Eversource Energy (ES) — Q3 2022 Earnings Call Transcript

Thank you, Candy. Good morning, and thank you for joining us. 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 as defined within the meaning of the safe harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995. These forward-looking 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. These factors 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 3 months ended June 30, 2022. Additionally, our explanation of 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 President and Chief Executive Officer; and John Moreira, our Executive Vice President and CFO. Also joining us today is our new Director of Investor Relations, Bob Becker. Now I will turn to Slide 2, and turn over the call to Joe.

Thank you, Jeff, and thank you, everyone, for joining us on this call this morning. I will provide you updates on the energy supply challenges facing New England this winter and the strategic review of offshore wind investments. Before turning over the call to John to review the quarter in various regulatory proceedings. But first, I will review our operating performance. We've had an excellent first 9 months of 2022 with our reliability indices remaining among the industry's best. Our safety ratings are strong, and our diversity and sustainability metrics look quite favorable compared with our goals and our peers. Response time to natural gas service calls, a key safety and performance metric for our gas distribution business continues to be excellent. Our sustainability ratings at MSCI and Sustainalytics continue to be well within the top quartile among our peers, and we are in the final stages of reviewing how to best move forward with establishing aggressive goals for greenhouse gas reduction, including potentially setting a science-based target, something that only a handful of U.S. utilities are undertaking. While we continue to improve the service we are delivering to our 4.4 million customers, we understand that our customers have a significant concern over this winter's energy costs. Not only are fossil fuel prices much higher than they were a year ago, but our region continues to be challenged by the combination of heavy reliance on natural gas generation and inadequate infrastructure to supply sufficient natural gas to that generation during cold winter months. This challenge looks particularly daunting for New England given the disruptions in the global energy markets caused by the war in Ukraine. New England's access to reported LNG will be even more limited than in the past years. ISO New England has indicated that while our supply should be adequate in a moderate or normal winter, they may be challenged during a prolonged period of bitterly cold weather. Last week, I wrote to President Biden, asking him to consider a number of measures to help New England through the winter. They included emergency audits under the Federal Power Act and the Natural Gas Policy Act, in emergency authority under the Defense Production Act to ensure adequate energy supplies for New England. The letter also recommended considerations of a waiver under the Jones Act to ease the logistical obstacles that effectively prevent the shipping of LNG between U.S. ports in New England. I also asked President Biden to direct the Secretary of Energy to convene all relevant parties to develop a plan to ensure the region is ready to meet the challenges one or more extreme winter weather events would present, using both the authorities available to the market participants and the federal government's emergency authorities. Many points in my letter were consistent with the New England governors' governance sent to Energy Secretary Granholm in late July; the need for action now is compelling. Many of the solutions require advanced planning because they may require actions by regulators, finding new resources, chartering vessels, and arranging for additional fuel deliveries. As a T&D utility with no generation other than 70 megawatts of solar, we are very limited in terms of how we can influence the wintertime supply-demand equation. In those areas we can influence, we've done a tremendous amount. We have invested billions of dollars in our transmission and distribution systems to alleviate bottlenecks. Our nationally recognized energy efficiency programs have helped customers become much more efficient with their energy consumption. We offer our customers innovative payment options, including year-round budget billing options. But this winter is nevertheless promises to be expensive for those electric customers who did not lock in multi-year contracts in the past years. In New Hampshire, our standard offer, or default service, rate rose in August from $0.11 to $0.22 per kilowatt hour. Similar levels are likely in Massachusetts and Connecticut beginning in January. For our natural gas customers, residential heating costs in total bills will be up just over 20% on average compared with last winter, somewhat less than that in Connecticut. While any increases during these times is difficult for our customers, we are looking at much more significant increases a month or two ago before the recent pullback in natural gas prices. Turning to Slide 3, I will provide you with an update on our offshore wind partnership with Orsted. As you know, construction of our first project commenced early this year. Installation of the onshore conduit system, including cable vaults in town roads and along the Long Island railroad right-of-way, is nearly complete and ahead of schedule. Construction of our new onshore substation is on schedule, progressing well. It should be complete in the second quarter of 2023. In-water construction will begin this month using horizontal directional drilling to install a conduit 80 feet below the beach that will extend offshore. The transmission cable will be installed through that conduit next year to move energy from 12 offshore wind turbines to a new substation and into the Long Island Power Grid. Installation of the largest components, including the foundations, turbines, and offshore substations, will begin next summer off the coast of Massachusetts. We also continue to progress well on our larger offshore wind projects. The Bureau of Ocean Energy Management issued a draft environmental impact statement for the 704-megawatt Revolution Wind project in September. We expect the 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. On Sunrise, our largest offshore project, we filed a joint settlement in September with the New York Public Service Commission. The settlement includes proposed mitigation for certain environmental, community, and construction impacts associated with constructing the project. The joint proposal was signed by the New York Department of Public Service, environmental conservation, transportation, and state, as well as the offers of agriculture and the Long Island Commercial Fisheries Association. We also continue to target a 2025 in-service date for Sunrise Wind. We are also making significant progress on our strategic review. That review covers the three projects I just mentioned, which will generate approximately 1,760 megawatts once in service, as well as up to 175,000 acres of offshore wind lease areas, where we and Orsted have rights to build additional offshore wind facilities. We are now engaged with a number of potential buyers for our 50% ownership interest in our offshore wind joint venture. Orsted is actively supporting the process. It is very possible that we contract with one buyer for three projects and another for the open acreage. We do not expect to have any incremental news on our strategic review before the EEI conference, but we may have updates by year-end. We remain very big fans of offshore wind and expect it to become a critical energy resource for the Northeast, particularly in the winter when wind speeds are higher and more consistent. You can see on Slide 4 how much has been awarded to date in New England, in New York, and how much still needs to be secured. Contingent on the outcome of our review, I expect that our principal role in the future will be that of a regulated transmission provider integrating this valuable resource into our region's grid rather than a turbine owner. Thanks again for your time. I will now turn the call over to John Moreira.

Thank you, Joe, and good morning, everyone. This morning, I will review our earnings results for the third quarter of 2022, discuss recent regulatory developments, and review our finance and activity. I will start with Slide 5. Our GAAP earnings were $1 per share in the third quarter of 2022 compared with earnings of $0.82 in the third quarter of 2021. Third quarter results in 2021 included a charge of $0.19 per share to reflect last year's settlement agreement that resolved a number of regulatory issues at Connecticut Light and Power. Both years included the impact of $0.01 per share of charges related to transaction and transition costs associated with the former Columbia Gas asset acquisition. Excluding these charges, we earned $1.01 per share in the third quarter of 2022 compared with earnings of $1.02 per share in the third quarter of 2021. For the first nine months of 2022, we earned $3.13 per share on a GAAP basis compared with earnings of $2.65 per share in the first nine months of 2021. Excluding charges related to transaction and transition and the CL&P settlement charges that we recorded last year, we earned $3.17 per share in the first nine months of 2022 compared with earnings of $2.95 per share in the first nine months of 2021. Looking at additional details on the third quarter earnings by segment, starting with our electric transmission segment, which earned $0.44 per share in the third quarter of 2022 compared with earnings of $0.40 per share in the third quarter of 2021. Improved results were driven by a large level of higher investments in our transmission facilities. Moving on to our electric distribution segment, which earned $0.65 per share in the third quarter of 2022 compared with earnings of $0.62 per share in the third quarter of 2021. Again, excluding the settlement charges I previously mentioned, the improved earnings were driven largely by higher revenues and lower pension costs, partially offset by higher O&M, property taxes, and depreciation expense. Our natural gas distribution segment lost $0.07 per share in the third quarter of 2022 compared with a loss of $0.06 per share in the third quarter of 2021. The increased losses were due to a higher nontrack O&M, property taxes, depreciation, and interest costs, which were partly offset by higher revenues and lower pension costs, primarily at Yankee Gas. Our water segment earned $0.05 per share in the third quarter of 2022, the same as the third quarter of 2021. Eversource parent and other companies lost $0.06 per share in the third quarter of 2022 compared with earnings of $0.01 per share in the third quarter of 2021, excluding the transaction and transition costs that I mentioned earlier. The decline was due largely to two factors: higher interest expense, primarily related to new parent company issuances, which lowered the results by $0.04 per share; and higher income tax expense of about $0.03 per share, which was specific to the third quarter results as this is when we finalize our annual corporate income tax returns. Despite the headwind from higher interest costs, we continue to project our full year 2022 earnings of between $4.04 and $4.14 per share, excluding transaction and transition costs that I spoke about earlier. Turning to the longer term, as you saw in our news release, and as you can see on Slide 6, we maintain a long-term EPS growth rate in the upper half of 5% to 7% range through 2026. We also reaffirm our $18 billion five-year regulated capital program that we discussed during our February earnings call, including our $3.9 billion regulated capital investment projection for this year. We will provide you with an updated five-year forecast when we report our year-end results in February. As we mentioned during prior earnings calls, there continues to be an increasing need for Eversource to make capital investments in our transmission and distribution systems that will enable our region to achieve its aggressive clean energy targets more rapidly. As a result of this strong public policy imperative and our ongoing focus on improving our systems to address aging infrastructure, we estimate that at least $3 billion of additional investments above our current $18 billion capital forecast will be required through 2026. In July, we discussed the need to invest up to $500 million in our transmission system to enable approximately 2,000 megawatts of offshore wind generation to be connected into the New England grid. We also noted that ongoing regulatory reviews of our advanced meter infrastructure proposals are currently taking place. At this time, regulators in both Connecticut and Massachusetts are actively working through dockets, with decisions expected later this year in Massachusetts and either at year-end or early next year in Connecticut. Moving to Slide 7, we want to highlight some new infrastructure needs to enable clean distributed resources to connect to our grid. Our proposals are currently before the Massachusetts Department of Public Utilities. Massachusetts has very ambitious carbon reduction goals, aiming for an 85% reduction by 2050. Two cornerstones of efforts to achieve those reductions are enabling offshore wind and solar generation. Joe discussed the offshore wind earlier; now on the solar front, a growing number of solar distributed energy resources are awaiting connection to the grid. In certain areas of our state, particularly in Southeastern Massachusetts, we are at a standstill in connecting new solar resources because there is very little available grid capacity. Under the current existing model, the developer whose project triggers the need for a significant upgrade to infrastructure pays the full cost of resolving this capacity issue or bottleneck. When large T&D equipment limits are reached, the cost to resolve such bottleneck could become cost-prohibitive for these developers. So the project will likely not move forward, nor will other projects behind it, thereby stalling in the interconnection queue. That has created a backlog of construction of about 350 megawatts of distributed solar generation in the state. The map on Slide 7 shows the six areas of Massachusetts with the greatest bottleneck. We have proposed a resolution whereby we would build out the system in advance and recover some of the costs from solar developers as they tie their projects into the grid. Slide 9 shows that the upgrades would be a combination of transmission and distribution infrastructure needs. Together, they would total about $900 million under our proposal. Developers would pick up about one-third of those costs over time, and the associated rate base would be adjusted accordingly. A DPU decision on the first of the six projects is expected later this year, with decisions on the remaining five projects to follow in 2023. We view our proposal as an innovative solution to a vexing issue that has slowed the build-out of third-party solar expansion in Massachusetts. On the regulatory side, we are nearing the end of one general rate review with hearings on another one about to commence. A summary of these two cases can be found on Slide 10. Briefing in the NSTAR Electric rate review concluded in late September, and a decision is expected on December 1, with new rates going into effect on January 1, 2023. We feel very good about the strength of our case as well as our proposals to enable the Commonwealth's clean energy goals. Moving to our new rate review, on August 29, Aquarion Connecticut filed its first rate review application in about ten years. Key elements of the three-year plan are shown on this slide. Aquarion Connecticut's case is a result of significant infrastructure investments made over the past several years to enhance water service reliability for its customers. Evidentiary hearings will start in about three weeks, and a final decision is expected in mid-March. Turning to recent financings, we completed our fourth green bond issuance at NSTAR Electric in September, selling $400 million of 30-year notes at 4.95%. That issuance helped pay off a similar size issuance that matured in mid-October. With that issuance now behind us, we have completed our long-term debt issuance program for the year. In terms of equity issuances, as you can see on Slide 11, we have now issued about 2.2 million shares through our at-the-market program at a weighted average price of $92.31. Through October, we have also issued approximately 810,000 shares of treasury stock this year to fund our dividend reinvestment and employee equity plans. The impact of those issuances reduced EPS by approximately $0.01 per share in the quarter. Finally, in terms of credit metrics, as you will see shortly when we file our 10-Q, our cash flows from operations totaled $1.7 billion in the first nine months of 2022 compared with $1.5 billion in the first nine months of 2021. This improvement was primarily driven by higher net income, higher depreciation and amortization, and lower pension plan contributions since our plan is essentially fully funded as of the end of 2021. Thank you very much for joining us this morning, and we look forward to seeing many of you on the call at our Annual EEI Finance Conference in Florida later this month. I will now turn the call back over to Jeff for Q&A.

Thank you, John, and I'm going to return the call to remind you how to enter your questions. Candice? First question this morning is from Shar from Guggenheim.

So Joe, regarding the offshore wind sale process, you mentioned on previous calls that you were working on the tax leakage offsets. Have you been able to identify anything there so far? Are we still considering a 100% sale of the leases in the projects, regardless of their construction cycle stages, without any build-own-transfer scenarios?

Yes. So we're definitely looking at a complete exit of the projects. In terms of the tax, I'm going to turn that over to John Moreira; he's better equipped to answer that question.

Shar, so as I continue to communicate, we're looking at every alternative to minimize any tax leakage. I think at this point, we're still going through those assessments working with our advisors. I think it's a little premature. But we do have a plan to mitigate as much of that tax leakage as possible.

Okay. Perfect. And then, Joe, you previously indicated that you need to find roughly $3 billion of spend to offset the loss of the wind earnings. If I recall correctly, you had about $1.5 billion that has been identified. So we're simply stepping up here to having a line of sight on roughly $2.4 billion out of the $3 billion with the DER spending you just released, or is there some overlap? And I guess where could we see the remaining opportunities, especially as we're thinking about this in the context of your overall growth guide as we look ahead to the sale and the next roll forward?

Yes. Well, the good news is that number, we've got up to about $2.5 billion. John is going to fill in some of the details on how we are going to fill that in. So John?

Yes, we have specified $1.5 billion of the $3 billion figure we discussed. Let me explain that to you. One billion is allocated to AMI, and I mentioned earlier that we expect a decision in Massachusetts by the end of this year, with Connecticut likely later this year or early 2023. This totals about $1 billion to $1.1 billion. Additionally, we have identified approximately $0.5 billion for transmission interconnection, with $200 million of that already approved. Today, we announced nearly $900 million in investments aimed at addressing a critical need in Massachusetts to support solar generation connecting to our grid. These investment opportunities will allow up to 1 gigawatt of generation to integrate with our transmission and distribution systems. We currently have six cluster projects under review by the DPU, which accounts for that $900 million. As I noted in my previous remarks, this work is mainly focused in Southeastern Massachusetts, where we are facing capacity constraints. From a regulatory perspective, we are progressing well, and we have developed a creative proposal for the regulators to address this demand. We are enthusiastic about this and expect it to materialize over the next 4 to 5 years, with the complete infrastructure in place by 2026 to support the 1 gigawatt I mentioned.

Got it. Terrific. So I guess the key message is you're chopping wood on that $3 billion that you're looking to backfill. So that's good.

Absolutely. I feel very confident that once we update our five-year capital plan that we'll share with you in February, that we will get to that number.

Next question is from David Arcaro from Morgan Stanley.

Maybe following up on a couple of the topics that Shar raised. On the offshore wind, strategic review process. Could you just give an update on what interests you're seeing, whether anything has changed with the rising rate backdrop and overall kind of number and type of potential interested parties there?

Yes. The process is progressing very well. We have several highly interested parties, and the interest rate hasn’t raised any concerns for them. We are very optimistic and remain hopeful about the process.

Okay. Got it. And then on the level of costs that have been locked in, it looked like the percentage hasn't changed since the last quarter. What are you seeing in terms of the inflation in offshore wind construction costs lately and your current thinking around willingness to lock in additional costs with the strategic review going on?

We are in the 80% range, specifically the low 80s. The contracts we are discussing are not ones I have major concerns about regarding costs and similar issues. There is competition in this area, so we will be strategic in our contracting approach. I am quite confident about the remaining 15% to 18%, and I do not have concerns about it.

Next question is from Steve Fleishman from Wolfe.

So just we're getting near the end on the Massachusetts case. Could you just give us a sense of just how you're feeling about getting a reasonable outcome there?

Yes, we feel very good about it. We had some productive hearings and engaged in meaningful exchanges. We have been actively working with multiple parties and remain extremely optimistic about a favorable outcome in that proceeding. The increases in question were not significant, and I believe people recognize the exceptional service we provide to our customers in Massachusetts. Therefore, we continue to be very optimistic.

Okay. Great. When you announced the offshore wind sale, you mentioned the net income you were hoping for in '26 and how you could use the proceeds to reach that level through investments in the regulated business. You're clearly getting those investments organized. Overall, how confident are you about achieving your growth targets along with the additional net income?

Yes, that's a great question. We are currently updating our revised five-year forecast, incorporating the additional capital necessary to achieve our goals. We are very confident that we will reach the guidance levels you expect from us. Overall, I feel very positive about our progress.

Next question is from Nicholas Campanella from Credit Suisse.

I guess, Joe, just on the Biden letter and the winter scenario. Obviously, the fact that you're writing this letter indicates it's a serious situation. And I just wanted to ask, when you think about the ability to deploy capital at the pace that you are in the current plan, does it change your thinking at all and the ability to spend capital with the pressure in customer bills from the fuel lines?

Yes. No. I mean, I think the investments that we want to make around transmission to unlock and tap into some renewable resources that cannot get onto the grid in a meaningful way for the operator. So that's something that will only reduce customers' costs at the end of the day if we're able to get at some of those renewables. So I don't think that this would have an adverse impact on our customers. So no, I don't feel it's going to impact it.

And then on IRA, good to see no AMT impact. And I think you're saying kind of cash uplift in the slides here. So can you maybe just update us on what your FFO to is in a post-IRA world versus kind of where it is today?

It will head in the right direction. There's no doubt about it with the IRA, given the deployment of our solar program in Massachusetts, where we get the ability to get those tax benefits upfront and then, as required, flow it back to customers over time. So we do see an uptick in our FFO to debt.

Next question is from Durgesh from Evercore.

Guys, what are sort of the key dates for us to watch on these six DER-related projects in Massachusetts? I believe you said one of them is under consideration for approval here shortly. Just if you can give us a timeline for us to kind of track that would be really helpful, for regulatory approval.

Sure. Durgesh, this is John. We have submitted all six proposals individually. We anticipate a decision from the DPU on the first one, which represents a $150 million opportunity, by the end of the year. The other five decisions will come throughout 2023.

Got it. So basically, by the time of your fourth-quarter update, CapEx update, you would have received a decision on one of the projects, and the remaining five will be layered in sometime next year?

That's correct. That's correct. And the construct, as I mentioned, is basically the same for all six projects. Obviously, there's varying degrees of investment for these six, but the construct that we filed for is very consistent.

Next question is from Jeremy Tonet from JPMorgan.

Just wanted to touch base on the offshore wind process a little bit more. And just want to see how is the process tracking toward that potential year-end announcement? Just trying to look at the language here is your slide language pointing to a slightly longer process versus prior expectations? Just trying to parse through this end of the year as you put it in the slides.

Sure. Yes, it's Joe. We're working very hot at this right now. We've got very interested parties. We would like to be able to have an announcement by year-end, but there's no guarantees around that. But I would tell you that there is a very strong group of buyers that are in there, and we feel very, very good about the process. So we're optimistic.

Got it. That's helpful. And then just pivoting, could you frame the impact of higher interest rate expense on growth within your EPS CAGR? Just wondering what levers are left to offset this higher expense? And how much of a headwind could it be? Same thing for pension, overall.

Yes. Yes, it will be a headwind, as you would expect. But we're on it, and we are working to mitigate that impact. Obviously, it's uncertain what the time frame is, and this higher interest rate environment will continue. But we, as I mentioned earlier, are focused on developing our plan for next year, and I feel very good that we'll have opportunities to mitigate that headwind.

Next question is from Ross Fowler from UBS.

All my questions on offshore would have kind of been answered. So maybe we can look back to Joe, your comments at the front of the call about bill pressure across this winter. You said bills would be up an average of 20%, and that's given the pullback in natural gas. It's been in the 70s, and the way it went lately. So we had some good weather, too, which is nice. But growing up there, it's going to get cold at some point. So can you just remind us how you're hedged across the winter for that natural gas on price, like through January, February, and March? And then maybe it's not even necessarily about hedging and price given your commentary, but more about even getting supply should it get colder than normal across this winter. So just maybe frame that risk for us a little bit more.

Let's focus first on our gas business. We are hedged and keep approximately a 20-day supply of LNG available at our facilities. We have multiple LNG facilities, which gives me confidence about the supply and natural gas situation for Eversource customers this winter. I have no concerns regarding that. We start planning and allocating resources into storage in May each spring, filling all our tanks, and we're in a very strong position this year. My main concern lies with the electric generators in the region, whether they are natural gas-fired or oil-fired; they do not have a secure fuel supply. As a result, during prolonged cold spells, they may lack the fuel needed to operate. This is what prompted me to write to President Biden seeking relief. He has significant resources, particularly with the petroleum reserves, to assist with oil. Additionally, I addressed the Jones Act, which restricts vessels from operating freely in U.S. ports. Recently, there have been 6 to 8 foreign vessels in the Gulf filling up, set to head to Turkey, Japan, South Korea, and Europe. It troubles me that they cannot come to the Northeast with U.S. liquefied natural gas. The President has the authority to address this issue, as he has done before during crises like the one in Puerto Rico. He has been a strong advocate for energy issues, and I have faith he will support us in ensuring our customers experience a trouble-free winter.

And then maybe winding back for a little bit more color on an earlier question. You mentioned that all of these capital programs you're deploying and filed for but aren't yet approved; some of them are really to sort of mitigate the rent pressure around electric bills because you're taking fuel costs out of the system. But if bills are going up in the near term, are you worried about bill pressure, maybe not certainly taking those programs away because that's where we're trying to get to is mitigating that bill pressure. But are you worried about regulators slowing the pace to alleviate some of that bill pressure?

Well, listen, we feel for our customers; this is a challenging time, but there's nothing new to this region. We have experienced this before, and we have a long track record of working with our customers. I think when the regulators see the type of investments that we want to make, and the benefits, I can list 10 transmission projects that have reduced customers' bills by billions of dollars. So these are all very good projects to help our customers access lower-priced electricity. So you have to make the investments in order to get the savings. I think that's what the regulators and key decision-makers will look at and decide that it's the right decision.

Next question is from Paul Patterson from Glenrock.

Can you hear me?

Yes.

So I wanted to follow up on a few things. First of all, on the proceeding in Massachusetts by Commonwealth Edison asking for a delay. You guys filed a joint letter, I believe, on Tuesday with National Grid and others, basically indicating that you had no intention to renegotiate the contract. And then, I guess, I saw that yesterday the Governor of Massachusetts seemed a little bit more open to the idea. Just wondering if you could give us a little bit more color on how you see this. And I guess if you can, why you guys see yourselves in a different position with your projects as opposed to this one that's asking for renegotiation?

Yes. Keep in mind that our pricing is higher; it's in the $100 to $110 per megawatt hour range. The project that we're talking about came in here and did very, very low pricing against projects that we had bid. I do not feel that we have a success for any renegotiation. And keep in mind that what the government has said is that he would allow National Grid to make a proposal. He didn't say that he was going to go and renegotiate with them. A lot of players will have to decide on this. Certainly, it's our regulators. Now regulators at the end of the day are the ones that are going to decide what is best for the customers. And so that's the reason why you're not seeing any of our projects in there right now looking to renegotiate.

That's great. I was curious about the response you've received regarding the White House and your letter, which makes sense. I'm thinking broadly about whether this situation with LNG imports, which plays a significant role in New England's reliability, serves as a wake-up call. Should the region be more receptive to infrastructure development, or should the federal government be more proactive in advancing these projects? I'm wondering if you're observing any changes in Washington related to reliability and the urgent need for significant infrastructure improvements to be expedited. Do you see what I'm getting at?

Well, yes, you appreciate the gravity of the situation here, absolutely. I do see that each of these governors realizes the seriousness of this. We are at a fragile point in time as we transition to this clean energy environment. Consequently, we're going to need some relief, whether it's the Jones Act relief or other types of projects. Certainly, it's disappointing. You know how hard we worked on Northern Pass to bring hydro down. Another great resource that this region could really use. I do think we're all working collaboratively. We were up in Burlington, Vermont. We had all of the states along with FERC, and we're looking at these issues. A lot of my colleagues at the table understand the seriousness of it. I'm fully confident that we're going to be able to put steps in place that will allow us to transition uneventfully to a clean energy future. It's going to be challenging. It's going to be challenging; it's going to require a lot of work. But I know that the folks at the table can get this done.

Next question is from Paul Zimbardo from Bank of America.

Just a couple for me. On Jeremy's question, what interest rates are you assuming in the cost of debt on the offshore wind when you give those expected long-term average ROEs? And just how has that evolved since you gave that original target?

Well, are you referring to next year?

The expected long-term average roles from the slides.

From a long-term perspective, the interest costs related to offshore wind after the divestiture will be used to lower both our short-term and long-term debt. In 2023, we have $1.2 billion of long-term debt maturing at the holding company, so the timing is perfect for us. Additionally, the total utility debt maturing is likely the lowest I have seen in a long time, with only about $800 million of debt maturing at the utilities. This positions us well, but we still need to finance our capital program. Therefore, I do not see any significant challenges or major changes in our long-term guidance due to the current interest rate environment.

Okay. I was more referring to like the actual projects. I didn't know if the interest rates are pressuring and there's an offsetting mitigation positive to keep the average ROEs intact.

Well, first of all, since these projects are under construction, the interest costs we are incurring during this phase are capitalized. Therefore, we are not experiencing any financing impact from these projects. Once we receive the proceeds from the divestiture, we will use those funds to reduce the debt we currently have.

Yes. Understood. Okay. Great. And then briefly, I know you gave some commentary last call about pension. Just if you could give any updated thoughts there about pension returns or just your overall thoughts as we enter next year.

Sure. A lot to do so. So pension returns, just like our peers, are not heading in the right direction for us. But even with that said, there will be some headwinds. But once again, not anything material, not anything that we cannot overcome.

Next question is from Travis Miller from Morningstar.

Not to belabor the point here too much, but back to the idea about what might happen in a harsh winter environment. In the past, on a regulatory standpoint, you guys have had some headwinds. We've had difficult weather events. Do you think something has changed? Are you trying to set up a scenario here where if there are issues in terms of energy delivery resilience, reliability? Is there a way you can turn that into a positive from a regulatory standpoint and get approval for more capital investment instead of getting penalized for not meeting a certain requirement?

Well, I think what we're focused on with the regulators now are solutions to deal with this current winter. I don't know that maybe that would translate into some longer-term investments. But right now, this fuel security program, where maybe these generators get given funds to have say a 7-day supply of fuel on-site, those are the types of measures we're looking at short-term measures with our regulators. During that dialogue, you can demonstrate to the regulator that a particular transmission investment would unlock a certain number of megawatt hours in a region and lower the cost. We have very good regulatory relationships. We have very good regulators that are very engaged, and we're engaged with them on these issues. Anytime you have engaged parties, you get much better solutions.

Okay. Great. And then one more on the governor's rates. Anything near term after the election that could be impacted either in programs that you're seeking approval for or things you'd expect in the next year or so on the policy front, depending on the outcome?

Yes, I believe we have a comprehensive understanding of all the states. The regulatory environment appears to be stable, and we have long-term plans in place. We don’t anticipate any major shifts regardless of the election outcomes. The focus on clean energy and advanced metering infrastructure is shared by all candidates. There is a widespread acknowledgment of the necessity for a grid that supports various resources, whether for electric vehicle charging, solar energy, or any distributed resource. Therefore, I do not foresee any changes, irrespective of who wins in each state.

Well, that was the last question that we have this morning. So we want to thank you all very much for joining us. We look forward to seeing you at our Annual EEI Finance Conference. If you have any more follow-ups today, please send me an email or give me a call. Thank you.