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Operator: Hello, everyone, and welcome to the Eversource Energy Q4 and Full Year 2022 Earnings Call. My name is Nadia, and I’ll be coordinating the call today. I will now hand over to your host Jeff Kotkin, Vice President of Investor Relations for Eversource Energy to begin. Jeff, please go ahead.

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.

Joe Nolan: Thank you, Jeff, and thank you everyone for joining us on this call this morning. We had a very strong 2022 operationally, financially in advancing the clean energy policies of the states we serve. As we look ahead to 2023, we consider ourselves to be extremely well positioned to deliver on our customers’ expectations, whether it relates to providing them with safe and reliable service, helping communities address the impacts of climate change, or standing ready, and fully prepared to respond to emergencies. The work that thousands of Eversource employees undertook, following a severe windstorm, two days before Christmas last year, working in bitter temperatures up to 16 hours a day, before and during the holiday, to ensure our customers had power, exemplifies the selflessness of our 9,600 colleagues.

We treasure the hundreds of appreciative comments we’ve received from our customers. On our ESG efforts, we published a new diversity, equity and inclusion report, and we are recognized as a leader in this area among the 1,000 largest US corporations by as you saw a nation-leading shareholder advocacy, non-profit focused on environmental and social corporate responsibility, and values aligned investing. We are now completing a new initiative on equity training across the entire company. In November, we announced that we had committed to setting a science-based target making us one of only a few US electric or gas utilities to take that challenging step. We continue to receive very positive feedback from many of our investors on that commitment and believe it will become an increasingly differentiating factor for Eversource in both the US and non-US investment portfolios.

Slide 5 illustrates some of our very — our key operational metrics starting with two key gauges of electric service reliability. Our customers’ average number of months between interruptions remained in the highest decile of the industry in our speed of restoration when outages did occur was in the top quartile. Our key safety metrics also remain strong. In terms of our 2022 financial performance, we continue to grow our non-GAAP earnings in dividend by approximately 6% something that we have done consistently since Eversource was formed nearly 11 years ago. As shown on slide 6, our Board approved an additional 6% increase in our quarterly dividend earlier this month. John will discuss some of the factors that we expect will move earnings per share growth over the next five years to solidly in the upper half of our long-term 5% to 7% range.

While our longer-term total shareholder return compares favorably with our peers, our 2022 return was disappointing. We understand that much of that is related to the uncertainty over our offshore wind investments. We expect to resolve that uncertainty in the coming months as our strategic review progresses. There is continued interest in both our three offshore wind projects in the nearly 175,000 acres of uncommitted lease areas that are part of our 50-50 joint venture with Ørsted. The process continues to move forward and is progressing through extensive due diligence. We expect an announcement concerning the outcome of the strategic review in the second quarter of this year. In the meantime, our work on the three projects is moving ahead.

Slide 7 provides a quick overview of the significant progress in recent months. As you know construction of our first project South Fork Wind commenced a year ago. Installation of the onshore conduit system including cable vaults and town roads and along the Long Island railroad is now complete as is the installation of the sea to shore conduit that will hold the transmission cable as it transitions to land. Installation of onshore cable is now underway and construction of our new onshore substation is on track to be completed this summer. Installation of the South Fork subsea transmission cable will begin later this quarter and installation of the foundations, wind turbines and offshore substation will begin this summer off the coast of Massachusetts.

We expect that South Fork will be fully operational by the end of the year. Our two larger offshore wind projects Revolution Wind and Sunrise Wind, continue to advance through citing and permitting, and we expect to commence construction of both projects in the second half of this year. The Bureau of Ocean Energy Management, or BOEM, issued a draft environmental impact statement for the 704-megawatt Revolution Wind project in September. We expect a final EIS in the second quarter of 2023 and to have all permits in hand in the second half of 2023. We continue to target a 2025 in-service date. We had two major developments late last year for Sunrise Wind, our largest offshore wind project. The project received a key New York Public Service Commission permit and BOEM published a draft EIS for the project.

As of the end of 2022, we had invested $1.95 billion in offshore wind. We made significant progress late last year procuring equipment and services and have approximately 90% of costs locked in, up from 82% as of September 30. On one of the slides in our appendix, you can see our updated total cost estimates for the three projects. The range is somewhat higher and narrower than it was a year ago. This is due to the fact that we have locked in much higher percentage of the cost, and that’s some of the nonwalking costs, especially those related to foundation, transportation and installation are higher than we had estimated earlier. I should reemphasize, that we consider offshore wind to be cost-effective source of significant clean energy supplies for the Northeast.

We expect our electric utilities to build much of the FERC-regulated onshore transmission infrastructure, needed to connect the offshore generation to load, regardless of the outcome of our strategic review. Those investments will be closely aligned with our commitment to be a leading catalyst for clean energy development in our region. It is one of the many ways we are helping the region decarbonize, and we have seen very significant progress on a number of our Massachusetts initiatives over the past year. Turning to slide eight. On December 30, the Massachusetts Department of Public Utilities approved the first of six proposals to unlock third-party solar generation that is currently stalled in the interconnection queue, as a result of inadequate transmission and distribution capacity.

If all six proposals approved, a total of 1,000 megawatts could ultimately be built and connected. As you can see on slide nine, the first approved project is Marion-Fairhaven. Commission proceedings are active for the other five proposals, and we expect deep new decisions on them this year. Our proposed investment in these six clusters, would be approximately $980 million, of which about $310 million would be reimbursed over 15 to 20 years by solar developers, as they fully subscribe to the unlock hosting capacity. Also late last year, as shown on slide 10, the DPU approved the implementation of AMI with a new customer information system for our nearly 1.5 million electric customers in Massachusetts. The DPU also approved our proposed continued investment in grid modernization.

Today these investments will enable customers to better manage their usage and provide us with significantly improved visibility into power flows and conditions on our electric distribution system. This will be critical for us as more distributed energy resources are connected to our system, and as more of the state’s space heating and transportation is electrified. We expect the new customer information system to be installed, primarily over the next two years, with meter installation in 2025 through 2027 time period. We hope that Connecticut regulators will conclude their AMI review this year and approve its rollout to 1.3 million of the state’s electric customers. Aside from these projects, we have many other initiatives in Massachusetts.

In December, the DPU authorized a four-year plan for electric vehicle charging infrastructure that is profiled on slide 11. On slide 12, we describe three other initiatives including a 38-megawatt hour battery storage facility that went online in Provincetown on Cape Cod last year and can supply up to 11,000 customers this time of year with power, should an outage occur on our principal distribution to serving the outer Cape. The slide also provides you with the status of our highly innovative network geothermal project in Framingham, Massachusetts, which is now 90% designed with construction to start this spring. Additionally, we have three proposals into the Department of Public Utilities to expand our solar generation with an additional focus on storage and equity justice communities.

We are very excited about all of these proposals as they help Massachusetts to achieve its very aggressive clean energy agenda and keep our region at the forefront of innovative solutions to the challenges of climate change. We hope that Connecticut and New Hampshire will embrace some of these clean energy programs and our involvement in delivering solutions. In Connecticut, there are clear signals from the Lamont Administration in the Governor’s Department of Energy and Environmental Protection that they are looking to promote significant investment in clean energy initiatives with both federal and utility support. To this end, we have three-grid scale battery storage projects pending before Connecticut regulators that would improve grid reliability and enable integration of clean energy resources.

These proposed investments, which are not in our current capital forecast, were enabled by recent state legislation. We hope that workable regulatory frameworks will be advanced to support such investments. Finally, I want to address power supplies in energy bills this winter. As you know, we were quite concerned entering this winter about the impact of higher energy prices in New England as well as uncertain supplies of natural gas, LNG and oil for the region’s generation. In fact, I wrote to President Biden before the heating season commenced asking that his administration invoked certain emergency measures to ensure that we have sufficient resources this winter. Fortunately, the mild temperatures this point to have reduced customers’ energy consumption and tempered the impact on bills.

They also have contributed to a sharp reduction in natural gas prices, which has started to lower natural gas bills for some customers. New Hampshire electric customers are seeing a rate decline this month. For most of our electric customers, lower power supply costs will start to be reflected in bills in July. Thanks again for your time. I will now turn the call over to John.

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.

Jeff Kotkin: Right. Thank you, John, and thank you again for the audience for sticking with us this morning. I’m going to turn the call back to Nadia to remind you how to enter questions in the queue and then she’ll turn it back to me and we’ll get going. So Nadia?

Operator: Thank you. I’ll hand back over to you Jeff.

Jeff Kotkin: All right. Thank you, Nadia. So our first question this morning is from Durgesh from Evercore. Good morning, Durgesh.

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?

Joe Nolan: Yeah. Good morning, Durgesh and thank you so much for being on the call. Yeah. So I just will tell you that I am the eternal optimist. Obviously, I wanted to have some news for you by year-end, but this is complex project. It’s got a lot of moving parts. And as you might imagine, it’s not a straightforward transaction in terms of due diligence that has to take place here. We’re talking about thousands of acres of the ocean floor people looking at other pieces of this transaction. So it took longer and shame on me, I should have been a little more realistic on the timing. But I will tell you there is significant interest in the lease here as well as the projects and we are going to get a fair price for these assets.

But I think the one thing that you should all take away from this call is that the progress that’s taking place on these projects we have not taken our eye off the ball. We will be in the wind business. We will be the first utility in the wind business in a large scale in the US offshore wind business by the end of this year, which is pretty extraordinary. The other two projects are moving on quite well. As you know the pricing of those projects is quite favorable. So we’ll continue to drive this process and focus on this review and this exit. But unfortunately, it doesn’t go at the pace that I like to go. I’d like to move at a good place, but this is very complex and you need to — folks need to understand that that any buyer of these assets is going to want to do significant due diligence.

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?

Joe Nolan: Well, I’ll tell you that the folks that are involved in the process right now are very sophisticated buyers. So we do not anticipate it would take — it wouldn’t happen in the second quarter, but it would happen third at the latest for. I mean, this would be a very quick close, because the level of due diligence that’s taking place is significant. So it wouldn’t be like you would get into an agreement and then have that process. That’s all being done upfront. So we do — it will take place this year is our anticipation.

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?

John Moreira: Yes. Durgesh, this is John. So I think the wildcard is where we think interest rates are going to be over the near term and longer-term, right. And on that front, I can tell you that we’ve been very conservative in our assumptions in our plan. Obviously, if those are the actual results by the feds don’t materialize to what we have and that will have an impact in and move us further directionally up or down. And the guidance range that we gave for next year is pretty wide. And what will — as we did last year if you recall we will revisit that range kind of midyear and we’ll have a better view on things, but the uncertainty right now is where interest rates are going to land.

Durgesh Chopra : That’s really helpful, John. Thank you so much. Appreciate the time guys.

John Moreira: Thank you.

Jeff Kotkin : Thanks, Durgesh. Our next question is from Nick from Credit Suisse. Good morning, Nick.

Nick Campanella: Hey, good morning everyone. Thanks for taking my question here. Just real quick on the fiscal 2023 drivers. I think you said you expect an increase in equity investment valuation. Just what is that item if you could just help us understand that? And can you quantify how large that is in terms of the fiscal 2023 benefit?

John Moreira: Sure, sure. I’ll take you back. We’ve had multiple years where we’ve had pluses and minuses. I think the pluses have always outweighed the minuses. So this is an equity investment that we’ve had in renewable resources primarily landfill gas generation. We — if you recall last year in the second quarter, we recognized fair a mark-to-market on that investment of about $12 million and we are seeing very attractive valuations on that footprint. So we have baked an increase assuming that we’ll get another favorable mark-to-market. We have done this in the past where we had the conviction that we thought it was going to be favorable, but it’s — over the years, it’s been a wild card. We’ve had backed these adjustments into our plan and our guidance previously.

Nick Campanella: Okay. Thanks for that. And then I guess just on the funding plan, can you just kind of discuss — have you kind of put this in front of Moody’s, what’s their view and just confidence level and kind of moving off the negative outlook here? Thanks.

John Moreira: Sure. Sure thing, Nick. Yes. So, I mean, we continuously meet with Moody’s and all three of the credit rating agencies and we certainly did that post announcement of our win divestiture. So they fully understand and appreciate our plans. We will be meeting with them over the next two months as we go through that annual cycle. But I think if you recall when we announced the offshore wind divestiture both S&P and Moody’s did take some action on €“ obviously, a favorable action. So they are in tune and lockstep with what we are planning to do.

Nick Campanella: Okay. And one last one for me just on your regulatory strategy. I know you’ve been staying out on the distribution side in Connecticut. Just how do we kind of think about when the next rate case would be? Thanks.

John Moreira: On the electric distribution side, as you know we have a settlement agreement that precludes any rate change €“ base rate changes, no earlier than 1/1/24, okay? I think right now we’re not earning the allowed but we’re not that far from it. I think we can stay out as far as 2025, the end of 2025. So I think that’s kind of where our head is at, but that will €“ that rate case will trigger recovery of storm costs. So you could very well see some filings that we want to start the prudency review of those storm costs later this year.

Nick Campanella: Thanks for taking my questions.

Jeff Kotkin: Thanks, Nick. Next question is from James Kennedy from Guggenheim. Good morning, James.

Unidentified Analyst: Hey, good morning, guys. Thanks for the time. So I guess just on the wind sale. You previously indicated that there could be separate sales at least the projects. Is that still the case? And then also it looks like there’s a little bit of creep in the total costs. Where are you seeing the pressures? And what’s in the balance of the unlocked cost at this point?

Joe Nolan: Yes. We do feel that the €“ this would be more than to be too biased somebody for undeveloped lease areas and folks that are interested in projects. We had €“ we did see higher costs associated with the foundation transportation and the installation contracts. As you might imagine, when you move to these larger turbines, the 11 megawatts, it was obviously very, very helpful for the project but it also brought larger foundation basis which drove costs. So that was the issue.

John Moreira: And James, we have those numbers in the appendix. I’ll direct your attention to that.

Unidentified Analyst: Okay. Perfect. And then just on the incremental spend, you guys have in the slides how should we think about the shape of that and the sizing through the forecast when the €“ lumpy on the transmission side? Is it outside of 2027? Just how should we think about the SKU there?

John Moreira: I would say the majority €“ the vast majority of that will happen between now and 2026. Some of those investments can spill over into 2027. The only one that’s more longer-term is the €“ what I mentioned in my formal remarks and that’s the Cambridge substation. That’s probably a bit longer. That probably takes us out through 2028.

Unidentified Analyst: Okay. And then

John Moreira: And then I would also mention €“ I’m sorry go ahead.

Unidentified Analyst: No you go ahead. Sorry.

John Moreira: I would also mention that that incremental that $3.3 billion of incremental investments I think it’s important for everyone to understand that two-thirds of that has already been approved by regulators.

Unidentified Analyst: Yes. Okay. And John, just on the sales side, any update on efforts to mitigate the tax leakage?

John Moreira: We continue to look and explore opportunities but given how we want the transaction to be structured, it’s going to be a challenge for us.

Unidentified Analyst: Okay. Fair enough. Thanks, guys. Happy Valentine Day.

Joe Nolan: Thank you.

John Moreira: Thank you.

Jeff Kotkin: Thanks, James. Our next question is from Angie from Seaport. Good morning, Angie.

Angie Storozynski: Good morning. So I just wanted to talk about offshore wind. So we saw a write-down of Sunrise at Ørsted. I don’t see the 10-K from you guys, but I’m assuming you didn’t write down the project. And I’m just wondering is it because it was reflected at a different amount in your books versus what Ørsted had, or is it somewhat indicative of what you have embedded as your expectation for the sale of the process of the project?

John Moreira: Sure. Angie, this is John. I can assure you, you will not see an impairment in our 10-K when we file it tomorrow. But with that said, let me give you kind of the key drivers of that. Number one, different accounting. Ørsted is under international accounting standards. The joint venture is under GAAP — US GAAP, and it’s a different calculation as to how you assess an impairment, okay? So two things — two conditions that prompted that. As Joe mentioned 90% of the cost being finalized. Those costs came in a bit higher than what we anticipated and the fact where interest rates are. That’s — those are the two elements that drove Ørsted to take a look at the impairment for Sunrise. Under the International Accounting Standards, the first step in the assessment is you have to assess your future cash inflows and those have to be at a discounted rate. So that’s really the two key measures that used to look at this and take the payment charge.

Angie Storozynski: Okay. Okay. And then on — so we’re seeing a delay in your process, but also a delay in the sale processes for onshore wind or solar assets. And I’m just wondering is it — I mean is it maybe that potential buyers are waiting for some clarity from the IRS about tax credits from the IRA and if that’s the case when would you actually expect some clarity on those credits?

John Moreira: Well, I think, the clarity from the IRA was effective beginning this year, right? So they will have to issue some guidance soon and we think it is soon. But obviously it’s an area that we feel comfortable with based on where we see the procurement coming from and we have convey that to the candidates that we’re speaking to.

Angie Storozynski: Okay.

John Moreira: But until those regulations come out you don’t know what you don’t know.

Angie Storozynski: I understand. And then lastly so there are lots and lots of bills proposed in the Connecticut legislature related to utilities. And I hear you that you’re not likely to have a rate case within probably the next two years, but there’s been discussion about how regulators see settlements and in general some push for increased supervision over electric utilities. I mean is there any comments I think you can make on those points?

Joe Nolan: Yes. So this is Joe. Good morning, Angie.

Angie Storozynski: Good morning

Joe Nolan: So I think, this time of the year you’ll begin to see in all jurisdictions legislative proposals that come out that will cover the landscape of our business. I think in terms of settlements I think if you read the stories there the fact of the matter is that the governor was very much on board. It was his settlement. Two of the three commissioners run with settlements and even some of the consumer reps. So, yeah, there’s a different philosophy down there around settlements maybe in Connecticut. But it’s so different than any year in terms of what takes place up there. And we will go up and we’ve been very actively involved in the discussions. And I think everybody knows that our operations €“ utility operations are transparent. There’s really not much that folks don’t see. So it’s just the first inning of a nine inning game, and we’ll have a seat at the table as we always do and discuss these issues.

Angie Storozynski: Great. Thank you.

Jeff Kotkin: Thanks, Angie, appreciate that. Next question is from Gregg Orrill from UBS. Good morning, Gregg.

Gregg Orrill: Good morning. Thank you. Just around the 2023 financing plan. Is it possible to put a range around the use of the ATM?

John Moreira: What I’ve been saying right along is, we’re €“ it’s not a marathon. We don’t have to €“ and it’s not a sprint where we have to issue. So, what we said and I continue to say is, we will continue to be very opportunistic as to when we execute that plan and issue more. Remind everyone that, we did $200 million last year in kind of the third quarter at an average price of $92. I would love to be in a position to do more at $92, but we’ll have to keep a close eye on our stock performance. So I really can’t say. I’ll give you a range as to what we would need to do, or would want to do at this point.

Gregg Orrill: Okay. Thank you. Also, on the Connecticut AMI, is there anything coming up that would give you the ability to put that into the capital plan?

John Moreira: An order would be nice. No, I think just given the €“ we have to be mindful, and we have to be very sensitive of where energy €“ energy supply costs are, right? So, I think as we are starting to see it go in the right direction for customers. And the cycle is, as I mentioned, new rates will be in effect in Connecticut in July 1. So could PURA take that up to coincide with that? It would seem to be a reasonable outcome. But I think until things tamper down everything is done. The record is basically closed. So it’s just a matter of a decision by PURA.

Gregg Orrill: Thank you very much.

Jeff Kotkin: Thanks, Gregg. Next question is from Paul Patterson from Glenrock. Good morning, Paul.

Paul Patterson: Good morning. How you doing? Just wanted to follow-up €“ can you hear me?

Joe Nolan: Yes, yeah.

Paul Patterson: Okay. So a couple of things. One on the PBR proceeding. There was a staff proposal that concept proposal seems regarding performance based regulation in Connecticut that had sort of some UK elements potentially showing up. And I was just wondering if you could give us a feeling as to; A, when you think we might get more clarity as to when the PURA will take more action regarding that proceeding? And also just if you have any initial response to what you saw the staff proposal have?

John Moreira: Yes, Paul this is John. I think right now, it’s still a little too early in this process. To be quite honest with you, they did issue that proposal, which was very ambiguous. So we are working with them to share with them some concerns that we have and what the consequences could be if they go a certain direction. But right now it’s similar to what Joe mentioned in the legislative process it’s a bit too early.

Paul Patterson: Okay. And then you mentioned the FERC 2011 ROE proceedings. Do you have any more of a sense as to when we might eventually actually get something from FERC on that?

John Moreira: Paul, I wish I did. I think what we’re looking at — and there’s been the MISO decision remanded back. So it’s before FERC, I really think that FERC is going to issue a decision on the MISO and fix the methodology and then we should see a decision on the remainder of the complaints that’s out there not just for New England but other jurisdictions.

Paul Patterson: Okay. And then just finally, Joe you mentioned the optimism that you’ve had and stuff regarding the offshore wind review. If you can just maybe give us a sense as to the — if you’re a gambler kind of thing, sort of, like 50/50, how you think maybe we might think about handicapping this potential sale is taking place at this point in time?

Joe Nolan: Well, I feel very confident. I mean, the folks that are in the mix, the folks that have been doing due diligence, very sophisticated players. Some of them have lost out on some opportunities in the Americas. So they want to be in the business. I think that you’ve seen that appetite. So I am very, very confident in that process and the success of the process.

Paul Patterson: Okay. Thanks so much guys.

Joe Nolan: Thanks Paul.

Jeff Kotkin: Thanks Paul. Next question is from Ryan Levine from Citi. Good morning, Ryan.

Ryan Levine: Good morning. A few questions here. What flexibility do you have in your financing plan if the offshore wind sale process gets delayed further? The smaller in size, it doesn’t materialize. Any color you could share around the tools you have to manage the various outcomes and your latest thoughts?

John Moreira: Is your question if the transaction does not happen, or is it if it gets delayed? I just want to make sure I understand it.

Ryan Levine: I guess, I was asking both. Just broadly around what options do you have if it gets delayed, it’s smaller in size or it doesn’t happen at all?

John Moreira: Well, we would have to issue more debt. We have been financing our $1.9 billion investment by issuing debt. And we have to — and also we have we — the transaction doesn’t happen, right? We are committed to those tax benefits right? So off the gate, we have our first project going live South Fork later this year. So there would be a sizable amount of tax credits that would be generated. So that would certainly help finance that commitment.

Ryan Levine: And then on the offshore wind CapEx what are the remaining drivers of the variance between in 2023 and then 2024 to 2026. It looks like there’s about $500 million of delta in different cases. Can you unpack what’s driving that delta?

John Moreira: Well, it’s directly related to some of the recent procurement that we finalized that got us from the 82% locked into the 90% locked in and that’s primarily the foundation for some of these projects.

Ryan Levine: Okay. And then last question. What percentage of — what percentage increase in your equity investments are you embedding in your 2023 EPS outlook? And what markers are you looking at for the landfill gas component that you disclosed earlier?

John Moreira: On the equity, I would say we don’t have a sizable component of that. But once again I’m not going to marry myself to that. If the market is attractive and we want to take advantage of that opportunity, we may issue more or we may issue less. But right now, it’s not a significant amount.

Ryan Levine: Okay. Thank you.

Jeff Kotkin: Thanks Ryan. Next question is from Paul Zimbardo from Bank of America. Good morning Paul.

Paul Zimbardo: Hi, good morning. Thank you for squeezing me in. On the earnings driver side, could you quantify first historically what the pension income was in 2022? And what you expect on income or expense for 2023?

John Moreira: Well, — what I would tell you — and it was part of my formal remarks is the headwind the difference 2022 to 2023 as a result of slightly lower pension income to be honest with you was about $0.04 of an impact for 2023 versus 2022 for the reasons that I took. So, not — it’s a modest negative year-over-year change.

Paul Zimbardo: Okay, great. Thank you. And again I appreciate all the disclosures involved on the incremental CapEx. Could you help a little bit on the bridge from the old guidance to the new guidance? I know you mentioned potential interest rate headwinds but just kind of the building blocks? Because before it sounded like there was a step up in 2026 from offshore wind and you more than replace that with capital. So, just if you could help us on the moving pieces that would be appreciated. Thank you.

John Moreira: Sure. I would say it’s primarily two items or maybe three. The incremental CapEx incremental investments. As you — as shown on the slide where we show a 7.5% CAGR for rate base growth. And interest rates, we do — we have a strong track record of managing our cost structure. So — but interest rates, it’s difficult for us to manage and control. So it’s a combination of that. And I would say items that we have not yet included in our capital forecast as they materialize will be additive and that will have an impact on growth rate — long-term growth rate.

Paul Zimbardo: Okay. Thank you very much.

Jeff Kotkin: Thanks, Paul. Next question is from David Paz from Wolfe. Good morning, David.

David Paz : Good morning. Thanks for letting me on here. Just quickly you mentioned interest rates several times in your assumptions. Can you just share what interest rate you have baked into the midpoint of the 2023 guidance?

Joe Nolan : I would say, we’re pretty much aligned with consensus when the plan was pulled together. I think consensus right now has multiple rate changes now in mid-year and we have baked that into our assumption.

David Paz : Okay. And are you seeing interest rates stay flat or rise or decline over the five-year period?

Joe Nolan : David, you might want to mute your phone while we’re answering, we’re hearing echo

John Moreira : Okay. Thank you, David. So, yes — no, we do taper off a bit in the latter year. David, you here on

David Paz : Thank you.

John Moreira : Thank you.

David Paz : Okay. Thank you.

Jeff Kotkin: All right. Thank you, David. Next question is from Travis Miller from Morningstar. Good morning, Travis.

Travis Miller: Good morning, everyone. Thank you. Longer-term, wondering if you look out kind of two to three years the comments around natural gas supply, electric rates, gas rates. Is there anything fundamentally you’re seeing right now either in what you’re doing capital investment, operating costs, et cetera, or what else is happening in that region that could change some of that pricing dynamic and supply dynamic?

Joe Nolan: Yes. I mean, I think — this is Joe, good morning Travis. So, yes, I think what we have happening here is, we have a significant amount of renewable energy that’s just waiting to come online and I think that’s going to be the game changer. Between that I think you’ll see a big push around storage. Storage is obviously a game changer. When you have intermittent resources around solar and wind it’s critical. And I think we’re seeing a lot of breakthroughs in that space as well. So I do — I mean, I do feel confident that we are on the precipice of some, exciting opportunities, which will drive down costs and increase supply for our customers. Unfortunately, you just can’t get her quick enough as far as, I’m concerned.

But the fact that, this project in New York, will be up and running by year-end is exciting. The other projects are — they’re progressing quite well. Even our competitor’s project, are going well, because we’re obviously, involved in some of those interconnections. So, I do see it but again, on behalf of our customers, it can’t happen fast enough as far as I’m concerned.

Travis Miller: Sure. Okay. Just a real quick comment. Does the influence of renewables, exacerbate the gas situation, or like you were talking about improvement just in terms of, a peak load time period?

Joe Nolan: Well, I think any additional resources in the region, coupled with some storage, improves the situation. We are — we do a very good job here in the region around gas. It takes us quite some time and some planning, but we’ve been quite successful around that gas supply. So, I think that the introductions of renewables are the increase in them, it’s going to help the situation and not hurt it.

Travis Miller: Okay. Great. And then one other real quick one. O&M inflation isn’t listed as, one of your drivers in the pluses and minuses. Is that because you’ve got, rate adjustments or something regulatory, you expect to be offset, or is that, you’re just not seeing, cost inflation on the operating cost side?

Joe Nolan: Yes, Travis, so good point. So we are seeing that, but you’re absolutely spot on. We do have inflation adjustments in Massachusetts, NSTAR Electric and at NSTAR Gas, where it’s based on GDP and the inflation adjustment. And as I mentioned earlier, we have a very good track record of cost management and we’re very focused on that as well.

Travis Miller: Okay. Great. Got it. Thanks so much. That’s all I had.

Joe Nolan: Thank you, Travis

Jeff Kotkin: Thanks, Travis. And that’s the last question that we see this morning. So, we want to thank you very much for bearing with us, during the beginning of the call. If you have any follow-ups, please give us a call or send us an e-mail. And I’m just going to turn it back to Nadia.

Operator: Thank you. This now concludes today’s call. Thank you so much for joining. You may now disconnect your lines.