Sure. I mean we've been active participants in these forums. And I think as you know the one attractive piece of Eversource is that over 40% of our business is FERC related and transmission. So we're very good at it. I think we probably have the best engineering talent in the industry and any type of technology or deployment of technology or opportunities. I can promise you that Eversource will be at the forefront of them.

Joe Nolan:

Thank you. Thanks, Paul.

Joe Nolan:

Good morning, Anthony.

John Moreira:

Correct, which would be permanent because we offload our debt with that. And then on the numerator side, once again, as I previously mentioned, those numbers only reflect cash inflows to 2024 and 2025. Obviously, these deferrals will continue beyond that period.

Joe Nolan:

Thank you.

Operator:

Thank you. The next question comes from the line of Travis Miller with Morningstar. Your line is now open.

John Moreira:

Hi, Travis.

John Moreira:

New Hampshire. No, it's both Mass.

John Moreira:

No. Those -- the prudency review there's multiple things happening in Mass. So we do have a prudency review happening in Mass. These are what -- these costs have already been approved in rates -- so any -- for Massachusetts. The one in New Hampshire yes, a good chunk of that we filed for $240 million that's going through the prudency review there. That will kick in right around the time that permanent rates goes into effect, which will be in 2025. So there is a piece of that in here. And as I mentioned, both Massachusetts and New Hampshire has a five-year recovery window.

John Moreira:

Only, right..

Joe Nolan:

Yes. We were very pleased. I mean, that legislation goes hand in glove with our entire operation. I mean, the integrated planning and the type of clarity that's needed as we begin to advance our investments. I think that was really a very, very positive step for us, and it's something that -- it's what we're all about. We're about collaboration. And that's what's still refreshing there in New Hampshire as well as Massachusetts around collaboration that we understand what's important to those administrations, and that's what we're delivering on.

John Moreira:

As I mentioned, Travis, our New Hampshire customers have experienced the benefit from those investments that we've made.

John Moreira:

Thank you.

Joe Nolan:

Good morning, Ryan. They must have saved the best for wasp.

John Moreira:

Yes. No, as I mentioned in my formal remarks, Ryan, as we saw with the Sunrise we have to reconcile to the CapEx that was embedded in the original purchase price. But that in and of itself will not have any impact on our financing plan. We spend less than what we thought the purchase price comes down. We spend more than what we had agreed to the purchase price increases. So really, no impact whatsoever. And as it relates to the revolution as we've been saying right along, there is a potential contingency that we would be subject to from a construction standpoint that we have to be mindful. But as I mentioned, so far, the construction activity has gone pretty well.

John Moreira:

Not as of right now. We don't see that. No. No, no, nothing.

John Moreira:

Because once we close the transaction, the funding obligation flips to GIP.

John Moreira:

Okay.

Operator:

Thank you. There are no additional questions waiting at this time. So, I would now like to pass the conference back over to Matthew for closing remarks.

Operator:

That concludes today's conference call. Thank you for your participation. You may now disconnect your lines.

Joseph Nolan:

Thank you, Matt, and thank you all for joining us on the call this morning. Let me begin with an update on the sale of our offshore wind business. I am pleased to report that we are on track to close the sale of the 3 projects over the coming months. We are progressing well on the approvals necessary to close these transactions, as shown on Slide 3. We have filed all regulatory approvals with the New York Public Service Commission and FERC for the sale of South Fork Wind and Revolution Wind to Global Infrastructure Partners. And we recently executed the purchase and sale agreement for Sunrise Wind with Orsted.

Operator:

[Operator Instructions] The first question comes from the line of Shahriar Pourreza with Guggenheim.

Joseph Nolan:

Thank you, Shahriar. Over the past decade, we've spent a significant amount of money on electric reliability for our Connecticut customers. Our best-in-class engineering has moved months between interruptions from 10 months to nearly 2 years. So clearly, our investments have paid huge dividends for our Connecticut customers. However, the regulatory decisions over the past few years are misaligned with the law and the state policy. And without a secure and predictable cost recovery path, we cannot continue to put additional capital resources on the table. So our investment objectives in Connecticut have been centered around safety and reliability.

Shahriar Pourreza:

Got it. And Joe, can you cut more if need be?

John Moreira:

I would also add, Shahriar, that as a reminder, we do have a resiliency program in place, which we get timely recovery of up to $300 million of distribution investments at CL&P, which has been very, very critical for us to achieve this performance level that Joe just mentioned.

John Moreira:

Our view, and that will continue to be our position, is to be opportunistic in exploring and utilizing our ATM program to accomplish that. As I've said time and time again, an ATM program gives us tremendous flexibility. And we were very successful in executing at least through month $75 million. We've done quite a bit more over the past couple of weeks.

Carly Davenport:

I wanted to just start on the FFO to debt walk, thanks for the detail there. I guess, first, could you just remind us of the cadence of the 2023 under-recoveries hitting the cash flow statement this year? And then how should we just think about -- as we think about the other drivers that you'd identified, sort of the split between the impacts between the $1.8 billion and those other drivers?

Carly Davenport:

Got it. Okay. Great. And then maybe just on the Massachusetts ESMP process. What are sort of the next milestones for us to look out for their? And then just more broadly, how do you think about opportunities for the other states that you serve to adopt sort of similar frameworks?

Operator:

The next question comes from the line of Nick Campanella with Barclays.

Nicholas Campanella:

Okay. So still moving ahead, it seems. I appreciate that. I guess just a follow-up on Carly's question just around the FFO to debt, just -- the South Fork's tax equity investment would probably be, I would guess, more onetime in nature to the, I guess, cash flow improvement. But just -- I just wanted to kind of confirm like net of these kind of one-time items, you still see this path getting you to 14% to 15%.

John Moreira:

Yes. No, we certainly do, Nick, the tax equity. We actually think, as I stated, 24 months. That's probably a bit conservative. I think that will probably lead into 2026. We do have other tax benefits that we want to utilize for us before we tap into those ITCs. So that can be elongated a bit, which is great.

Nicholas Campanella:

And then just one last one for me just on Sunrise. I know that you're not giving the price, but -- last quarter, there was negative book value. I don't believe that the queue is out, but is that still the case or something that you can kind of talk about? Or do we have to wait for the sale agreement to be public for you to revise that?

Operator:

The next question comes from the line of Jeremy Tonet with JPMorgan.

John Moreira:

Yes. No, it's a mixed bag. So obviously, what's more critical is that we have the cash coming in, right, which will displace debt and obviously enhance our operating cash flows.

John Moreira:

Sure. I would frame it this way. It's not about a mad dash to the finish line. It's about a thoughtful process that we will run for the greatest value that we possibly can harvest. So that's what's important to us, is obtaining the greatest maximum value we possibly can. So if its transactions takes a bit longer, we are fine with that. The rating agencies are fully aware of the timeframe that we've mapped out with them. And obviously, they are comfortable with that.

John Moreira:

Absolutely, absolutely because it displaces debt.

Steven Fleishman:

Just maybe tie up one more question on Aquarion on the -- you mentioned appealing to the Supreme Court. Is there like a timeline? I don't know if you already filed that or when would you file that and when would you know if they take the case.

Steven Fleishman:

Okay. But you're not going to hold off the sale process to wait for that, you just move forward.

Steven Fleishman:

Okay. And then just on Connecticut Regulatory Environment. I appreciate the decisions being made there. Early in the year, there had been talk about the governor may be kind of expanding the commission and some changes there. Is that still being considered at all? And just -- I know you've been on an initiative to try to highlight these issues. Just do you feel like you're making any progress in resonating on the kind of quality of the regulatory environment being kind of investable?

Joseph Nolan:

Yes. I've got to tell you, one of the challenges -- first of all, we don't really have a sizing at this point. We're really in the first inning of this game, but the fact that they are interested around utility on solar, I take great confidence. But I will tell you the one thing there's no shortage of in the state of New Hampshire is land. And so that's where I see great opportunity.

Andrew Weisel:

In Connecticut, another question here, I agree the state policies and regulatory environment are not aligned. So I understand you're reluctant to put capital to work. My question is, what exactly is it that you're looking for? What would it take to get you more comfortable with the regulatory setup? Is it a qualitative good faith kind of conversation? Are you looking for something more explicit like preapprovals for spending on AMI and EVs?

Joseph Nolan:

No, I think we can do it in the regulatory arena. Certainly -- I mean, we're aligned with the governor, we're aligned with this other agencies. So we can have a collaborative effort that we submit a filing for all on the same page. Even the Attorney General, we have very, very strong relations there. But we just have to get pure, aligned with all of the other interests around the state so that we can get a constructive roadmap to move forward.

John Moreira:

Well, keep in mind that in that 300 to 400 basis point movement, it does include other cash flow items that we have not quantified in that $1.8 billion, Andrew, and then additionally, when the cash comes in, it's going to impact both the numerator and the denominator accordingly. So it's not a one for one.

Anthony Crowdell:

Just quickly on Slide 12, you had issued some parent debt already in the -- for the year. Do I think that's going to -- that's for the maturities at the bottom of this slide or the maturities you may also refinance and that's going to be incremental debt? And let me know if that's not clear.

Anthony Crowdell:

Great. And then just to stay on the mark with Connecticut questions. I know sometimes when utilities ramp up CapEx or they may be doing some new projects, they talk to policymakers, some regulators prior to it and get a feel of just the policymakers are on board with this increased capital that they're spending. I'm curious if something happened in Connecticut where you had similar discussions on actually to lowering of CapEx.

Operator:

The next question comes from the line of Durgesh Chopra with Evercore.

John Moreira:

Well, there's still a lot of things in flux, and I'm not -- we're not moving off of the $1.3 billion equity needs until we have more clarity, so as things evolve over the coming year. But right now, our position is to kind of work preparing the potential sale for Aquarion and get through Phase 1 and see what -- how that -- see what that looks like.

John Moreira:

No, no. If you look at the left-hand side of that slide on the bottom, we have other drivers. Those other drivers are cash inflows that we have not quantified. But yes, yes, yes. No, we have assumed -- as I continue to reiterate, in our financing plan that we have assumed the sale of Aquarion.

Joseph Nolan:

Yes. No, it's too early right now, but we continue to stay close to it, and we'll keep you updated. We did start though. The good news is we're in the ground, and construction is underway. So we're excited, and we're going to utilize the same practices that we successfully deployed in the construction of the South Fork project, which, as you all know, though, all 12 of the turbines are up, and they're running. And we're very, very proud that we are the first offshore wind provider in the United States.

Travis Miller:

Real quick one, staying on CL&P here. If you take out your depreciation or maintenance CapEx, how much of that additional CapEx is covered under an existing rider or tracker or something like that outside of a base rate? You mentioned energy efficiency. Is there other CapEx?

Travis Miller:

Okay. Okay. And then kind of a real quick follow-on on some of the other questions. Do you expect the clean energy policy overall, not necessarily just the rate setting, but clean energy policy overall in Connecticut will be a political issue this year? Or is that something for years down the road?

Matthew P. Fallon:

Sorry, Elissa, I just want to thank everybody for their time, and please follow up with IR with any additional follow-up questions that we can help out with. And I'll turn it back over to Elissa.

Robert Becker:

Good morning and thank you for joining us. I am Bob Becker, Eversource Energy's Director for Investor Relations. During this call, we'll be referencing slides we posted yesterday on our website. And as you can see on Slide 1, some of the statements made during this investor call may be forward looking. These statements are based on management's current expectations and are subject to risk and uncertainty which may cause the actual results to differ materially from forecasts and projections. We undertake no obligation to update or revise any of these statements. Additional information about the various factors that may cause actual results to differ and our explanation of non-GAAP measures and how they reconcile to GAAP results is contained within our news release, the slides we posted last night and in our most recent 10-K and 10-Q. Speaking today will be Joe Nolan, our Chairman, President and Chief Executive Officer; and John Moreira, our Executive Vice President and CFO. Also joining us today is Jay Buth, our Vice President and Controller. Now, I will turn the call over to Joe.

John Moreira:

Thank you, Joe. And good morning, everyone. This morning, I will cover our 2023 financial results, the offshore wind impairment, the 2023 regulatory update, an update of our 5-year investment forecast for our regulated businesses. And I'll wrap up with our 2024 recurring earnings guidance, long-term financing plan and 5-year earnings and dividend growth guidance. I'll start with 2023 results on Slide 10. Our GAAP results for the year were a loss of $1.26 per share, compared with GAAP earnings of $4.05 per share in 2022. In the fourth quarter, results were a loss of $3.68 per share, compared with GAAP earnings of $0.92 per share in the fourth quarter of 2022. Results for the full year 2023 include an after-tax impairment charge of $5.58 per share, related to our offshore wind investment and $0.02 per share after-tax charge related to our nonrecurring costs. Results for 2022 include a $0.04 per share charge, primarily related to transition costs associated with a completed integration of EGMA. Excluding these charges and the offshore wind impairment, our non-GAAP recurring earnings were $4.34 per share in 2023 as compared to $4.09 per share in 2022. Breaking down our 2023 full year non-GAAP recurring earnings of $4.34 into segments. electric transmission earned $1.84 per share for 2023, as compared with earnings of $1.72 per share in 2022. Improved results were driven by continued investments in our transmission system and lower income tax expense. Our electric distribution earnings were $1.74 per share in 2023, as compared with earnings of $1.71 per share in 2022. A base distribution increase at NSTAR Electric was partially offset by higher interest expense, property taxes and depreciation. Our natural gas distribution segment earned $0.64 per share in 2023, as compared to $0.67 per share in 2022. Increases in depreciation and interest expense, higher effective tax rate and the impact of certain reconciliation charges exceeded the revenues we received from capital trackers and base rate increases at NSTAR Gas and EGMA that became effective November 1, 2022. Our water distribution segment earned $0.09 per share in 2023, compared with $0.11 per share in 2022. Lower results were driven by higher depreciation, O&M expense and interest expense. The results reflect the impact of a very disappointing decision in Connecticut, from PURA for the Aquarion water rate case which is under appeal. Eversource parent and other companies' earnings were $0.03 per share in 2023, as compared with a loss of $0.12 per share in 2022. The improved results reflect a lower effective tax rate and the gain on our planned liquidation of a renewable energy fund, partially offset by higher interest expense and a contribution to the Eversource Charitable Foundation. Let me now turn to offshore wind, starting with the highlights of our sale of South Fork and Revolution Wind to GIP. With South Fork Wind expected to be in service before the transaction closes, our construction contingency is primarily related to Revolution. The terms of the transaction include a capital cost sharing agreement. Under this agreement, capital expenditure overruns incurred for the 50% interest in the project, up to approximately $240 million will be shared equally between Eversource and GIP. Above this threshold, 50% of any project cost overruns would be borne by Eversource. If the final project costs come in under the current construction forecast, Eversource will receive a payment for this difference. The terms and pricing of this agreement with GIP are assumed in the impairment charge and in our long-term financing plan. Let me review the offshore wind impairment, as shown on Slide 11. In 2023, we recorded impairment charges on our offshore wind investment of approximately $2.17 billion pretax or $1.95 billion after tax. As you can see on this slide, the impairment charge was driven by a lower-than-expected sales value of approximately $400 million for the 3 projects, after completing our strategic review in the second quarter of last year. As a result of adverse developments in the fourth quarter, including the further reduction in the expected sales prices driven by higher project costs and the October 2023 denial of the OREC pricing petition for Sunrise Wind, we realized an additional impairment charge in the fourth quarter of approximately $1.77 billion. The Sunrise Wind project drove about $1.22 billion of the impairment charge. In large part due to the OREC repricing denial which led to a lower assumed revenues and ultimately, an evaluation of the potential abandonment cost of Sunrise, if it is unsuccessful in the New York RFP for solicitation. As a reminder, to participate in the process to submit a rebid in the solicitation NYSERDA required any existing projects to terminate their current OREC agreements. This potential loss of both a contract revenue stream and ultimate project viability and any related termination costs was factored into our impairment analysis. Therefore, we assume that if Sunrise is not successful, in the rebid. This would result in no sales proceeds and no value attributable to the ITC adder. These items, coupled with estimated cancellation costs for the project, net of any salvage value, drove the additional impairment charge. Although we have factored this downside set of assumptions and probabilities into our impairment analysis, if Sunrise is ultimately successful in the RFP, Eversource would then sell its ownership interest in the project to Orsted, under the terms of our recently announced agreement. With the completion of that sale, our interest in Sunrise would be terminated. We would not be subject to any further construction contingencies or project cancellation costs. If we are successful selling Sunrise to Orsted, it would provide a full exit for the Offshore Wind business. Turning to Slide 12. I'll walk you through the carrying value of our offshore wind investment, as of December 31, 2023. The carrying value that I will discuss reflects the impact of our fourth quarter impairment charge by project. As you can see, the value of both Sunrise and Revolution were impacted by the fourth quarter impairment. The value of South Fork was not impacted. The fourth quarter impairment charge assumes a set of scenarios regarding potential construction contingencies for Revolution Wind. The charge also assumes that Sunrise Wind would be abandoned. We are very disappointed by the financial impact recognized on these early-stage Offshore Wind projects. However, we are comfortable with the impairment charge assumptions. We have reflected these assumptions in our long-term financial plan which I'll cover in a minute. As we move forward and finalize the sale of these projects, including the result of the recent New York RFP 4, the ultimate carrying value of our offshore wind investment, could change accordingly. On the regulatory front, we had another busy year. Our key 2023 regulatory items are highlighted on Slide 13. Starting with Massachusetts, we completed proceedings on our 2018 to 2021 storm cost recovery request, of approximately $136 million. I'm pleased to report that the Massachusetts DPU conducted a very thorough review and we received approval to recover 100% of our request. This approval highlights the importance of our storm response and acknowledges the tremendous effort from my Eversource colleagues and our contractors to restore customers as quickly and as safely as possible. Also in Massachusetts, we received approval of our first annual revenue adjustment under NSTAR Electric's PBR plan. This adjustment included an increase of a capital adjustment factor or CAPA [ph] as we call it. Turning to New Hampshire. We received the final order of proven $47 million of storm cost recovery, for weather events occurring in 2020 and in 2021. Again, we were granted nearly 100% of our request. We expect to file a general rate review in New Hampshire later this year, to recover the cost of investments that we have made over the last 4 years to significantly improve reliability for customers in New Hampshire. In total, we are now recovering approximately $400 million in rates, over the next 5 years for storm costs in Massachusetts and New Hampshire. In Connecticut, at the end of December, we filed our request for a prudency review of approximately $635 million of storm costs, relating to weather events that occurred from 2018 through 2021. The Connecticut filing contains more than 10,000 pages of support for costs incurred for these significant weather events. We look forward to working through the prudency review with PURA in 2024. Lastly, in our Aquarion's appeal of its March 2023 rate decision, oral arguments were held on January 11 and we expect the court decision over the coming months. Turning to our regulated utility capital plan. Slide 14 reflects our 5-year utility infrastructure investments, by segment updated through 2028. As a reminder, this plan reflects projects that we have a good line of sight on from a regulatory approval perspective. Over this 5-year period, we expect to invest approximately $23.1 billion in our regulated electric, natural gas and water businesses, to continue providing customers with safe and reliable service to meet ongoing load growth and to achieve progress on Clean Energy objectives. Starting with transmission. Our plan includes nearly $6 billion of transmission infrastructure investments, over the next 5 years. These investments include replacement of aging infrastructure to harden the system and increase resiliency during extreme weather events. Innovative substation projects undertaken for reliability and electrification purposes and interconnection projects, adding Clean Energy resources to the grid. Our Transmission capital plan includes a launch, scale, innovative project to build a substation in Cambridge, Massachusetts, completely underground. We are working closely with the city on this project which includes nearly $1 billion of investments to interconnect 4 existing transmission lines. This project will increase capacity to enable electrification and improve the reliability of electric service for customers. Turning to Electric Distribution. Our updated capital forecast now reflects nearly $10 billion of planned utility infrastructure investments, with a continued focus on system resiliency and our top-tier reliability for Electric Service. Our planned electric distribution investments include over $0.5 billion of our AMI program, in Massachusetts. The AMI program will allow customers to save money through heightened control over their own energy consumption and to experience higher service levels through faster outage restoration and other service functions. On the natural gas side, our 5-year plan reflects nearly $5.5 billion of investments and is centered around reliability and safety. The plan is highlighted by our bare steel and cast iron pipe replacement programs in Massachusetts and Connecticut. Across our natural gas system, we'll continue to thoughtfully engage with our states to ensure our investments enable equitable transition to a Clean Energy future. Turning to the water segment. Our 5-year investments are forecasted to be over $1 billion, supporting investments in water treatment facilities and water main replacements to improve water quality. Rounding out our Eversource capital plan, our investments in technology and facilities that's forecasted at $1.1 billion. Moving to Slide 15. Our updated capital plan reflects a $1.6 billion increase in utility infrastructure investments from 2024, through 2027 versus the prior plan. This increase reflects greater visibility on the work needed to serve our customers over the next 4 years. An important consideration in relation to our 5-year capital plan is what has not been included. On the right-hand side of the slide, we show some potential infrastructure investments not currently included in our forecast which would be additive to the plan. These opportunities total up to $2 billion in the forecast period with Connecticut AMI at the top of the list at nearly $700 million. The resulting impact from our updated capital plan, is shown on Slide 16. The customer-focused core business investments included in our capital plan would result in 7.7% growth in rate base from 2022 through 2028. Next, I will turn to our 2024 earnings guidance on Slide 17. We are projecting a non-GAAP recurring earnings per share range of $4.50 to $4.67 per share for 2024. Positive drivers this year include transmission investments for system resiliency and increased electric demand, distribution base rate increases in Massachusetts and New Hampshire, continued focus on controlling O&M expense and a lower effective tax rate. In 2024, our planned distribution rate increases include the first rate base roll-in for EGMA which will adjust rates to recover 6 years of capital investments. This rate adjustment will take effect in November of this year. These positive drivers are expected to be partially offset by higher expenses related to increased capital investments and share dilution. Turning to our long-term financing plan. I'll start with our cash flow assumptions regarding offshore wind, as shown on Slide 18. As I said earlier, our wind impairment reflects a set of assumptions that we have also embedded in our long-term financing plan. Let me walk you through what is assumed in our financing plan. First, we assume cash inflows from the announced sale of South Fork and Rev Wind of $1.1 billion. These proceeds include the value of the 10% ITC adder for Revolution Wind of approximately $170 million. Also assumed in our financing plan, is the realization of our tax equity investment in South Fork Wind which we expect will bring in around $500 million of cash over the next 24 months. The last item is related to our sale of Sunrise Wind to Orsted which is not assumed in our long-term financing plan. If Sunrise is successful in the New York RFP 4 that would be a positive to our plan. I'll now cover a number of drivers that are expected to enhance our FFO to debt ratio from 2023 to 2025, as you can see on Slide 19. These drivers include the Offshore Wind proceeds that I just discussed, planned rate increases at our utilities, recovery of storm cost deferrals, scheduled equity issuances and proceeds from a potential sale of our water business. In terms of the equity assumed in our plan over the next several years, we expect to issue up to $1.3 billion of equity through our existing ATM program. We will also continue to be opportunistic with our alternatives. As Joe mentioned, we are undertaking a review of our water distribution business. Proceeds from a successful sale are assumed in our long-term financing plan, reducing the level of equity that would otherwise be needed. As you can appreciate, we cannot provide any additional details beyond what we've disclosed. We will keep you updated on any decisions from this evaluation and any changes in our financial guidance. Closing now on Slide 20, our robust 5-year capital plan and long-term financing plan drive our 5% to 7% EPS growth rate, through 2028. To be clear, the 5% to 7% is based off of our 2023 recurring EPS of $4.34. Before we get to your questions, I'll turn the call over to Joe for his closing remarks.

Robert Becker:

Thanks, Joe. I'll turn the call back to the operator to begin Q&A.

Shahriar Pourreza:

Joe, let me ask you a question on the up to $1.3 billion equity, I guess without seeing sort of market interest with the inquiring sale and details around Sunrise, where you could get more proceeds than you embed and planned, depending on how things shake out, right which you just alluded to in your prepared, what's kind of giving you confidence around the $1.3 billion, can you beat it? And how are you thinking about the timing and the means of raising that equity?

Shahriar Pourreza:

Sorry but the timing and the means of that equity, any sense there?

Shahriar Pourreza:

Great. And then just lastly on this one is just on revolution cost sharing. John, can you just maybe walk us through the pathways for overages on the project? I mean what can go wrong? Any way to sensitize some of the puts and takes either on the construction side, i.e., how expensive does it get putting the crew on standby on the O&M availability side?

Operator:

We now turn to Steve Fleishman with Wolfe Research.

John Moreira:

Yes. I mean that was -- we like the ATM program for the reasons I've just stated, it gives us tremendous opportunity and we can take advantage of the market. But if we encounter a very favorable, attractive value, then we can do something -- we'll look to do something else. Whether it's a block or some other deals. So right now, we -- I want to have the most -- the greatest sense of flexibility to execute and maximize the value that we harvest.

John Moreira:

Yes. I mean we -- 2023, we have been challenged by our operating cash flow, is primarily driven by the turnaround and the methodology that we have been required to use as part of guidance from PURA. So for example, our -- we've been significantly under recovered at the COMP franchise in 2023, by a sizable amount close to $1 billion. So that's going to turn around and that's going to turn around in 2024 and 2025. We will get that cash in. So right now, we expect to be in the low single digits for 2023. We're still kind of working those numbers through. But moving forward, I feel confident that we'll be in a 14% to 15% FFO to debt, as I indicated in Slide 19. I'm sorry, I said low single digits. I'm sorry. I meant low double digits.

John Moreira:

Exactly. So the utilization of that, Steve, will happen based on our taxable income. So a lot can happen, storm costs being one of them that we take the deduction as we incur those storm costs and that can lower the utilization of that ITC. So right now, we've modeled it over the next 24 months but if we have further deductions from an operating standpoint, that would slip into '26.

John Moreira:

Correct; that's a reasonable approach.

John Moreira:

Yes. We don't have -- Connecticut is not factored in. As you -- we just said in the formal remarks, we filed for the prudency review. That's going to take some time. So none of that, it's all really predicated on Massachusetts and New Hampshire. However, once the Connecticut storm cost recovery kicks in, that will give us more inflow of cash for the out years beyond 2025.

Nicholas Campanella:

So good to see you reaffirming the 5% to 7%, I guess, just you previously used to say high end of that range. I just wanted to kind of clarify if you have any message on where you kind of stand in the 5% to 7% at this point? And then how do we kind of think about Aquarion sales kind of impact to that 5% to 7%? Is it baked in? Does it put you somewhere else in the range depending on those outcomes there?

Nicholas Campanella:

Okay. I appreciate that. And then I guess just sticking with Aquarion, obviously, you're trying to find ways to mitigate equity issuance in the 5-year plan. Just what's inspiring your confidence to kind of come back to do another sales process at this point? Do you feel confident it's not going to be as drawn out as the last one? And then just how do we kind of think about like the time line and then also the agency's willingness to kind of see through another asset sale, just given you're still on negative outlook?

John Moreira:

And I would just add, Joe, is spot on from an execution, this is a totally different animal. And then from your latter question on how the agencies, as long as we have a pathway, this kind of mitigates any further equity needs that we may have. So it's still cash coming in the door which is very appealing and supportive of our credit metrics.

David Arcaro:

Could you just touch on cost savings initiatives. I think you mentioned that you're expecting lower O&M in 2024. I guess how much lower? What are the levers you're pulling there? And what are you thinking kind of going forward off of a 2024 base there, too?

David Arcaro:

Okay, great. Then, I just wanted to clarify maybe on the New York 4 outcome with the auction. How could that change the outlook? Is -- are you saying the proceeds for Orsted are not currently contemplated in the equity need guidance? And could that come down from where it is now based on being successful in that auction?

David Arcaro:

Yes, makes sense. Then just wanted to quickly clarify. Just the $1.3 billion, does that include the DRIP? Or do you -- what do you expect that to be on an annual cadence going forward?

Operator:

We now turn to Durgesh Chopra with Evercore ISI.

John Moreira:

I would say it's a combination of both. Yes, we did leave the CapEx, their CapEx in our forecast but it's clear, it's delineated. You can see how much that relates to. And the fact that in my formal remarks, I highlighted and we have it in the slide on the deck that if you look at the forecast period, forecast over forecast, we're up $1.6 billion. And in my formal remarks, I also indicated that we should be mindful of what has not been included in our 5-year forecast. And that amount could be up to $1 billion to -- up to $2 billion, once again within this forecast period. So we feel very, very optimistic, we are able not only to replace the earnings but also mitigate any of the dilution.

John Moreira:

Yes. I mean, obviously, they have dipped a little. We've been out of Connecticut for quite some time. We've had the settlement agreement. I would say that they're probably in the CL&P [ph] is around hovering around 8% and Yankee in the 7% range.

John Moreira:

Well, I mean, we were -- we've determined that we're going to stay out for at least another year or longer. So we model in the appropriate assumptions as we normally do with any rate proceeding in our 5-year forecast.

Agnieszka Storozynski:

So just maybe first on assumptions behind the equity needs. So again, if I just look at the $1.3 billion and what I would expect Aquarion could bring. That's a little bit -- it seems like we're getting close to $3 billion in equity, again, my estimates, that seems large versus our prior expectations. And I'm just wondering what kind of credit assumptions you have embedded in it? So do you expect that, that amount, whatever the number is, eventually allows you to keep current ratings -- credit ratings, especially with the S&P?

Agnieszka Storozynski:

Yes. And then secondly, you have this port challenge for Aquarion's rate case. And I'm just wondering if, one, there's an outcome we need for that sale process to be successful; and two, if you approach the regulator in Connecticut about this potential sale?

John Moreira:

Angie, I would just add that, quite honestly, as Joe mentioned, we should see that court decision in the next couple of weeks. That's our expectation. And that would actually be behind us before we execute on the transaction.

Joseph Nolan:

Yes. No, we've had communication with the governor. I did talk to the governor and I let him know of this transaction. As you know, it's quasi-judicial Board, the PURA and there's certain things they can and can't talk about. So we're trying to be very mindful of that.

John Moreira:

Angie, you're spot on. As you heard from me, our growth rate 2023, compared to '22, hovered around a 6% growth rate. We just -- as Joe mentioned, the Board just approved on an annualized basis, another 6% dividend increase. So we have a long-standing record of continuing to grow our dividend in line with our earnings.

Anthony Crowdell:

Just I guess two quick ones. One to follow up from Steve's question. I think you were talking about maybe some ITCs in your FFO to debt metrics. Any chance you could tell us what amount of ITCs you booked in '23 earnings and what your forecast is in '24 earnings?

Anthony Crowdell:

Great. And then just lastly, on the 8-K you filed this morning, gave some more details on the transaction. I believe in it, you guys have guaranteed an IRR to the buyer of roughly 13%. If you use your best estimate today of what you think the project would cost and your best estimate forecasting everything, where do you think the IRR stands today?

Anthony Crowdell:

Well, I guess I'm wondering, it's at 13%, we were maybe forecasting a lower IRR of the project based on our assumptions. And so we're thinking that -- or is there from day 1 that you assume that there's a payment going out to the buyer to get to the 13% IRR?

John Moreira:

Yes, that's right.

Paul Zimbardo:

To clarify, what's the forecast for capital investment into offshore wind into 2024 and specifically kind of before the close of the transaction?

Joseph Nolan:

And whatever we put in comes back to us. It's not as if we're going to be out of any money.

John Moreira:

Yes. I mean, where we landed in 2023, I would say, high teens and where we project to be in 2024 is also in the high teens, I would say, 18% to 20%, is the effective tax rate. So some of the benefits that we were able to recognize, we see those recurring in 2024.

Ryan Levine:

On the cost sharing or earnout clawback like structure, what's the time line where you would receive cash payments, if costs were lower than targets? And conversely, if there's any cash flows -- cash outflows? And any sense on timing when you expect those payments to be made?

Ryan Levine:

Okay. And then given the uncertainty of the contingent payments, would you look to wait to time your equity issuance once you have resolution on COD?

John Moreira:

Yes. And that's been factored into our financing plan, the timing of when that would reach COD and so we're -- we feel good. Joe, in his formal remarks and some of the Q&A that he's responded to, we feel good where we are with the most current forecast -- construction forecast for Revolution and that has become the baseline for the sharing.

Joseph Nolan:

No, it's -- the process has not started. It's going to -- last night, we kicked it off and it will be -- we'll get to work on it as soon as this call is over.

John Moreira:

No, we don't. I just reiterated what our expectations are for both long-term earnings, EPS growth of 5% to 7% and we have -- we expect to grow our dividend in line with the earnings growth.

Travis Miller:

On the Revolution, what kind of involvement are you going to continue to have on the operational construction side? And I'm thinking in part to make sure that the costs stay in line with your estimate. Will you be involved in the project or more third party?

Travis Miller:

Okay, perfect. And then going back kind of strategic over the years. I think one of the initial thoughts that you had behind all these nonutility investments was to reduce some of the exposure to Connecticut. Now it seems like you've come back and now have more of that exposure post this. What's kind of changed over the years to -- in Connecticut to suggest that you think perhaps a better operating environment -- investment environment there?

Operator:

[Operator Instructions] We now turn to Paul Patterson with Glenrock Associates.

John Moreira:

I believe Anthony's question was more on the ITC.

John Moreira:

No.

John Moreira:

Yes. Paul, a couple of things there. Number one, quite honestly, we were a bit disappointed that docket or those dockets, there is actually 3 of them got delayed or pushed out a bit. So I think it's still far too early for us to speculate because I think there are proceedings that we wanted to take place. And now some of those will likely happen. So we can't speculate, as to what the outcome would be at this point. I think there's a lot more work and a lot more discussion with PURA that will have to take place.

Aidan Kelly:

This is actually Aidan Kelly on for Jeremy. Just one quick question on our end. What was the parent interest expense drag in '23 versus '22? And could you just talk about like the offsets behind that?

Operator:

This concludes our Q&A. I'll now hand back to Bob Becker for final remarks.

John Moreira:

Thank you, everyone.

Operator:

Ladies and gentlemen, today's call has now concluded. We'd like to thank you for your participation. You may now disconnect your lines.

Robert Becker:

Good morning, and thank you for joining us. I'm Bob Becker, Eversource Energy's Director for Investor Relations. During this call, we'll be referencing slides we posted on our website. And as you can see on Slide 1, some of the statements made during this investor call may be forward-looking. These statements are based on management's current expectations and are subject to risk and uncertainty, which may cause the actual results to differ materially from forecasts and projections. We undertake no obligation to update or revise any of these statements. Additional information about the various factors that may cause actual results to differ, and our explanation of non-GAAP measures and how they reconcile to GAAP results, is contained within our news release, the slides we posted this morning, and in our most recent 10-K and 10-Q. Speaking today will be Joe Nolan, our Chairman, President, and Chief Executive Officer; and John Moreira; our Executive Vice President and CFO. Also joining us today is Jay Buth, our Vice President and Controller. Now I will turn the call over to Joe.

John Moreira:

Thank you, Joe, and good morning, everyone. This morning, I will review our results for the third quarter of 2023, discuss the status of our offshore wind investments, and review our cash flow position. Let me start with Slide 6. Our GAAP and recurring earnings were both $0.97 per share in the third quarter of 2022 compared with GAAP and recurring earnings of $1 per share and $1.01 per share respectively for the third quarter of 2022. GAAP results for 2022 include transition and transaction costs related to Eversource Gas Company of Massachusetts of approximately $2.2 million. As a reminder, results for the third quarter of 2023 reflect a negative $0.08 per share impact for NSTAR Electric's rate design change, as shown on slide 7, adjusting the earnings for the third quarter of 2023 by this amount would result in both GAAP and recurring earnings of $1.05 per share. As I have previously mentioned, this rate design change does not impact full year results. Moving back to Slide 6 and looking at some additional details on the third quarter earnings by segment, starting with our Electric Transmission segment, which earned $0.46 per share in the third quarter of 2023 as compared with earnings of $0.44 per share in the third quarter of 2022. Improved results were driven by our continued investments in our transmission system. Our third quarter 2023 Electric Distribution earnings were $0.50 per share, compared with earnings of $0.65 per share in the third quarter of last year. The earnings decrease is due primarily to the timing of the rate design change at NSTAR Electric that I mentioned earlier, as well as higher storm-related costs, higher interest costs, depreciation, and property tax expense. These factors were partially offset by higher distribution revenues at NSTAR Electric and from capital trackers that we have in place. Our Natural Gas Distribution segment lost $0.10 per share in the third quarter of 2023 as compared to a loss of $0.07 per share in the third quarter of 2022. The increased losses were due to higher regulatory and operating expenses, depreciation, and interest expense, and were partially offset by higher revenues from the base rate increases at NSTAR Gas and EGMA which took effect November 1 of 2022. Our Water Distribution segment earned $0.05 per share in the third quarter of 2023, which is the same level, we are in the third quarter of last year. Eversource Parent and Other Companies' recurring earnings were $0.06 per share in the third quarter of 2023, as compared to a loss of $0.06 per share in the third quarter of 2022. The improved third quarter results primarily reflect a lower effective tax rate, that was partially offset by higher interest expense. Turning to Slide 8. Based on our financial results to-date and our strong cost discipline, we are narrowing our 2023 recurring earnings projection to between $4.30 to $4.43 per share compared with our previous range of $4.25 to $4.43 per share. Looking at our longer term earnings growth rate expectation, as you saw in our news release and can see on Slide 8, we are reaffirming our long-term EPS growth rate solidly in the upper half of the 5% to 7% range. We are also reaffirming our $21.5 billion five-year regulated capital program, as shown on Slide 9. Current capital expenditures totaled approximately $3.2 billion in the first nine months of 2023. Now, to further expand on what Joe covered, we reached an important milestone in our effort to exit our offshore wind business. On September 7th, Eversource completed the sale of its 50% interest in the lease area that includes approximately 175,000 developable acres to Orsted for $625 million in an all-cash deal. We also closed on our tax equity investment in South Fork Wind with Orsted. We used $528 million of the proceeds from the lease area sale for our tax equity investment. As a current 50% equity partner in South Fork, half of this tax equity investment or $264 million was returned to us in October. We expect to recover the tax equity investment primarily in the form of tax credits once the turbines are placed in service. These tax credits will be utilized to reduce Eversource's federal income tax liability, including refunds from prior years expected over the next 12 to 18 months. As Joe mentioned, we continue to make good progress on advancing the sale of our existing 50% interest in our three offshore wind projects. On our second quarter earnings call, I discussed one of our contingent considerations with the sale of the projects, that we expected a positive outcome from the Sunrise Wind OREC repricing petition, representing approximately $450 million in value to Eversource. Although we were very disappointed by the New York Public Service Commission's rejection of the pricing petition, we are encouraged by NYSERDA's quick reaction in its request to run an accelerated RFP process. As I previously indicated, advancing the sales transaction was not contingent on a resolution of Sunrise's OREC repricing petition. As we assess our options for an OREC rebid for Sunrise, we could potentially see a scenario whereby we move forward with the sale for South Fork and Revolution Wind, followed by a transaction for the sale of Sunrise with the buyer. As we navigate through this accelerated RFP process, we will continue to look at every alternative to keep this sales process moving forward in an efficient and timely manner. Now, I'd like to update you on our expectations for qualification for the two additional 10% investment tax credit adders under the Inflation Reduction Act or IRA. We had previously assumed a positive outcome regarding one additional 10% adder for Sunrise Wind and Revolution Wind that represented approximately $400 million in value to Eversource. Let me start with the Energy Communities. We do believe there is a good path around the prospects for qualifying for the Energy Communities provision of the IRA for both Sunrise and Revolution, which would increase our potential ITCs to 40% of the eligible basis for these projects. Therefore, the Energy Communities' qualification would cover this contingent value that we have recognized. Also, we will continue to explore opportunities to engage with the Treasury Department, as they clarify the rules around the domestic content provisions of the IRA to qualify for an additional 10% investment tax credit. As a reminder, the $400 million in value I just mentioned, is based on achieving a single quantification outcome between either the Energy Communities or the domestic content adders. As assumed in our second quarter offshore wind impairment charge, we only assume one additional 10% ITC adder as a contingent consideration. Should the projects qualify for both the energy communities and the domestic content adders, it would result in upside to Eversource. We will continue to monitor both the RFP process and the ability to qualify for one or more of the ITC adders and evaluate their impacts along with other potential impacts, as part of our continual review of our impairment models. As a part of this evaluation, an important consideration will be the likelihood of success of any future bid award for Sunrise Wind from this accelerated RFP. Turning to cash flows. First, let me say that maintaining strong credit ratings is very important to us. Therefore, we are disappointed with the recent credit rating action taken by Moody's as the timing was a bit unfortunate. Our short-term ratings were not impacted by this action and therefore we should not see any impact on our commercial paper cost. As it relates to future long-term financing cost, we see potentially minimal impact. We expect our cash flows will be enhanced and more specifically, an improvement in our ratio of funds from operation relative to debt or FFO to debt. Although we expect that our 2023 FFO to debt would be a bit weak primarily given the delay in closing the offshore wind sales transaction, however, moving forward, we expect our cash-flow position to increase significantly. There are several factors we expect to contribute to enhancing our FFO to debt ratio well beyond the new threshold of 13% of FFO to debt by 2024 and beyond. A key factor driving an improvement in cash flows are the proceeds from the sale of our offshore wind projects along with eliminating the project funding requirements. You may recall that as of June 30th of 2023, the carrying value of our offshore wind investment was $2.1 billion, net of the $401 million pre-tax impairment charge and the proceeds from the sale of the lease area. We have previously indicated that there are approximately $850 million of contingent considerations as part of the sale that is comprised of the $450 million pricing adjustments or now an RFP rebid for Sunrise OREC. If successful with the RFP award, this cash flow would be received when the transaction closes. In addition, as I previously discussed, a potential $400 million from the energy communities of a 10% ITC adder quantification would be received when the projects reach COD, which we expect in 2025. Cash flows will be further enhanced from our core regulated businesses from electric and gas distribution rate adjustments primarily in Massachusetts and other cost recovery mechanisms. We anticipate additional deferred storm cost recovery of about $400 million to $500 million rolling into rates during 2024, that will be recovered over a five-year period. Also of note, we will fully monetize our $528 million of South Fork tax equity investment through lower tax payments and refunds, which will further contribute to an improvement in our cash flow and provide the ability to pay down debt, including a portion of the $1.4 billion of parent debt maturing in 2024. Lastly, we are committed to completing the $1 billion equity as part of our ATM program. As shown on Slide 10, we have issued no additional equity under this program through October. We also anticipate raising an additional equity through our dividend reinvestment and employee incentive programs through October, and we have issued 900,000 shares under that program. Thank you for joining us this morning, and I look forward to seeing many of you next week. I will now turn the call back over to Bob for Q&A.

Operator:

Thank you. [Operator Instructions] Our first question for today comes from Shar Pourreza of Guggenheim Partners. Your line is now open, please go ahead.

Joseph Nolan:

Good morning, Shar.

Joseph Nolan:

Great. Well, thanks, Shar. Let me start with the RFP. While the merits of our repricing petition were in line with the recent NYSERDA RFPs and the resulting price ask from our petition was lower than the average price of a recent New York awards, our repricing petition was denied, unfortunately by the New York PSC. The primary reason, Shar, they cited was the pricing adjustments would have been done administratively rather than through competitive procurement, which is what they did not want to do. However, you'll see that NYSERDA then issued an RFP right after the denial for a future RFP for additional offshore wind. We have responded to that recent New York RFI and we'll evaluate the RFP terms. Given the maturity of Sunrise, in terms of the citing, permitting and early construction, this project is probably best positioned to win this RFP. John, you can hit on the impairment question for Shar, please.

Shahriar Pourreza:

Got it. And then, John, you mentioned that the sale process could be split with Sunrise later, which is kind of helpful, I guess. What could that look like? How should we think about the implications for investing in the project and timing? Basically, will you be on the hook for it? And any contingencies? Thanks, guys.

Shahriar Pourreza:

Got it. Perfect. I appreciate, guys. I'll jump back in the queue. I know there's others that want to ask. Thanks.

Operator:

Thank you. Our next question comes from Steve Fleishman of Wolfe Research. Your line is now open, please go ahead.

Joseph Nolan:

Good morning, Steve.

John Moreira:

Sure, sure. As I said in my formal remarks, we pride ourselves in having very strong credit ratings, and that's important to us. And my remark on the unfortunality of it is that the fact that we do see a significant enhancement in 2024 that would get us well above the 13%, and quite honestly, probably exceeding the 15% threshold. But we fully understand the predicament that Moody's they've been in with a negative outlook for quite some time. Storm activity, as I've mentioned, in the past three years, have been -- have created a headwind for us from a cash flow perspective, but we do see that enhancing in the years to come.

John Moreira:

Well, Steve, let me start by saying that having -- being at the 13% right now does give us a little bit more flexibility where we can be opportunistic from an equity standpoint. But as I've said, I don't want to lose sight of the fact that we strive on maintaining a very strong credit rating. And right now, based on our plan, I do see -- everything else being equal, I do see us getting to 15% by the end of 2024.

John Moreira:

That's what I confirmed in my formal remarks. That is correct.

John Moreira:

Yeah, I mean, we've done a great job in managing to the current year exposure, and we will continue to be focused on that. We are very disciplined in our O&M strategy, and we've been very successful, as a matter of fact. As a result of that cost discipline, we've been able to narrow our guidance range, our EPS guidance range. So, yes, I would say to frame it, when I started the year, I didn't think the Feds were going to move as rapidly as they did with increase in rates. So it has put some further pressure on us, and we have a plan that will get us to where we need to be.

John Moreira:

That's correct. That is correct.

John Moreira:

Thank you, Steve.

Operator:

Thank you. Our next question comes from David Arcaro from Morgan Stanley. Your line is now open, please go ahead.

David Arcaro:

Thanks so much for taking my question. Hey, good morning. Let's see. Maybe just following up on Steve's last question. If rates stay where they are, do you continue to see the ability to hit solidly in the upper half of your guidance range? And maybe could you elaborate on some of the cost-cutting initiatives where the opportunities are that you see going forward?

David Arcaro:

Okay, great. That's helpful. And then also just looking out at the FFO to debt trends you've got a couple or I guess I'm thinking of the tax equity payment in 2024, that's a bit of a one-time boost. But then post 2024, is there a trend off of that year where you expect FFO to debt to trend naturally just based on the core business outlook, does it fall below 15% after that or are there ways to maintain it in that rough range? Thanks.

David Arcaro:

Okay, got it. Thanks. Appreciate the color.

Operator:

Thank you. Our next question comes from Nicholas Campanella from Barclays. Your line is now open, please go ahead.

Joseph Nolan:

Good morning, Nick.

Joseph Nolan:

Sure. Thanks, Nick. I'll take I'll take a crack at it and then John can pipe in. Couple of things we're not -- we have no plans of filing a rate case in Connecticut. We actually -- the settlement precludes that until 2025. So that would be the earliest, although not required at that point. Our storm cost filing is in very good shape and the filing is imminent at any time, we can make that filing as well. Again, that's a filing that we need to go through first, a review of it. So it's -- they'll go through all the documents and make sure that everything is in order so that it's something that you want to deal with outside of a rate case. We'll get that behind us, get the amount established, and then that way there it makes for a simpler or less complex rate case. So that's the current thinking right now. John, if you want to add any color, feel free.

Nicholas Campanella:

That's helpful. And then just one follow up on the assumptions underlying the 5% to 7% EPS CAGR here, like acknowledging that you're continuing to point to the high end of that range. you do have the ATM outstanding and you haven't issued a lot of that, and multiples are lower. So I'm just trying to understand, is this like a true mark to market of if the stock price stays where it is, you still see this as an executable 5% to 7% CAGR? Thanks.

Nicholas Campanella:

Thank you.

Durgesh Chopra:

Hey, good morning, team. Thanks for taking my questions. Hey, first, just can you tell us what's the expected spending on the offshore projects this year? I think you're targeting roughly $1.5 billion per the Q3 slides.

Durgesh Chopra:

Okay.

Durgesh Chopra:

Got it. Okay. And then just going back to the equity question, just off the remaining amount that you've -- kind of the $1.2 billion, what's the -- any help you can give us on timing of how you might execute on that equity?

Durgesh Chopra:

Okay. So not this year, right obviously?

Durgesh Chopra:

Okay. Thanks.

Jeremy Tonet:

Hi, good morning.

Jeremy Tonet:

Hi. Just starting off here, coming back to the sales process announcement and realize there are elements that are outside of your hands here. But if we're thinking about timing here, is this a matter of, like, days, weeks, or months? And are you able to identify any material gating items at this point or other risks around these negotiations? Just trying to get a sense for how the process could unfold at this point.

Jeremy Tonet:

Got it. Very helpful there. Thank you. And then just pivoting back to equity. Just want to clarify a couple of points here to make sure I got it right. The $1.2 billion of external equity needs, is this kind of embedding, I guess, offshore wind sales price to a certain level, and does this assume higher New York price and success on one of the two IPC adders? Just trying to get clarity on what is factored in at that point. And then just to confirm, I guess, what you talked about earlier, the plan reaffirmation is based on current stock price levels, or does that need to be kind of reevaluated later for the 5% to 7% growth?

Jeremy Tonet:

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

Anthony Crowdell:

Hey, good morning. Just a couple of questions. First, on Sunrise, I think, on -- Orsted last week lowered their probability of being successful on a rebid. I mean, you guys seem very optimistic on a rebid. Just curious if there's any change in your thinking on Sunrise versus maybe last quarter.

Anthony Crowdell:

Great. And just curious, on the pricing, I don't know if you want to disclose it. But I just said the pricing you submitted to the New York Public Service Commission was attractive. On the rebid, could we assume that that price would exist on the rebid or through the rebid there's a chance that pricing could even go up higher or lower? I mean, could the pricing change?

Anthony Crowdell:

Great. And then just lastly, a whole bunch of moving pieces in this story. Big improvement in FFO to debt we should start seeing in 24. Just when we think about when all the dust settles, I mean, does 2024 look like it becomes a transition year and the offshore wind clears up? Or do you think that happens sooner, or does the cleanup to a fully regulated story happen more in 2025?

Anthony Crowdell:

Great. Thanks for taking my questions. I appreciate it.

Operator:

Thank you. Our next question comes from Julien Dumoulin-Smith of Bank of America. Your line is now open, please go ahead.

John Moreira:

Sure, Julian. So the capitalized interest right now is about -- I don't know, I would say $25-ish million. And that's all at the parent company, $25 million, $30 million.

John Moreira:

Well, with the cash inflows that I've mentioned, including some of the utilization of ITC, we can't lose sight over that, that I feel we would be able to harvest within the next 12 to 18 months, that's close to $500 million coming in the door, plus the proceeds from the offshore wind. We will turn the corner in 2024 and beyond. So, I do as Joe mentioned, 2024 is the pivotal turning period for us.

John Moreira:

And Julian, we have, as I mentioned in my formal remarks, is $1.4 billion that will mature at the holding company in 2024. And that's all back end half year, those maturities will take place June and October.

John Moreira:

Okay, so the breakup fees that Orsted announced on their call, we're 50% partner. So we would be on the hook for that 50% as well.

John Moreira:

The proceeds from the sale?

John Moreira:

Yeah. I mean, we haven't disclosed that, but I think you can certainly kind of assess that as to where we stand. And the reason is that it's a moving target as to when the transaction closes because we still have this funding commitment. But if you draw the line in the sand, as of [$9.30 million] (ph), I mentioned that our total investment was $2.1 billion, and we have $850 million of contingent consideration that covers that balance. So the balance would kind of be in the range of what you would expect.

John Moreira:

Take care, Julien.

Operator:

Thank you. Our next question comes from Travis Miller of Morningstar. Your line is now open, please go ahead.

Joseph Nolan:

Hey, Travis. Good morning.

John Moreira:

Travis, we're so excited about that plan that we filed because it does differentiate Massachusetts as being very progressive in that regard. And we're working with the key stakeholders, as Joe mentioned in his formal remarks. I would say from a cost recovery mechanism, I think it's far too early for us to speculate as to what that would be. We need this process to continue to kind of play out a bit more. Right now, as per the legislation, it's before this council, this Grid Mod Council that's made up of key stakeholders and policymakers of Massachusetts. So that is still being reviewed by the Council, and we'll file that early 2024 with the DPU. So I think it's a bit premature to start speculating on the recovery mechanisms.

John Moreira:

I would say 70-30. 30 be in O&M.

John Moreira:

Yeah, I mean, consistently we've been at 62%, and our dividend policy supports that payout.

John Moreira:

Thank you, Travis.

Paul Patterson:

Hey, great to hear you guys. Just really..

Paul Patterson:

Just really -- I guess really almost -- all my questions have been sort of answered. But I'm sorry to be a little bit slow on the timing here. Sounds like before we may get a final transaction sort of crossed T's dotted I's by the end of the year. And I'm just wondering, you mentioned the NYSERDA rebid process. If you could just go over, again, I apologize for being a little slow on this. The timing you're expecting on that and how that might impact this potential for splitting up this -- the South Fork versus the other projects and what have you?

Paul Patterson:

Okay. And then, I guess the -- okay, you answered it. Thanks so much.

John Moreira:

Thanks, Paul.

Joseph Nolan:

Yeah. I want to thank everybody for taking the time to join us this morning on our earnings call. I'm looking forward to seeing many of you next week in the desert at the EI Financial Conference, and we can spend some more time digging into any of the details that are important to you. And also, as you know, our investment relations team is always available to answer any questions that you might have in the interim. So thank you again for your time, and have a wonderful day.

Robert Becker:

Good morning, and thank you for joining us. I’m Bob Becker, Eversource Energy’s Director for Investor Relations. During this call, we’ll be referencing slides we posted yesterday on our website. And as you can see on Slide 1, some of the statements made during this investor call may be forward-looking. These statements are based on management’s current expectations and are subject to risk and uncertainty, which may cause the actual results to differ materially from forecasts and projections. We undertake no obligation to update or revise any of these statements. Additional information about the various factors that may cause actual results to differ and our explanation of non-GAAP measures and how they reconcile to GAAP results is contained within our news release, the slides we posted last night and in our most recent 10-K and 10-Q. Speaking today will be Joe Nolan, our Chairman, President and Chief Executive Officer; and John Moreira, our Executive Vice President and CFO. Also joining us today is Jay Buth, our Vice President and Controller. Now I’ll turn the call over to Joe.

John Moreira:

Thank you, Joe, and good morning, everyone. Today, I will review our results for the second quarter of 2023, including our offshore wind impairment charge, and I’ll also discuss our recent offshore lease sale transaction give you a status update and review our 2023 financing activity. So let me start with Slide 9. Our GAAP earnings were $0.04 per share in the second quarter of 2023 compared with GAAP earnings of $0.84 in the second quarter of 2022. As we announced in May, based on our completion of the Offshore Wind Strategic Review and the status of dependent project sale process, the results for the second quarter include an after tax impairment charge of $0.95 per share related to Eversource Energy’s total offshore wind investment. I will review details of this impairment in a few minutes. Results for both years include transaction and transition costs related to the acquisition of Eversource Gas Company of Massachusetts and other charges that total $6.2 million in the second quarter of 2023 compared with $5.5 million in the second quarter of 2022. Absent these charges and the offshore wind impairment, our recurring earnings were a $1 per share in the second quarter of this year compared with $0.86 in the second quarter of last year. Looking at some additional details on the second quarter recurring earnings by segment, starting with our Electric Transmission segment, which earned $0.46 per share in the second quarter of 2023 compared with earnings of $0.44 per share in the second quarter of 2022. Improved results were driven by our continued investments in Eversource’s electric transmission system to maintain high reliability performance for customers. Our second quarter 2023 Electric Distribution earnings were $0.47 per share compared with $0.37 in the second quarter of last year. The improved results were primarily due to higher revenues, mainly from base distribution rate increases at NSTAR Electric, an expected favorable regulatory decision in New Hampshire that provided the recovery of previously expense costs and lower O&M as a result of lower storm restoration costs. These benefits were partially offset by higher interest expense, depreciation and property taxes. Our Natural Gas Distribution segment earned $0.03 per share in the second quarter of 2023 compared with earnings of $0.02 in the second quarter of last year. The improved second quarter results were due primarily to higher revenues from capital tracking mechanisms supporting our continued investments in Massachusetts natural gas infrastructure as well as lower non-tracked O&M expense. These benefits were partially offset by higher depreciation, interest and property tax expense. Moving on to our water distribution segment that earned $0.03 per share in the second quarter of this year, really at the same level that we earned in the second quarter of last year. Eversource parent and other companies earnings were $0.01 per share in the second quarter of 2023 compared with flat earnings in the second quarter of 2022, excluding the offshore wind impairment charge and the transaction and transition charges as I previously discussed. Improved second quarter results primarily reflect the lower effective tax rate, the residual benefit of a disposition of Eversource’s interest in a clean energy fund partially offset by higher interest expense. Now turning into Slide 10, to further expand on what Joe covered on the sale of our 50% interest in approximately 175 acres of undeveloped – uncommitted lease area to Ørsted for $625 million in an all cash deal, we have executed a letter of intent with Ørsted to use a portion of the proceeds from the lease area to provide tax equity to South Fork -- to the South Fork Project through a new tax equity ownership interest that we are finalizing the terms of this new agreement as we speak. On July 27, we received approval from the Committee on Foreign Investment in the U.S. or CFIUS that allows us to close on both the lease area as well as the tax equity investment in South Fork later this month or early September. As part of complete – completing our Offshore Wind Strategic Review, Eversource evaluated its aggregate investment in the contracted projects, the uncommitted lease area and other related capitalized costs and determine that the carrying value of the offshore wind investment exceeded its carrying value. The current estimate of fair value has been based on the sale price of the uncommitted lease area, the expected sale price of Eversource’s 50% interest in the three contracted projects based on the most recent deal pricing, investment tax credit qualifications for potential adders, and the expectation of a successful repricing of the Sunrise Wind OREC contract. As a result, Eversource recognized an after-tax impairment charge of $331 million or $0.95 per share in the second quarter of this year. This charge will have no – will not have any impact on our cash flows from operations. We have made good progress on advancing the sale of our existing 50% interest in the three contracted offshore wind projects. As Joe mentioned, the due diligence phase is now substantially complete and behind us, and we are advancing the transaction documentation. This process is complex with multiple agreements that must be completed at the same time, such as a replacement joint venture agreement. We recognize this process has taken a bit longer than expected, but we are now – but we are not going to rush through this documentation phase. It’s important for us to have all agreements in a good place. With that said, we continue to remain focused on completing the final phase of this process, and once again, as Joe mentioned, we expect to announce the transaction soon. As a reminder, our total offshore wind investment after accounting for the impairment charge is approximately $2.1 billion as of June 30 of this year. Now turning to Slide 11. We are maintaining our full year guidance of $4.25 to $4.43 per share with a somewhat different quarterly earnings profile from 2022 due to a rate change, as I previously discussed in our first quarter call. As a reminder, the rate change – the rate design change at NSTAR Electric became effective at the beginning of this year, which eliminated higher summertime demand charges. This change shifts $0.08 per share of after tax revenues out of the third quarter and into the first and fourth quarter and roughly equal $0.04 per share split. There is no impact on the rate design change on the second quarter or the full year results. In addition to reaffirming our long-term EPS growth rate solidly in the upper half of the 5% to 7% range, we also reaffirm our $21.5 billion five-year regulated capital program that we shared during our February earnings call. Capital expenditures total – has totaled about $1.98 billion in the first half of 2023. Moving to Slide 12. Here, we highlight several factors that we expect will contribute to an improvement in cash flows in 2023 as compared to 2022. We expect an improvement over last year’s in the ratio of funds from operation relative to total debt levels. Items we are highlighting on this slide include absence of 2022 one-time cash outflow items, net proceeds from the sale of our offshore wind investment, both the projects and the lease area that will be used to lower debt balances, monetization of South Fork Wind investment tax credits, higher storm cost recoveries and distribution rate increases, and the remaining equity issuance that we have discussed. As you are all aware, over the past several years we have experienced several significant storm events having an adverse impact on our cash flows with a sizable deferred storm balance in Connecticut alone at approximately $900 million at the end of June. Our dedicated employees and the external contractor resources we depend upon to restore service to our customers safely and efficiently, which comprise the vast majority of the level of deferred costs, do an incredible job working around the clock in these severe weather events, but that does come at a cost. In terms of the year-to-date financing activity, please turn to Slide 13. As you can see here, in early May, we issued $1.8 billion of parent debt in three tranches at coupon rates ranging from 4.75% to 5.45%, and we retired $450 million of parent company debt. Our expectation is that debt issuances will be much, much lower in the second half of 2023. We have issued no additional equity under our ATM program through July of this year. We remain committed to completing the remaining $1 billion in our ATM program. In addition, we anticipate raising additional equity through our dividend reinvestment and employee incentive programs using treasury shares, and through July, we have issued 647,000 shares. Thank you very much for joining us this morning. And I look forward to seeing many of you soon. I will now turn the call over to Bob for Q&A.

Operator:

Thank you. [Operator Instructions] Our first question comes from the line of Shah Pourreza with Guggenheim Partners. Shah, please go ahead. Your line is now open.

Joe Nolan:

Good morning, Shah.

Joe Nolan:

Yes, we can hear you.

Joe Nolan:

Yes. Well, thank you, Shah. And I want to thank everybody for their patience around this complex offshore wind seal. And it’s been very, very complex. It involves multiple agreements that all have to be aligned and we want to be sure that we get the most money for our shareholders out of that exit and we remain focused on completing this transaction. To the point, we’re not going to let John Moreira take any summer vacation until he has it all taken care of. But back on point here, this region is so dependent on natural gas for electric generation. And that shift has to come, it’s has to come in some form of an alternative generation, and that’s where wind given the energy factors in this region, we can – you got a wind availability factor out there of 40% – 49% to 50%, in the winter months it’s even greater when we peak. So we feel very strongly that wind is going to play a major role as we transition to this clean energy environment. It performs especially well for us and for our customers. So I don’t see anyone taking their foot off the gas. The policy makers are very, very excited about wind. So I don’t see that winning and I really feel the appetite for wind assets, although there’s been a few that have decided not to go forward. There are – as you know, we’re out there very actively building. I was excited to get a lot of reports out of the foundations being installed for the new substation. And we are – we will be the first offshore wind company in service in the fall, which is very, very exciting to me. So there are many parties that remain committed to offshore wind. Our offshore wind leases are very, very prized assets. They sit in an area that has all the fundamentals necessary to deliver great wind speeds for any future bias. So that’s why we feel good that it will continue to do well here. So all in all, it’s going to take place. It didn’t take place obviously at the pace that all of us would’ve liked it to take place. But I just want to promise you that we are here at the one yard line and we are getting it over the goal. I think some of the announcements that we made today should give you greater clarity as to how much we really know about this transaction and that this really is the final stage. We are really focused on redeploying the proceeds for a debt pay down, and we’re reaffirming our 1B equity issuance that we provided to you on the year end 2022 earnings call. So, for that reason, I’m very confident that we’ll complete the deal soon. And thank you again for your patience, Shah.

Joe Nolan:

Yes, we are. We are fully confident in that.

Joe Nolan:

Yes. We are fully confident in that and there’s no change.

Joe Nolan:

John?

Shah Pourreza:

Okay. Perfect. I’ll jump back and let others ask. Thanks guys. Appreciate it.

Operator:

Our next question comes from Steve Fleishman with Wolfe Research. Steve, please go ahead. Your line is open.

Joe Nolan:

Good morning, Steve.

John Moreira:

Yes. Steve, so that is correct. We have included both of those components in our impairment analysis. And obviously in order for us to be in a position to do that there needs to be a certain level of conviction and probability. And on both of those, we feel very, very good about. I would say, on average, folks can certainly calculate it, but it is probably 400 a piece, $400 million.

John Moreira:

Yes. And I think some of those items we have already shared, and they might even be disclosed in our 10-Q. But I would size kind of the first category these one-timers that we experienced in 2022 that we will not materialize in 2023, I would say, at least $0.25 billion – so $250 million goes away. The three categories of those where we were as part of the 2021 Connecticut CL&P settlement agreement we still had half a year of refunds in 2022. That’s been – I see, so that’s behind us. So that was about 70-some-odd million, $78 million. We made early on in 2022, some capital contributions, which we don’t expect to make at least for the foreseeable future. And then we had another property tax settlement in Massachusetts, to the tune of $70 million that will not materialize this year. So that’s that first category. And I think all the other ones, when you look at rate adjustments, cost recovery of previously deferred costs. Those are starting to kick in. So in Massachusetts, as part of the rate case, we have close to $400 million rolling into rates, we had a piece of it that took effect earlier this year, and we have another chunk that will take effect January 1, 2024. So I think if you factor those items then and – clearly, the biggest immediate improvement in our cash flow is going to be the closing of these two transactions, the offshore wind transaction. So those are all the items. And obviously, as we’ve said, we still have $1 billion left under our ATM program to be executed. So all of those items gives me confident that we will certainly move in the right direction from an FFO to debt.

John Moreira:

Thank you.

Durgesh Chopra:

Hey, good morning team. Thanks for giving me time.

Durgesh Chopra:

John, just really quickly, you mentioned – you mentioned as part of the impairment charge, you assumed repricing on the Sunrise Wind? Can you just walk us through what the steps are, what the next sort of milestones are as you kind of have filed for that repricing? And then what does that mean? Is that $400 million related to that repricing, if that’s what you’ve quantified it as?

Durgesh Chopra:

Got it. Thanks. And then just switching gears. You mentioned roughly like $900 million in the deferred storm cost downs – and I know there is a filing coming up in Connecticut. Maybe can you just talk to that? And what is the path to recovery and time line of those costs?

Durgesh Chopra:

Got it. So as part of your cash flow walk, there’s nothing there like 2022 to 2023, and then in terms of just improvement from recovery of those costs. That’s more longer term dated.

Durgesh Chopra:

Thanks so much.

Operator:

The next question comes from David Arcaro with Morgan Stanley. David, please go ahead. Your line is open.

Joe Nolan:

Good morning.

David Arcaro:

I was wondering are you still expecting $2.1 billion to $2.4 billion in CapEx in that 2024 to 2026 period that I think you disclosed previously and our returns still at that same level in the 11% to 13% ROE range?

David Arcaro:

Yes. Yes. Sorry. Offshore wind 2024 to 2026 CapEx plans. Any changes to the longer-term CapEx?

David Arcaro:

Okay. Got it. Thanks. And then the impairment on the offshore wind assets was slightly larger than the last estimate. I was just wondering if you could elaborate on what might have changed since the last estimate when you announced the recent transaction?

David Arcaro:

Okay. Got it. So a couple of moving pieces there, and it sounds like so the original estimate of the write-off that didn’t include a re-pricing of Sunrise or the potential value of the tax credit adders.

David Arcaro:

Okay. Got it. Understood. Thanks very much.

Operator:

The next question comes from Andrew Weisel with Scotiabank. Andrew, please go ahead. Your line is open.

Joe Nolan:

Good morning, Andrew.

Joe Nolan:

Our position is that our 2021 settlement agreement provides the ability or qualifies for that four-year rate review, and that four-year rate review will expire in the fall of 2025.

Joe Nolan:

Yes.

Joe Nolan:

Yes. We can hear you.

Joe Nolan:

Yes.

Joe Nolan:

No, we will not wait for the determination from the State of New York on that. We will announce once the – these documents as we’ve mentioned are ready to go.

Joe Nolan:

No worries. Thank you.

Gregg Orrill:

Yes. Thank you. Regarding the…

Gregg Orrill:

Hey, regarding the billion dollars related to the ATM equity, what’s the intent there for how long that would last you to fund the plan? And then is there any update on the Aquarion rate case appeal? Thanks.

Gregg Orrill:

Thanks.

Rich Sunderland:

Hi, good morning. This is actually Rich Sunderland on for Jeremy. Can you hear me?

John Moreira:

Yes, Rich. Good morning.

John Moreira:

Pre-tax.

John Moreira:

The parent tax item, I would tell you that it’s probably close to about 100 basis points different quarter-over-quarter in the effective tax rate. So last year’s effective tax rate was like 24 and change, and we’re running around 22 and change.

John Moreira:

It was baked into the guidance. We were banking on that. We were tracking the proceeding very, very closely with last year, and we felt very good and comfortable about baking that in. I would say – if I remember correctly, in the $15 million to $20 million range.

Joe Nolan:

Yes. Well, no, that was a draft as you know on July 21, it’s not the final decision. Obviously, it’s – it appears to track the Aquarion decision discouraging investment in the State of Connecticut. We’re obviously concerned about that decision and we’re hoping that between now and the final decision that there are some changes in that. As you know, we will have our day in court, and if this remains as is, I assume that, UI will be in court as well to talk about that. 2025 is a long way away in terms of what we expect will happen in 2025. So I don’t want to speculate on that. We will continue to monitor that, continue to engage with key policy make us in the state. We have very good relations with the Governor, with the attorney general, with other parties. Their agenda – our agenda is very much aligned around clean energy and clean energy investments. There are a number, I mean one of the things that’s interesting with the State of Connecticut is the number of clean energy technology companies in that state. I mean, there are fuel cell companies, battery companies, all of them are looking to deploy their technologies. So any type of a chill on investment in that state is not good for all of these startup companies. And it’s obviously disappointing, but listen, we’re not going to get this hot, we’re not going to lose faith. We’re going to continue to work that those relationships down there and try to get to a place that’s fair for our customers and for our shareholders. That gets us to a much better cleaner environment with investments in that state. So again, it’s a very fluid situation. We’ll have to see what the final decision looks like, but I just want everybody to know that I am personally involved working this along with the 9,500 other employees of this company, and we are going to work through these issues and I’m confident that we can get to a much better place.

Joe Nolan:

Thank you.

Joe Nolan:

Good morning, Anthony.

Joe Nolan:

Yes. I hear you and I’m not – we have not disclosed that and truth we told that I want to have those discussions with the agencies before I share any of that detail with the broader audience. So we are now – given where we are with the contracted project transaction. Now we’re at a point where I can share some of that information, some of the details with the rating agency. So – and I have a meeting scheduled over the next several weeks to be able to do that.

Joe Nolan:

Those are the – what we plan to disseminate once we execute the agreement. But as I’ve said, there will be some potential movements up or down.

Joe Nolan:

Correct. Correct.

Joe Nolan:

Thank you.

Julien Dumoulin-Smith:

Hey, good afternoon team or good morning rather, I should say. Thank you guys very much for the time. Just following up on a few house cleaning items here from the prior questions, just clearly what – when in your forecast do you assume Connecticut Electric and natural gas rate cases, obviously you’re holding to the upper end, just wanted to clarify when you think you’ll pursue those.

Julien Dumoulin-Smith:

Got it. And no changes to your CapEx forecast for now, right in Connecticut?

Julien Dumoulin-Smith:

Got it. Excellent. And then just clarifying earlier FFO to debt, I know lots of questions, pluses and minuses, but can you just quantify the big building blocks as you think about through the forecast period, especially through 2025 here? I mean, I think I heard ITC earlier, can you just clarify, I know that you got some legacy items that we talked about earlier, and thank you again, John. But on 2022, but can you talk about the big puts and takes here that improve the metrics prospectively through the forecast period?

Julien Dumoulin-Smith:

Yes. I’m thinking about not just like 2023 to 2024, but really kind of getting that sustainable structural level, right, as you think about the big building blocks.

Julien Dumoulin-Smith:

Yes. And just to clarify your 2024 metrics here, do they benefit an FFO? Oh, go for it.

Julien Dumoulin-Smith:

Right. And 2024 includes the tax equity in your FFO?

Julien Dumoulin-Smith:

Got it. Okay. Excellent. Thank you. Really appreciate all the details here. Appreciate the cleanup, best of luck guys. Cheers.

Joe Nolan:

Thank you.

Robert Becker:

Thanks, Emily. That concludes our call. Thank you for joining us today. If you have any follow-up questions, please reach out to Investor Relations.

Jeff Kotkin:

Thank you, Jason. Good morning, and thank you for joining us. I’m Jeff Kotkin, Eversource Energy’s Vice President for Investor Relations. During this call, we'll be referencing slides that we Ørsted yesterday on our website. And as you can see on Slide 1, some of the statements made during this investor call maybe forward-looking, as defined within the meaning of the Safe Harbor provisions of the US Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on management's current expectations, and are subject to risks and uncertainties, which may cause the actual results to differ materially from forecasts and projections. These forecasts are set forth in the news release issued yesterday afternoon. Additional information about the various factors that may cause actual results to differ can be found in our Annual Report on Form 10-K for the year ended December 31, 2022. Additionally, our explanation and how and why we use certain non-GAAP measures and how those measures reconcile to GAAP results, is contained within our news release and the slides we Ørsted last night, and in our most recent 10-K. Speaking today will be Joe Nolan, our Chairman, President and Chief Executive Officer, and John Moreira, our Executive Vice President and CFO. Also joining us today are Jay Buth, our VP and Controller, and Bob Becker, our Director of Investor Relations Now, I will turn to Slide 3, and turn over the call to Joe.

John Moreira :

Thank you, Joe, and good morning, everyone. This morning, I will review our results for the first quarter of 2023, discuss our recent Aquarion rate decision, and review our most recent financing activity. I will start with Slide 6. Our GAAP earnings were $1.41 per share in the first quarter of 2023, compared with GAAP earnings of $1.28 in the first quarter of 2022. First quarter results for 2022 include $0.02 per share impact, primarily related to the integration and transition of the acquisition of the assets of Columbia of Massachusetts, now known as Eversource Gas Company of Massachusetts. So, the $1.41 per share in the first quarter of 2023 is best compared with $1.30 per share, excluding those costs in the first quarter of last year. Looking at some additional details on the first quarter earnings by segment. Our first quarter 2023 electric distribution earnings were $0.47 per share, compared with $0.41 in the first quarter of 2022. Improved results were driven largely by higher revenues at NSTAR Electric. This resulted from two factors, both related to the conclusion of our rate review from last year. The first was a base rate increase that was effective January 1st of this year, which provided about $0.03 per share benefit in the first quarter. The second was a rate design change that also took effect January 1st of this year. This design change eliminated the higher summertime demand charge. This change will have the effect of moving about $0.08 per share of after-tax revenues out of expected third quarter results, and into the first quarter and the fourth quarters of this year, in roughly equal $0.04 per share split. This annual rate design change is illustrated on Slide 7. Continuing with the quarterly results on Slide 6, the first quarter 2023 benefits from those changes and the additional distribution revenues at Connecticut Light & Power, were partially offset by higher interest costs and higher depreciation, as well as pension expense. Our electric transmission segment earned $0.45 per share in the first quarter of 2023, as compared with earnings of $0.43 in the first quarter of 2022. Improved results were driven by higher level of investment in our transmission facilities. Our natural gas distribution segment earnings were $0.49 per share in the first quarter of 2023, as compared with earnings of $0.47 in the first quarter of 2022. Improved results were due primarily to higher base distribution revenues that took effect November 1, 2022, at NSTAR Gas, as well as Eversource Gas Company of Massachusetts. This was partially offset by higher depreciation, interest, and property tax expense related to increased investment in our natural gas delivery systems to better serve our customers. Our first quarter water distribution segment earnings were $0.01 per share lower this year as compared to the first quarter of 2022, and this is due primarily to higher operations and maintenance costs. Eversource parent and other companies after-tax losses decreased $12.5 million in the first quarter of 2023, as compared with the first quarter of 2022. And this is due primarily to benefit from our equity investment in a renewable energy fund, partially offset by a contribution to our charitable foundation. This resulted in a $0.03 per share benefit for the quarter. Additionally, after-tax transaction and transition costs decreased by $4.8 million in the first quarter of 2023, as compared to the same period in 2022. Those benefits were partially offset by higher parent company interest expense for a net year-over-year improvement in the parent and another of about $0.02 per share. Overall, as you can see on our income statement, we have managed our O&M quite well in the quarter, despite the storm events we experienced in March, and slightly higher tension costs. Now turning to Slide 8, we are maintaining our full-year guidance of $4.25 to $4.43 per share, with a somewhat different quarterly earnings profile as compared to 2022. Once again, we expect that NSTAR rate design change to add about $0.04 per share to the fourth quarter earnings as it did in the first quarter of this year, but will lower the third quarter earnings by about $0.08 per share. Overall, the rate design changes will have no impact on the full-year results. In addition to reaffirming our long-term EPS growth rate of solidly in the upper half of the 5% to 7% range, we also reaffirm our $21.5 billion five-year regulated capital program that we discussed during our fourth quarter in February earnings call. Our core business capital expenditures totaled approximately $790 million in the first quarter of 2023. As Joe noted earlier, we have changed the timing of some of our offshore wind construction costs. Previously, we had projected $1.9 billion to $2.1 billion of 2023 construction costs related to our share of our joint venture with Ørsted. Now, due to an expectation that the joint venture will be able to move approximately $1 billion of payments from late 2023 to future periods, we are now expecting $1.4 billion to $1.6 billion of offshore wind related expenditures in 2023, effectively lowering our capital projection by $500 million in 2023, and raising it by $500 million over the following years. Overall, we have made no change to the estimated costs of completing our three projects or their timetable, and continue to expect South Fork to be in service later this year and for Rev Wind and Sunrise Wind to enter service in 2025. In the first quarter 2023, our share of capital expenditures totaled about $200 million, putting our total offshore wind investment through March of this year at $2.16 billion. Moving to regulatory update. For the first time in a while, we currently have no active rate reviews underway, and have long-term rate plans in effect for many of our utilities. In March, we received a very disappointing decision in the Aquarion Connecticut's first rate review in about 10 years. The rate decision, which ordered a $2 million reduction to Aquarion rates, was not unanimous. Two of the three commissioners commented that the 8.7% authorized return on equity, provided a very negative signal for utility investment in Connecticut. Due to concerns with the legality of the decision, and the negative long-term impact on customers, we have appealed the decision to the Connecticut Superior Court, where a temporary stay is currently maintaining existing rates and preventing the rate reduction order by PURA. The next hearing on the stay is scheduled for May 15. We look forward to working through the appeal process and believe we will come to a reasonable outcome that complies with the law, is good for customers, and provides us with the opportunity to recover our cost of service, including a fair return on our investments. Turning to financing activities. Since our previous earnings call, we have issued $750 million of parent company debt, and retired $450 million of parent debt just this week. As you can see from Slide 9, we have issued no additional shares through our ATM program, but through April, we distributed approximately 400,000 of treasury shares to meet our dividend reinvestment and employee incentive programs. Finally, as some of you may know, Jeff Kotkin will be retiring from Eversource later this summer. I want to acknowledge Jeff for his many years of outstanding service to our company, the financial community, and our shareholders. I have had the pleasure of working with Jeff for more than 12 years, and I am sure you will agree, he always goes the extra mile. Since the first day Jeff joined the communications department at the former Northeast Utilities nearly 38 years ago, he has been an integral part of Eversource's journey, contributing to the company's growth, evolution, and success amidst various challenging challenges over the years. Throughout it all, Jeff has delivered exceptional service to investors, been very supportive of his colleagues, while providing steady guidance to senior management and our board. It's no wonder why Jeff has been widely recognized as the best IR professional in our industry for many, many years. We are all truly thankful for his devoted service, and we wish him all the best as he spends more time with his grown family, whether it be on the Connecticut shoreline, or in the beaches of Hawaii. Thank you, Jeff, and you will certainly greatly be missed. Thank you.

John Moreira :

So, with that said, I want to thank everyone for joining us this morning, and looking forward to seeing many of you very, very soon. And now, I'll turn the call over to Bob for Q&A.

Operator:

[Operator Instructions]

Shahriar Pourreza:

Good morning, Joe. So, Joe, I wanted to maybe start with a little bit more color if you could provide on the sale process and maybe just additional thoughts beyond sort of the prepared remarks. I mean, are we still looking at three buyers that you can offload all the projects? And then just maybe how you're feeling about pricing. And Joe, the reason why I ask the pricing question is, some investors are pitching that you'll sell the projects at substantial discount to book value. So, maybe just give us any color on how you've seen valuations evolve, even if it's generally.

Shahriar Pourreza:

Okay, perfect. And then lastly, Joe, there's obviously been a good deal of attention in the investment community on the backdrop in Connecticut and the prospects really for lawmakers to tighten sort of the regulatory guardrails around things like settlements with SB-7. I guess, how do you see that process evolving as the session enters its final innings to you and other utilities? Do you even have a seat at the table in those conversations? Just some aspects of the State have become somewhat very adversarial, so I'd love to maybe get some thoughts there. Thanks.

Shahriar Pourreza:

Got it. Perfect. And then Jeff, congrats on phase two. You're going to be really missed, and drinks - unlimited drinks on Mr. Nolan and I. Thanks. Appreciate it, guys.

Shahriar Pourreza:

There you go. Congrats, guys.

Operator:

I think they dropped their question.

Paul Patterson:

Hello. Hi.

Bob Becker:

Hi, Paul.

John Moreira:

Hey, Paul, it’s John. So, first of all, I think the order that came out was really more of a framework. The details are still out. We'll be picking this up in April of next year to finalize and work on the specifics. So, I think it's too early to make the determination. Clearly, the UK model is a significant difference from how we've been operating through the traditional cost of service. And then - and if we were to change to something that drastic, it would have significant ramifications financially and otherwise to the utilities in the country. So, I think it's too early for us to indicate one way or the other as to where things ultimately will shake out.

Joe Nolan:

I mean, our expectation is that the stay would be a permanent state from where it currently stands today. We feel very - based on our assessment, we feel very comfortable with opposition and the commentary that we've made in our filing and we will make in our filing on Monday. Our briefs are due on Monday. So, more to come on that front. But hopefully, that permanent - it'll move from a temporary to a permanent stay and until we see the appeal process work its way through.

Joe Nolan:

No, it's not. It’s not a strong possibility. We see a path for a clean exit from this. So, that's not - that is definitely not the case.

Bob Becker:

Thanks, Paul. Our next question comes from the line of Steve Fleishman of Wolfe Research. Good morning, Steve.

Joe Nolan:

Yes. So, thanks, Steve. A couple of things. Yes, there's - we're talking about two announcements, two buyers in the second quarter, and there might be a space of - a short period of time between announcements, but both in the second quarter, yes.

John Moreira:

Steve, this is John. Yes, we're going through the negotiations right now. So, it's a little premature for us to indicate ultimately where that will shake out.

Joe Nolan:

Yes, I mean, obviously, I think you know our track record around settlement, and if there's an opportunity there, we certainly will work with any parties around settlement. The Aquarion asset, we've managed very, very well. We have very low rates. We've been making significant investments as you know that I think it's one of the best-run water companies. So, we do see an opportunity. We think we have allies in the State down there to kind of work through that. But as you know, it takes two to tangle in the settlement space, and we need to have some willing participants. So, we'll always work towards settlement. We think settlement is the way to go and we're optimistic that we can probably have some type of an outcome that would benefit both parties.

Bob Becker:

Thanks, Steve. Our next question comes from Jeremy Tonet at JPMorgan. Good morning, Jeremy.

Joe Nolan:

Well, I mean, I think that was one of the points that had us make the pivot because we think there's so much opportunity in both the land aspect of it and the investment around, not only the projects that we were involved in, but the projects that everybody else is involved with. We are very well positioned in this region at load centers, and people want to get to those. So, because they want to get to them, they're going to go and spend time with us. So, we see a tremendous opportunity for investment in offshore wind as it relates to our regulated business. And that's really what our focus. Our focus has been around de-risking and focusing on the regulated assets. So, we do see, Rich, a great opportunity, not only with Ørsted, but with these other wind partners. It's already playing out right now with other wind partners that we don't have any ownership on to build wind and transmission-related assets, to help them inject clean energy into the new England and New York grid.

Joe Nolan:

Yes, I mean, just a great question. And we've been talking about that. As you know it was front and center for me in the company last late summer fall. And it's still on my radar, and I'm concerned about it. I'm concerned about say fuel supply for generators. We're very interested in - you saw what happened in PJM where folks didn't show up. We had a similar situation on a smaller scale take place in the ISO New England market where folks didn't show up when they were expected to show up. I think it was a shocker, the number - the penalties they were talking about in PJM. I mean, up here, they were pretty significant. So, we are focused every day on what we can do to help minimize the risk to our customers, because although we could line up significant supply for our customers, at the end of the day, if people don't perform and the lights go out, they're going to come knocking on our door. And we are - obviously, it's not our fault, but you get blamed because the lights go out. So, we are focused every day in our energy supply area, in our transmission area, in our engineering area, as to what we can do to facilitate solutions to fully enable this grid to operate during very challenging conditions. But in doing that, what it's going to also do is, it's going to drive the price of energy down in the region, which is what our goal. We want to lower the clearing price in the region so that our customers are not getting the type of shock that they're getting, which has been devastating to them, and we know that.

Bob Becker:

Thanks, Richard. Our next question comes from Paul Zimbardo at BofA. Good morning, Paul.

Jeff Kotkin:

Thank you, Paul.

Joe Nolan:

Yes, Paul, we did.

John Moreira:

No, at this point we do not. We continue to assess the timing of that rate request.

Bob Becker:

Thanks, Paul. Our next question comes from Ryan Levine at Citi. Good morning, Ryan.

John Moreira:

Sure, Ryan. So, it’s different for the two pieces, right? So, it's different for the uncommitted lease area, as it is for the contracted projects. Speaking of the contracted project, that's probably one that has a bit longer timeframe for regulatory approval. On that one there, because we just - our subsidiary or the joint venture that holds those projects, are considered a public utility company, so we would now need to obtain FERC approval, and that's probably a three-month process. Other than that, it's more - it's the traditional Hart-Scott-Rodino. And depending on who the ultimate buyer is, we could require CPH’s approval. But once again, I think that's very - that's weeks, not months.

Ryan Levine:

Appreciate the color. So, given that timeline, curious how you're thinking about your financing plan. I know you issued some parent debt at 545 basis points year-to-date. Are you considering the convert market given that seems to be open to a lot of utilities in this environment?

Ryan Levine:

Okay. I mean, you mentioned in your side deck a May 1 maturity. Was there any update on what happened there?

Ryan Levine:

Okay. I appreciate the color. Thank you.

Travis Miller:

Again, a public congratulations to Jeff. If you ever mistakenly find yourself in Chicago, let me know. I owe you drinks, et cetera, for all the help over the years, but try to avoid the winter times here. Offshore wind again, thinking about the - you mentioned the payment shift there, the $500 million. Thinking about the timing in terms of the close of any deal, does that payment shift save you the $500 million of cash that you had previously planned to finance, or allow you more capacity to invest in other places this year? I'm just thinking through the timing of that, how that affects the plan.

Travis Miller:

Okay. And then I know this isn't your project, but there's another transmission line proposal out up your way from Canada. Any thoughts on differences between, say Northern Pass or any of the other proposals that have been made over the decades that you know of?

Travis Miller:

Sure. Okay, very good. That's all I had. Thanks so much.

Operator:

That concludes the conference call. Thank you for your participation. You may now disconnect your lines.

Jeff Kotkin:

Thank you, Nadia, and we apologize for the delay in starting the call. We were having a problem with our webcast link, and it had to be reset. We couldn't just start the call, with only the dial-ins working. So we appreciate your patience greatly, and we look forward to your questions after the intro remarks. So, let me start. Good morning. Thank you for joining us. During this call, we'll be referencing slides that we posted yesterday on our website. And as you can see on slide 1, some of the statements made during this investor call maybe forward-looking, as defined within the meaning of the Safe Harbor provisions of the US Private Securities Litigation Reform Act of 1995. These forward-looking statement's are based on management's current expectations and are subject to risks and uncertainty, which may cause the actual results to differ materially from forecasts and projections. These forecasts are set forth in the news release issued yesterday afternoon. Additional information about the various factors that may cause actual results to differ can be found in our Annual Report on Form 10-K for the year ended December 31, 2021 and our Form 10-Q for the three months ended September 30, 2022 – I'm sorry, the 10-K was for 2021. Additionally, our explanation and how and why we use certain non-GAAP measures and how those measures reconcile to GAAP results is contained within our news release and the slides, we posted last night, and in our most recent 10-K and 10-Q. Speaking today will be Joe Nolan, our Chairman, President and Chief Executive Officer; and John Moreira, our Executive Vice President and CFO. Also joining us today is Jay Buth, our Vice President and Controller. Now, I will turn to slide 4, and turn over the call to Joe.

John Moreira:

Thank you, Joe, and good morning, everyone. This morning I will be covering our 2022 results, our 2023 earnings guidance, our updated five-year regulated investment capital plan and long-term outlook and give you an update on some current regulatory proceedings. Let me start with our 2022 results on slide 14. Our GAAP earnings for 2022 were $4.05 per share, compared with $3.54 per share in 2021. In the fourth quarter of 2022, GAAP earnings were $0.92 per share, compared with GAAP earnings of $0.89 per share in the fourth quarter of 2021. Results for both 2022 and 2021 include transition and transaction-related costs, primarily associated with integration of Eversource Gas Company of Massachusetts. Also, full year 2021 GAAP results included charges related to the CL&P settlement agreement. Excluding those nonrecurring charges, we earned $4.09 per share in 2022, up 6% from $3.86 that we earned in 2021. For the fourth quarter, excluding these charges, we earned $0.92 per share in 2022, compared with earnings of $0.91 per share in 2021. To break down our earnings by segments, electric transmission earned $1.72 per share for the full year 2022, compared with earnings of $1.58 per share in 2021. Higher earnings resulted from continued investment in our transmission system. We invested just over $1.2 billion in our transmission facility in 2021, compared with $1.1 billion in 2021. Current -- mostly replace an agent, equipment and improving reliability and resiliency for the region. Our electric distribution segment earned $1.71 per share in 2022, compared with $1.61 per share in 2021, excluding the Connecticut settlement-related charges. Higher revenues and lower pension expense were partially offset by higher O&M, depreciation, property taxes and interest costs. Fourth quarter 2022 results also reflect a $10 million contribution we are making to help some of our customers pay the significantly higher energy bills we have seen this winter. Our higher distribution expense primarily stemmed from our ongoing investments in the distribution system to improve service and reliability for our customers. We invested about $1.35 billion in our electric distribution system in 2022, up from $1.24 billion in 2021. The higher O&M was driven in part, by higher storm costs in 2022. Non-deferred storm expense cost us about $0.05 per share, more in 2022 than it did in 2021. Our natural gas distribution segment earned $0.67 per share in 2022, compared with earnings of $0.59 per share in 2021. Higher revenues and lower pension expense were partially offset by higher O&M, property taxes, interest and depreciation expense, much of it driven by our continued investment to improve the safety, reliability and resiliency of our natural gas distribution system. Our Water Distribution System segment earned $0.11 per share, in both 2022 and 2021. Excluding the transition and transaction-related charges, Eversource parent and other companies lost $0.12 per share in 2022, compared with a loss of $0.03 per share in 2021. This change was due largely to higher interest expense, particularly in the second quarter of 2022 and higher -- and our higher effective income tax rate. Overall, as Joe covered in his remarks, we are very pleased with our 2022 performance, as we successfully overcame many challenges and delivered very positive result, for our customers and all of our stakeholders. From 2022 results, I will turn to 2023 guidance, on Slide 15. We are projecting non-GAAP earnings of between $4.25 and $4.43 per share, this year compared with $4.09 per share, we earned in 2022. The slide shows, the factors that we expect to positively and negatively impact earnings in 2023 compared with 2022. One item benefiting earnings is our ongoing program to upgrade our electric transmission system where we expect to invest approximately, $1.2 billion again, in 2023. I will discuss the principal drivers behind that investment, and how it will benefit our customers in a moment, when I discuss our long-term capital plan. We are also -- we also project higher revenues in our distribution companies, as we continue to upgrade and expand our distribution systems. Those higher revenues are due primarily to rate adjustments at NSTAR, Gas, EGMA and PSNH that were that went effective on November 1 2022 and at NSTAR Electric, just beginning of last month. We expect that they will be partially offset, by anticipated increases in depreciation and property taxes. We expect enhanced returns in 2023, on an investment in a fund that we have owned related to various clean energy facilities. Those facilities have significantly increased in value, in recent years, and have benefited our results for several years, and now include in 2022. Interest expense will continue to be a headwind at Eversource parent. It will also be a headwind at our distribution segments. While the portion of interest expense allocated to transmission is tracked, the distribution portion is not and will weigh on earnings. Lower pension expense was an earnings tailwind for us in 2022, primarily due to the extremely strong asset returns that we performed in 2021. In 2023, we expect pension costs to be a slight headwind to earnings of approximately 4% -- $0.04 for the year as compared to 2022. Here are some reasons why -- behind this modest impact; first, a significant portion of our pension cost or pension benefit is capitalized into our capital projects; secondly, pension expense or pension cost related to our transmission segment and to our Massachusetts Electric and natural gas distribution segments are fully tracked; third, a higher discount rate reduces the impact of the amortization of prior year accumulated actuarial losses; and lastly, the higher discount rate means that our pension plan remains fully funded and we do not anticipate making any contributions in 2023. From 2023 earnings expectation, I'm going to turn to slide 16 and cover our five-year plan to invest approximately $21.5 billion in our regulated electric natural gas and water distribution businesses to continue to provide customers with safe and reliable service to address ongoing load growth in certain areas of our service territory and to help our states meet their decarbonization goals. The increased investment is focused primarily within our electric, transmission and distribution segments. Much of the increase in the transmission capital projection is due to increased investments in the replacement of older equipment in our substations, overhead infrastructure and underground cables. This investment continues to make our transmission system more reliable even during extreme weather events. Increased storm hardening and system resiliency has resulted in no transmission related outages through the last several severe storm events. We also are including the early years of a major new project to build an underground substation in Cambridge, Massachusetts where the load growth continues to accelerate. A site-in application for this project was filed about a year ago. We are incorporating significant additional transmission investment in the physical security of our major substation and a total of about $450 million for transmission investments in the distributed energy and offshore wind projects Joe mentioned earlier. On the electric distribution side our updated forecast now reflects the inclusion of AMI in Massachusetts and the completion of our proposed distributed energy projects also in Massachusetts. Earlier Joe mentioned that the first cluster of these distributed energy projects have been approved and that the hearings are ongoing for the remaining five. Our forecast also reflects the Massachusetts DPUs recent approval of our multi-year grid modernization and electric vehicle charging program. Moving on to the natural gas side, our increased investment is primarily related to increased regulations around natural gas companies construction activities that have evolved since The Merrimack Valley incident several years ago. We've also increased the number of projects to harden our system against flooding and added protection on our low-pressure systems. In the Water segment, our updated five-year capital investment forecast of approximately $1 billion is more than 10% above the previous forecast, primarily reflecting the addition of Torrington Water, the acquisition that we completed last year and the additional Water Treatment Facility investments. It also includes about $70 million of per year to replace nearly 25 miles annually of Old Water Mains. Aquarion has more than doubled the scope of its Water Main Investment program since being acquired by Eversource. Moving on to slide 17 which compares year-by-year investment levels in the years 2023 through 2026, they totaled approximately $3.3 billion. This is consistent with the discussions we've been having with investors since last May, when we indicated that the increased investment requirements in our regulated infrastructure would likely offset 2026 earnings impact of divesting our offshore wind investments, if that is ultimately the outcome of our strategic review. Slide 18, shows that some major potential initiatives remain outside of our investment plan. Connecticut regulators continue to review our proposed AMI program. So that investment of approximately $475 million remains outside of our plan, as are some potential related storage projects also in Connecticut. Our transmission system on Cape Cod could interconnect another 1200 megawatts of offshore wind, in addition to Vineyard Wind and Park City Wind. As such, interconnections are now under technical review, by the ISO New England, but we have not reflected any potential amount in our plan. In addition, we've not reflected potential transmission projects that likely, will be needed to move significant sources of offshore wind generation to load centers. We've also now reflected potential clean energy alternatives, we are beginning to explore as alternatives to natural gas. As you can see on slide 19, the customer-focused core business investments that are included in our capital forecast would result in a 7.5% rate base CAGR through 2027. Supported by those investments we have maintained our EPS rate of -- growth rate of 5% to 7% and believe, we will be solidly in the upper half through the forecast period as illustrated on slide 21. In addition, to our earnings growth, we are enhancing our internally generated cash. Last year cash flows from operations totaled just over $2.4 billion and that is compared with slightly under $2 billion in 2021. And the 2022 figure included a few cash outflows we do not expect to occur in 2023. As such as about $80 million of the pension contributions that we made in 2022 and more than $70 million of customer bill credits related to the CL&P 2021 rate settlement agreement and higher than average storm costs. We expect that the combination of enhancing credit metrics, progress on our strategic review, and equity issuance plans will allow us to maintain or, in the case of S&P, improve our current ratings. Those strong ratings provide significant benefits to customers by allowing us to borrow at some of the lowest rates in the industry. We also expect an increased level of storm cost recovery compared to 2022 as part of the NSTAR Electric rate decision. Maintaining those levels will require us to regularly infuse equity from our parent company into our regulated businesses. Slide 21 illustrates the sources of that funding. In addition to improving cash flows as I mentioned -- previously mentioned we will require additional debt issuances principally at our regulated utilities. We expect to issue nearly $1 billion of additional equity through our at-the-market program over the coming years. We will continue to use treasury shares to fund our dividend reinvestment and employee incentive programs. Should our strategic review results in a sale of our offshore wind investments, we would expect to use all of the net proceeds on day one to pay down parent debt. This will create increased financial flexibility in the future as we fund our regulated segments. Moving on to our regulatory update. In the past few years, we have had a lengthy discussion about various regulatory reviews, but this year, that discussion is much briefer. As you can see on slide 22, we continue to await FERC's ruling on several pending complaints that were filed beginning in 2011, challenging the return on equity authorized for all of New England electric transmission owners. On the distribution side, the only ongoing rate review involves Aquarion Connecticut, where a draft decision is due shortly. Due to the capital program at Aquarion, as I mentioned earlier, Aquarion's returns have slipped below its currently allowed 9.63% authorized return on equity. We believe we have made a strong case for a reasonable increase in Aquarion's water rates, which are quite low compared to its peers. Elsewhere, we don't expect significant rate review activity in 2023. In Massachusetts, all three of our electric and natural gas utilities are currently operating under long-term rate plans that extend from five to 10 years. Finally, as you can see on slide 23, we continue to remind investors that they should consider our long-term track record and attractive risk profile in determining whether to invest in our company. This slide shows that over the decade, since Eversource was created, we have consistently achieved the earnings and dividend growth we targeted, while achieving very strong operating performance. We also have enhanced our ESG profile which certainly ranks us among the best, if not, the best in the industry. Thank you again for joining us this morning and I will now turn the call over to Jeff.

Operator:

Thank you. [Operator Instructions] I'll hand back over to you Jeff.

Durgesh Chopra:

Hey, good morning. Good morning, Jeff. Thanks for giving me time this morning. Maybe Joe, can you comment on sort of the offshore strategic review right, originally, you guys were targeting year-end last year for completion of the review. It's certainly taking longer than expected. So maybe what's driving that? Any color you could share there?

Durgesh Chopra:

Understood. And then just maybe a quick follow-up. The Q2 kind of update on the review what is that due to timing of a potential close? Is that still sort of midyear, or are we thinking about second half of this year, if you do decide to go forward with the sale that is?

Durgesh Chopra :

Got it. And then just one final one if I can and then I'll jump back in the queue. So a lot of investors have asked about the CapEx raise this morning and how that translates into your long-term EPS growth rate. I mean the rate base growth CAGR is up. It's now 7.5%. And relative to your guidance of 5% to 7%, you're saying solidly in the second half. Just can you comment on that? Are you being a little conservative here?