Eversource Energy (ES) Earnings Call Transcript & Summary

As Welcome to the Eversource Energy, 2021 Year-End Results Conference Call. My name is John. I'll be your operator for today's call. [Operator Instructions] Please note, the conference is being recorded. I will now turn the call over to Jeff Kotkin.

Thank you, John. Good morning, and thank you for joining us. I'm Jeff Kotkin, Eversource Energy's Vice President for Investor Relations. During this call, we'll be referencing slides that we posted last night on our website. And 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. 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 Phil Lembo, our Executive Vice President and CFO. Also joining us today are John Moreira, our Treasurer and Senior VP for Finance and Regulatory; and Jay Buth, our VP and Controller. Now I will turn to Slide 3 and turn over the call to Joe.

Good morning. Thank you, Jeff. I will start with an overview of our team's 2021 operating accomplishments, update you on offshore wind projects and discuss recent progress executing our Clean Energy strategy. I will then turn it over to Phil for a review of our financial performance and new 5-year forecast. We accomplished a great deal in 2021, as you can see on Slide 4. We had a terrific year operationally. We were able to put closure around a challenged set of regulatory proceedings in Connecticut, we made very significant progress on offshore wind projects, and we have enthusiastically engaged the entire company around our target of having operations be carbon neutral by 2030. Turning to Slide 5 and operations. You can see that our electric service reliability and restoration performance were top decile and top quartile, respectfully. And our safety metrics as well were well above average. We continue to invest to enhance our customers' electric service reliability and the results are apparent. Even during a year when we had 20 major storm events and dozens of less severe events around our 3 states, we also continued to refine our emergency response efforts, which were on display again just 2.5 weeks ago, when a weekend blizzard clobbered Southeastern Massachusetts with hurricane force winds and snow depths up to 2.5 feet. Thousands of our employees and contractors worked through biting cold to restore about 300,000 outages. Winds were still howling after the snowfall ended, but our crews were able to get our customers back online within 2 days. Most of our storm damage was pre-related. We continue to work closely with our regulators in the communities we serve to ensure that we are installing more resilient equipment on our system and addressing the heavy vegetation along our roadways. We are committed to making the important investments needed to maintain high levels of electric service reliability and providing the grid resiliency needed to support our region's aggressive clean energy goals. In addition, we continue to accelerate the replacement of our most leak-prone natural gas and water infrastructure. Turning to Slide 6. You can see that despite strong results, we, like many other high-performing utilities, underperformed both our peers and the broader markets in 2021 from a total return standpoint. This comes after some very strong years of relative outperformance by Eversource that continues to place our medium- and long-term total return significantly above the EEI Index. There are solid reasons for our strong long-term record. First, since the 2012 merger that created Eversource, we have consistently achieved short-term and long-term earnings per share growth of about 6%. Going forward, we continue to expect our regulated businesses to support EPS growth in the upper half of the range of 5% to 7%. That earnings growth has enabled us to achieve attractive long-term dividend growth as well. As you can see on Slide 7, earlier this month, our Board approved a $0.14 per share increase in our annualized dividend, an increase that is consistent with our long-term growth projection. Not only is that level of dividend growth attractive to our investors, the low 60%s payout ratio that it represents allows us to reinvest more than $500 million of earnings annually back into our business, reducing our incremental debt needs and supporting our strong credit rating. Turning to Slide 8. Our offshore wind business had more positive developments over the past 13 months than we experienced over the previous 3 years combined. Last week, as you can see on the slide, New York Governor Hochul joined in breaking ground on South Fork, the first offshore wind project we are building under our 50-50 partnership with Ørsted. [ Land-based ] construction has commenced on Long Island with a 130-megawatt 12-turbine project will connect into Long Island Power Authority grid, greatly -- providing greatly needed source of clean power. We expect South Fork to begin operating in late 2023 and thank the federal, state and local regulators and elected officials who have worked on the review of this project for years. 2021 also was a pivotal year of our 2 much larger projects, Revolution Wind and Sunrise Wind. As you can see on Slide 9, we are well into the federal and state siting process for both projects. Last year, the Bureau of Ocean and Energy Management set schedules for review of those 2 projects which we expect will culminate in the final siting approvals in the second half of 2023. Assuming those schedules are met, we expect both projects to enter service in 2025, with Revolution Wind likely entering service first. We have made significant progress securing materials and services for our 3 projects. We have 80% of the costs of the portfolio locked in. It seems that every few weeks we are announcing another contract. Many of those contracts are with domestic manufacturers and service providers that are located in states where we are contracting for our offshore wind projects. Slide 10 has an overview of some of the publicly announced contracts. However, over just the past few months, we have seen higher-than-planned costs for such items as offshore wind foundations, [ certain ] installation vessels and logistics as well as offshore substations. Ørsted referenced some of these cost increases during its investor call 2 weeks ago. The pandemic and global growth in offshore wind have rapidly tightened the market and supply chain for offshore goods and services. Fortunately, we procured the largest scopes of work prior to the inflationary pressure taking hold. Our wind turbine agreement with Siemens and wind turbine installation vessel charter with Dominion Energy, which makes up a significant portion of the project's costs, are 2 prime examples. Throughout the projects, we and our partner, Ørsted, have been successful in finding ways to offset increases with savings in other areas. I am optimistic that our teams will find additional improvements opportunities as we move forward with the projects. One of our key contracts is for the Connecticut State pier in New London. The State of Connecticut, Eversource and Orsted are funding a $200 million project to create an important staging area for offshore wind construction, including our South Park Wind, Revolution Wind and Sunrise Wind projects. It is probably the best site for this work between North Fork, Virginia and Halifax, Nova Scotia, and only 60 to 65 miles from our nearest turbine locations. As you can see on Slide 11, the Connecticut Port Authority commenced onshore work last summer. And a couple of months ago, the authority received approval from the Army Corps of Engineers for the in-water construction. We consider the New London lease to be a tremendous source of future economic development for the state of Connecticut and a key strategic advantage for our partnership. The site is quite close to our 550 square mile area where we and Orsted expect to build projects with at least 4,000 megawatts over the coming years. We expect to continue to seek new opportunities for our lease area off Massachusetts, while continuing to be disciplined and strategic in our bidding. In Massachusetts, Governor Baker has proposed new energy legislation that, among other items, could amend certain restrictive pricing language that contributed to having only 2 bidders in the state's most recent offshore wind RFP. The bill is currently in the House and is expected to move on to the Senate during the current legislative session that ends in mid-July. We will keep you apprised of its progress. Separately, as many of you are aware, the Eversource-Ørsted joint venture did not seek to be prequalified for next week's New York bight auction. We are very comfortable with our current uncommitted acreage and think it's strategically located to provide us with a competitive advantage in future RFPs in New England and New York. Once the bight auction is complete, our understanding is that New York likely will move swiftly to its next offshore wind RFP. Our offshore wind partnership is just one of several major initiatives we have underway to help our states combat climate change. At the same time, we are focused on reducing [ emissions ] within our own operations. Slide 12 notes that the 5 key areas where we are seeking to reduce greenhouse gas emissions in our efforts to be carbon neutral by 2030. No U.S. utility or natural gas utility has a more aggressive target date for achieving carbon neutrality for Scope 1 and Scope 2 [ emissions ]. We are currently looking to enhance our climate leadership by taking a closer look at emissions across the value chain, including examining what a science-based target would entail for a company with our profile. This includes downstream [ emissions ] from our customers' energy use. Clearly, our energy efficiency programs offer many benefits in this regard. Last year, we invested approximately $600 million on initiatives that will help our customers reduce their lifetime greenhouse gas emissions by approximately 4 million tons. Our new DPU-approved 3-year energy efficiency plan will expand those efforts with a growing focus on electrification. It will provide our Massachusetts electric and natural gas customers with the tools necessary to meaningfully reduce their carbon footprint and help place the state on the path to be net GHG neutral by 2050. The $1.7 billion plan maintains our long-standing mission of helping all residents and businesses reduce their energy usage and manage energy costs, and is also focused on service to customers in environmental justice communities and low and moderate income households. Through our now approved programs, we expect to electrify more than 23,000 new and existing residential households as well as more than 20 million square feet of commercial space. Separately, NSTAR Gas last month rolled out an innovative community geothermal project for Framingham, Massachusetts, that was enabled in our 2020 NSTAR Gas rate decision. It is shown on Slide 13. We are also preparing an integrated program to combine our opportunity to build more rate-based solar in Massachusetts with the potential to tie in storage in microgrids. We expect to file initial proposed projects with the DPU within a few months. This is part of our comprehensive climate resilience efforts that are consistent with the goals of state policy makers. Finally, I want to comment on our relationships in Connecticut. Compared with a year ago, I believe we are in a much better place. Our October rate settlement was approved by PURA and significant customer credits lowered CL&P customer bills in December of 2021 and January of 2022. PURA has issued final orders on storage and electric vehicle programs, which are now being launched. We sense a broad level of support for AMI as it lowers costs and improves service to customers, significantly advances the pace of integration of renewable energy resources, and enables achievement of the state's clean energy goals. We believe PURA will move forward with the docket and approve its deployment at some point later this year. Thanks again for your time. I will now turn the call over to Phil Lembo.

Thank you, Joe. And this morning, I'm going to cover several areas, 2021 results, our 2022 earnings guidance, an updated 5-year regulated investment plan and long-term outlook, an update on some of the current regulatory proceedings, and finally, additional details around our offshore wind investment plan. So let me get started. Start with the 2021 results on Slide 15. Our GAAP earnings for 2021 were $3.54 per share compared to $3.55 in 2020. In the fourth quarter of 2021, GAAP earnings were $0.89 per share compared with GAAP earnings of $0.79 in the fourth quarter of 2020. All those periods include acquisition costs, primarily related to our purchase in 2020 of the assets of Columbia Gas in Massachusetts, which we now call Eversource Gas of Massachusetts or EGMA. As I noted on our third quarter call, 2021 full year results also include charges related to the settlement agreement in Connecticut. Excluding those nonrecurring charges, we earned $3.86 per share in 2021. That's up 6% from $3.64 in 2020. For the fourth quarter, excluding these charges, we earned $0.91 per share in 2021 compared with earnings of $0.85 in the fourth quarter of 2020. To break down the earnings into segments, electric transmission earned $1.58 per share for the full year 2021 compared with earnings of $1.48 in 2020. Higher earnings resulted from continued investment in our transmission system. We invested just over $1.1 billion in our transmission facilities in 2021, and that's compared to just about $960 million -- $964 million, to be precise, in 2020. And that's for -- the reason for that was it's mostly replacing obsolete equipment and improving reliability and resilience in the region. Our electric distribution segment earned $1.61 per share in 2020 excluding the settlement charge -- excluding the settlement charge. This compared to $1.60 in 2020. The higher revenues were largely offset by higher O&M, depreciation, property tax and interest expense. And really, these higher expenses stem from our ongoing investments to improve service and reliability for our customers. We invested about $1.25 billion in our electric distribution system in 2021, and this is up from just under $1.2 billion in 2020. Our natural gas distribution segment earned $0.59 per share in 2021 compared with earnings of $0.40 in 2020. This growth was driven primarily by having a full year of EGMA earnings included in our financials in 2021, and this is compared to less than 3 months of EGMA earnings in 2020. This also includes the ongoing investment in safety and reliability of our natural gas systems, where we invested about $800 million in 2021. Our water distribution segment earned $0.11 per share in 2021, and this is down $0.01 from $0.12 in 2020. The small decline primarily reflects the sale of the water delivery system around Hingham, Massachusetts, that occurred in 2020. We continue to invest in clean and reliable water delivery, with investments in our water segment totaling $144 million in 2021. This is up 13% from the prior year and about double from where it was when we first acquired Aquarion in 2017. Excluding acquisition-related charges, the Eversource parent segment lost $0.03 per share in '21 compared to earnings of $0.04 in 2020. This change is largely due to a higher effective tax rate. Overall, as Joe covered in his remarks, we are very pleased with the strong year we had, as we successfully overcame many challenges and delivered very positive results for our customers and for all of our stakeholders. From 2021 results, I'll turn to our 2022 guidance in Slide 16. We are projecting recurring earnings of between $4 and $4.17 per share this year, compared with $3.86 we earned in 2021. The midpoint of that range reflects a 6% increase over 2021. This range excludes the remaining costs we expect to incur as we complete the integration of EGMA operations from NiSource to Eversource systems in 2022. The primary growth drivers are our ongoing investment in our electric transmission segment, where we expect to invest approximately $1.1 billion in 2022. The higher revenues from our distribution segments, much of it relates to ongoing reliability and resiliency investments with existing recovery mechanisms and a performance-based revenue adjustment at NSTAR Electric. Those higher revenues will be partially offset by anticipated increase in depreciation, property tax and interest expense related to our customer-focused investments. On Slide 17, you see that we are reiterating our long-term earnings per share guidance in the upper half of the 5% to 7% growth rate from our core regulated businesses with 2021 recurring EPS of $3.86 as the base level. To be clear, this guidance excludes earnings from offshore wind projects. And on Slide 18, you can see that the primary driver of this growth is our regulated capital program, which continues to make our energy and water delivery system safer, more reliable and more resilient for our customers. We expect to invest approximately $18.1 billion in those systems over the 5-year period of 2022 through 2026. That compares with a $17 billion investment plan we discussed with you a year ago, which was for the period of 2021 through 2025. On the distribution side, we assume that we'll invest nearly $400 million over the next 5 years on grid modernization and electric vehicle charging infrastructure in Massachusetts, which is somewhat above our recent spending levels there. We receive timely recovery of these investments with a return. In Connecticut and New Hampshire, we have not assumed any grid mod investments at this time. As you can see on Slide 19, these investments in our core business are projected to produce a rate base CAGR of approximately 7.1% over the forecast period. Slide 20 lists the investments that are included in the 5-year estimate and what remains outside of it. Note that we continue to exclude AMI from our core capital program. As Joe indicated in his remarks, dockets to implement AMI are very active in both Massachusetts and Connecticut, and may be concluded later this year. However, they are not yet at the point where we should be including them in our capital forecasts. Altogether, implementing AMI in the 2 states would require about $1 billion of investment in order to deliver long-term customer savings, enhance grid resiliency and enable clean energy benefits. Also excluded from our 5-year forecast are certain transmission investment opportunities. ISO New England studies indicate that about $500 million of onshore investment would be needed to interconnect nearly 3,000 megawatts of offshore wind through Cape Cod in the southeastern portion of our service territory. Since the nature and timing of these investments are still under evaluation, we have excluded it from our capital guidance. I should emphasize that we would expect such projects to be incremental investments in our core regulated business. They are not related to our 3 offshore wind projects, which, as you saw in the earlier slide, connect through New York and Rhode Island. So in addition, it is also becoming clear that significant additional transmission investment beyond the $500 million will be needed to reliably tie in the 9,000 megawatts of offshore wind that Massachusetts, Connecticut and Rhode Island are targeting. These investments will extend beyond our forecast period and such are not included. They are excluded from the forecast. Finishing up my discussion on the regulated business, I'll first turn to a review of our current regulatory items. As you can see on Slide 21, we continue to await FERC's rulings on several items. The first are the 4 complaints that were filed beginning back in 2011 challenging the return on equity authorized for all the New England electric transmission owners. The others are generic dockets, one looking at the 50 basis point RTO adder and another looking at transmission incentives. On the distribution side, we are currently operating under multiyear rate plans in most of our distribution jurisdictions. CL&P's base rate freeze was approved as part of the comprehensive settlement Joe mentioned earlier. PSNH is in the second year of a multiyear rate plan. Our 2 Massachusetts natural gas delivery utilities are operating in the early years of 8- and 10-year rate plans. Yankee Gas is nearing the 4-year mark since its most recent rate review, and we are currently evaluating when its next review will take place. Therefore, our primary rate review this year will be at NSTAR Electric in Massachusetts. Slide 22 covers the key elements of the review. We filed it a month ago and expect a decision around December 1, with new rates to take effect at the beginning of 2023. There are several components to the filing and a couple of the key ones are noted on the slide. So let me pause here to summarize. We expect to deliver another very positive year performance for our customers, shareholders and all stakeholders in 2022. Our long-term earnings growth continues to be in the upper half of the 5% to 7% range through 2026 from our core regulated business. Our long-term growth rate is supported by a projected rate base growth of 7.1%. We have upside opportunities in the areas of grid modernization, AMI and incremental transmission development that are not part of our current forecast. The investments I've discussed thus far have been in our regulated business. Now I'll turn to our offshore wind partnership with Ørsted. Joe mentioned earlier, our JV with the Ørsted has signed contracts in place for about 1,760 megawatts of offshore wind, and we've locked in approximately 80% of the costs we need to bring our 3 projects into service. To date, we've invested about $1.2 billion in the JV, which includes some development and acquisition costs that are not directly related to the 3 projects. In 2022, we expect to invest an additional $900 million to $1 billion in the 3 projects. Over the remaining years of our forecast, we expect to invest an additional $3 billion to $3.6 billion to complete and bring into service all 3 projects. These estimates fully reflect certain cost increases that we've encountered over the past few months that were covered earlier in Joe's remarks, as well as our estimates of our costs going forward. Last year, we told investors that we would provide more visibility into our financial expectations for our offshore wind investments. So providing you with the range of expected -- of the expected investment levels over the next several years is part of that. And as we said before, the benefit on earnings from the large projects [ enter ] service in 2025 is not projected to be significant. However, assuming Revolution Wind and Sunrise Wind enter service in 2025, we expect offshore wind earnings to add between 6% to 8% of the net income we expect from our core regulated business in 2026. The benefit on Eversource's cash flow beginning in 2026 is likely to be much more significant. Since Eversource is currently a cash taxpayer and we expect to remain one, we expect to use investment tax credits and accelerated depreciation for tax purposes in a highly efficient and effective manner, and that's just based on today's tax code. Changes are currently being considered in Congress to spur more clean energy investment that could significantly enhance our projected cash flows and returns. Potential changes include utilization of a direct pay option, allowing an increase of tax credits to 40% for meeting certain domestic content requirements and raising production tax credits to the -- raising production tax credits to the ITC equivalent of 30%. Any of these potential changes could have significant positive implications for this business and cash flows and none of these changes is reflected in the offshore wind guidance that I noted earlier. Historically, we have guided that our offshore wind projects were expected to generate mid-teens returns, based on a standard Eversource 60-40 debt equity structure. Those returns or higher are achievable with enhanced clean energy benefits contemplated by the Build Back Better plan. But even with no changes to the current tax code, we now expect our offshore wind equity returns to be in the 11% to 13% range, so still accretive for the Eversource investor and highly supportive of our state's aggressive clean energy goals. So to summarize offshore wind, our projects are making excellent progress and continue to project in-service dates as previously forecast. We, like other developers, have very recently experienced higher costs associated with global supply chain and vendor capacity issues. But perhaps like most other U.S. developers, we have a very clear line of sight on 80% of our costs, and we continue to work closely with Ørsted to identify savings opportunities. Despite some higher costs, we continue to project offshore wind earnings that are higher than in our regulated businesses. Closing out today's call, I want to discuss our financing plans. As we've always done, we expect to finance our capital needs in a balanced way through a combination of internally generated funds, new debt issuances and common equity. We intend to maintain the existing strong credit ratings that we currently have with the rating agencies. Given the level of investments contemplated in this 5-year outlook, we are planning to add an incremental $500 million to our equity needs over the next several years. When we first discussed issuing equity 3 years ago, we outlined a multipronged plan to raise equity capital. The first $2 billion plan was comprised of $1.3 billion in block equity and $700 million through an at-the-market or ATM program. Separately, we announced that we would use about $100 million a year in treasury shares rather than open market purchases to fund our dividend reinvestment and employee stock programs. So to help fund the updated investment plan and allow us to maintain our strong financial profile and credit ratings, we are now increasing the size of our expected ATM program by $500 million, so to a total of $1.2 billion. In addition, we expect to continue to fund our dividend reinvestment and employee stock programs using treasury shares, and this is expected to be about $600 million over the next 5 years. Finally, as you can see on Slide 23, we continue to remind investors of our long track record of positive performance. This slide shows that over the decade since Eversource was created, we have consistently achieved the earnings and dividend growth we targeted even back in 2012, while achieving very strong operating performance. We also have significantly enhanced our ESG profile, which certainly ranks among the best, if not the best, in the industry. So we thank you again for joining us this morning, and I'll turn the call back to Jeff for Q&A.

Thank you, Phil. And I'm going to return it to John just to remind you how to enter questions. John?

[Operator Instructions]

Great. Thank you, John. First question this morning is from Steve Fleishman from Wolfe.

Just maybe one question. Just there's a lot of offshore wind disclosures that you gave here in the call. Is there a reason that none of this is in like the slide deck and the like? Just some color on that. It's helpful to have it, but just -- yes.

Yes. It's all included in our 10-K, Steve, that is being released today, too. So the nature of all those disclosures is included there. So the combination of the comments and the 10-K, I think, provide all the information.

Great. And then just to summarize, when I'm looking out to 2026 and thinking about the changes from the 6% to 7% regulated growth or upper half of 5% to 7%, we have in '26 an incremental 6% to 8% net income, so that -- from offshore wind. So that's take the base of the growth rate of the regulated, add 6% to 8% net income? And then my share count would basically be $500 million more of equity than we would have had previously.

Is that your question? How do you get to the calculation? Yes.

I'm just trying to kind of get to kind of thinking the pieces for -- from kind of EPS...

Yes, it's a little bit more than the 5% because what we did, we increased the -- that dividend reinvestment, about $100 million, we would -- before, it was like $100 million a year for 5 years or $500 million. Now it's about $120 million for 5 years. So it's the incremental ATM program and then $100 million more on the DRIP side.

I'm sorry. If I wanted to look at -- so just on that -- the part on the DRIP side. So my recollection is you were doing $100 million a year previously for treasury and DRIP, and now you're going to be doing how much per year?

It's just $120 million. Just...

$120 million. Okay.

Yes.

So basically, over 5 years, that's another $100 million of equity incremental. But I mean $600 million overall incremental equity.

Yes.

Okay. That's helpful. And then just -- in terms of just -- how are you feeling about the time lines on Revolution? I think there's a comment in the 10-K about that you're still analyzing those. Could you just give a little more color on that, please?

Steve, we feel very, very good. We had a good opportunity to spend some time with the Interior Secretary last Friday. We've got tremendous support down there. And all indications are that we continue to make great progress. We expect the draft environmental impact statement July of this year. And all our approvals are expected by 2023 with construction beginning shortly after that. So we don't anticipate -- although, never say never -- but things have been very, very smooth in this. I had mentioned in my prepared remarks we've accomplished more this past year than we have in the 3 previous years. So I'm very, very optimistic of the schedules.

Last question, just I assume you probably updated the rating agencies on the offshore wind capital plan and your updated financing plan. And I just want to kind of check that you expect that this should kind of keep stable ratings?

Yes. We have -- as you can imagine, Steve, we're in frequent contact with the agencies, whether they be -- whether it's on our capital spending plan, the regulatory developments in the various states, or -- and such. So we have and we will continue to keep them updated throughout this year.

Next question is from Insoo Kim from Goldman.

First question, also on offshore wind. Could you just clarify, first of all, that the total cost, I guess, of your 50%, I think I heard $1 billion in 2022 about, and another $3 billion to $3.5 billion over -- for remaining few years. Is that correct? So if I think about, what, $4.5 billion for your state, that's about $9 billion total for the entirety of the 3 different projects. So taking 1.7, 1.8 gigawatts for those reflect about $5,000 per for KW all in. Is that the right ballpark from that?

Doing the math that you just did, that's where you would get to, yes.

S Okay. And then related to that, just thinking about the new offshore wind returns of the 11% to 13% versus somewhere in that mid-teens you were talking prior, given 80% of your project costs are largely locked in, so we're talking mostly in that other 20% of costs, are those, from a timing perspective, going to mean you'll have to lock in pretty soon at these inflated levels that get your estimates to a lower level? Or do you have more time to see if potentially there's some subsiding of costs?

Yes. Thank you. Great question. So the remaining 20%, we think we have opportunities there to look -- we're not going to rush to sign a contract just to sign a contract. We are going to be thoughtful in delivering. I mean one of the things that has taken place in this offshore wind business, we were -- I was up in Albany for a foundation construction, we're onshoring it here in America. So -- there's a lot of -- the supply chain is really moving very fast. So we think the remaining 20%, there's a great opportunity here for us to have some competitive opportunities and not rush just to sign a contract for the sake of signing a contract. So the long answer to your short question is, we think we have some time for the remaining 20% and that we will remain disciplined in terms of executing any contracts.

Got it. And just one quickly, if I could. On that upper half of the 5% to 7% through '26, that embeds that investment of the offshore wind and the financing costs that are associated with that as well?

Yes, correct. Yes, during construction, we basically capitalized the interest cost to the projects, but that does embed that in there, into...

That makes sense.

Next question is from Durgesh Chopra from Evercore.

I just had one quick clarification, all my other questions were asked. On the equity, the $1.2 billion ATM and the $600 million through DRIP and others, that's for the regulated side, right, that doesn't cover your $4.5 billion roughly investment on the offshore side?

Well, the -- what we've incorporated in terms of financing incorporates what we believe is an appropriate level for our long-range outlook that we've outlined here. So it's not a plan that you set it and forget it, right, like the commercial, you put it in the oven, set it and forget it. But this is something we continuously we'll monitor. We'll look at our plan, including our financing needs, and if there are adjustments that are needed as we move through the next few years, we'll do that. But right now, that -- what I've indicated to you is to support the full investment activities that I've outlined.

Next question is from Nick Campanella from Credit Suisse.

I guess, just -- thanks for all the color on the offshore wind stuff. Just looking at the base business, O&M, combating inflation, you've done a pretty good job of keeping things flat historically. Just what's in your forecast in this 5-year plan for O&M?

In the long-range forecast, it's maintaining that same approach, in that flat to maybe up slightly as we move through, but certainly well below sort of an inflation level. We've been very good about finding efficiencies and opportunities in our processes. When we go in for rate cases, distribution rate cases, we'd like to be able to portray that costs are lower today than they were x years ago when we went in for the previous case. So we're looking to maintain that discipline on our O&M costs and keep them flattish. They might go up slightly, but in that flat to less than 1% level.

Got it. That's really helpful. And then I guess just like looking at the guide, $4 to $4.17, a $0.17 range, I think it's just a bit wider than what you've historically provided in '21 and '20. Is that just law of large numbers playing out, or are you kind of seeing higher volatility in the base businesses?

I think it's a combination. Some of it is just the numbers are bigger. And that range, if you go back 4, 5 years, it was maybe $0.10 and then it was $0.15. So it's -- as the numbers have grown, sort of the range around it has grown and -- so it's -- there's nothing to read into it other than that. And as I said, the midpoint is really in that 6% area.

Next question is from Angie Storozynski from Seaport.

I just had one follow-up on offshore wind. So you guys mentioned the 11% to 13%. Are we talking about levered IRRs? And then secondly, is there any difference in your expectations for profitability of the initial projects versus those that are coming online in '25 ?

I didn't catch the last part of your question, but the first part is the number is the return on equity. So that's -- I think Ørsted may talk about IRRs, but we've always -- for our investors, they like us to talk in terms of ROE. So it's the return on equity numbers.

Yes, the second question was, is there -- I mean, I assume that it's an average return across the 4 projects. So is there, for example, higher profitability or higher returns on the initial projects coming online and as the time goes by, as those inflation pressures increase, potentially, then those projects that come online later have lower returns?

No. The number, we've always tried to talk about it as an average portfolio, so our portfolio of the 3 projects. Just keep in mind, though, when you look at the size, South Fork is much smaller than the other 2. So by definition, just due to size, it's going to have less contribution when it comes online. But the numbers we're talking about are kind of a portfolio number.

Next question is from Sophie Karp from KeyBanc.

I have a couple of questions for you. First on the offshore wind, and just broadly speaking maybe on your CapEx program. So you have a sizable portion of it locked in, but could you discuss where you have some sensitivities to price inflation from where the pricing may be, how much is that? Is that in the escalators in some of the parts that are already locked in otherwise? Or is it all concentrated in the kind of 20% that's not locked in? Any color on that would be helpful.

Yes. I'd say essentially it's in the 20% that's not locked in that there's still discussions on certain contracts or certain projects that we're working through with our joint venture partner. But I'd say the main -- the more significant items are just the ones that haven't been done yet as opposed to anything special escalation-wise in the existing 80%.

Got it. And my second question was on the kind of surprise energy bills that people are seeing. Some of your peers in the Northeast have been in the press lately, with their customers who have [ given ] surprise bills on the energy component predominantly, right? And that creates potentially political overhangs for this for your peers. What are you seeing in your territory? Because you're pretty far north, and I know historically has been -- it could have been an issue. What are you seeing this winter and how you guys plan to [indiscernible] that situation if it arises?

Yes. So we get out in front of this in the fall. We spent a lot of time with our regulators, with the administrations, with the governors, to kind of alert our customers of this volatility in the marketplace. I think -- I will tell you it was well received by all of our regulators and key stakeholders. I think we do a very good job around hedging. And I think that we've secured an awful lot. So the shocks that I think some folks are seeing. I mean, it's certainly -- our customers -- although it's -- you never like to have an increase, I think that they understood, and they were able to prepare and plan for it. We did a lot of outbound thing to get our customers to look around, some -- to do some budget billing, so it allows them to kind of spread it out and take some of the peaks off, and I think that went a long way. And obviously we spent a lot of time around energy efficiency. So I think all of those drivers, no one likes to see a bill increase, but I think if you inform customers and they understand it's coming, they're able to properly prepare for it.

Next question is from Julien from Bank of America.

Just wanted to follow up in brief here. I'm just reconciling the percentages that you talked about a moment ago. On the 6% to 8% additive, say, by '26 here, it seems like that implies something in the order of magnitude of like $140-ish million of net income. I just want to reconcile that against the total quantum of CapEx that you all are contemplating investing, right? If you think about a ballpark number, like $5.5 billion of CapEx, what kind of equity ratio and ROE are you trying to back into it? Because if I look at 12% ROE and, say, a 40% equity ratio, it looks like it might be the mid-$200 millions of net income. So I just want to reconcile like what approach we should be taking. Are you employing more leverage in the offshore effort here, and that's how you get the ROE a little higher here? Or just how does that math tie between the 2 approaches? I'm sorry to go back on the call here.

Yes. No, no, that's a great question. And certainly, you are -- your estimate of 2026 offshore wind would be based on your estimate of where we're going to be in terms of the base core business, right? Because assuming whatever growth assumption you use within our guidance for what our net income will be in 2026, that's going to trigger your 6% to 8% calculation. So that could be higher than the number that you've thrown out there, but it's certainly your calculation. There could be slightly better leverage contribution as we look out around the edges of the offshore wind capital structure versus the regulated business capital structure. As we get approval for the regulated business capital structure, there's also more beneficial tax benefits on the offshore wind side that enable accelerated depreciation makers, depreciation. We're able to take that and use that efficiently given our tax profile. So those are just some of the things.

Got it. And just to clarify that super quick. The 5% to 7% in the upper half, that applies through '26, right? Just to make sure I heard you right on that. And then the -- if I can, just to clarify the tax piece of it because you brought it up there a second ago. How are you thinking about electing it, right? I mean given the higher [indiscernible] seems like that might be beneficial for an ITC versus a PTC election here. Can you talk about the ITC election decision? And then what's the amortization period for that potentially, to calculate that ROE? I think that might be the -- when do you have a discrepancy [indiscernible]

It could be. And certainly, those tax items are kind of evolving, Julien, as you can imagine. So there could be some -- if that there's going to be benefits from a clean energy bill, maybe it's called Build Back Better or something like that, that could enhance the PTC rate. So I think that's an issue that we're -- we, ourselves and our models have run it different ways. And I think that it will become a lot clearer probably in the next 12 months, what would be the best approach. But certainly, it's something that is a consideration.

Got it. But the baseline ITC amortization period, I know we've talked about this in the past, do you have a sense of what that would be if you ended up electing that?

Yes. Typically, it's over the life of the asset.

Our next question is from Andrew Weisel from Scotia.

First, a question on the dividends. How are you thinking about the pace of growth relative to consolidated earnings versus regulated earnings? In other words, should we expect 6% growth in the dividend through 2026? Maybe something higher since you're expecting the upper half of the range, maybe higher because of offshore? Or could it be something lighter given the capital needs to finance all the CapEx?

Our guidance is that we expect our dividend growth to be in line with our overall Eversource earnings growth. So $0.005 or $0.01 on a dividend could make it a point something it makes a difference. But we've consistently been in that range. We've grown the dividend in line and maybe just slightly higher even than the earnings growth of Eversource. So that's the outlook that we would take going forward.

Okay. But it was 5.7% most recently, right? That's a little below the midpoint? Was there anything behind that?

That's what I was just trying to say is that you put another $0.01 on $0.14, it brings it up to 6.2%. I mean traditionally, we've kept our dividend. We've had a few years at one rate, we had it a few years of $0.12, and a few years at $0.13. So we decided to just keep it 2 years at the $0.14. It's 5.8%, another $0.01 would have moved it over. So do you raise it a $0.005 to get it to exactly 6%? But overall, when you look at 2 or 3 years, when you look at the trend, it's very consistent with our earnings growth.

Okay. Makes sense. Yes, I'll try not to obsess over rounding. One other question. This might just be the math of it, but the rate base CAGR, I believe it was 8.0%. Now it's 7.1%. That caught my eye, especially with the big increase to the CapEx plan. I think it was 6.5% increase with the roll forward. How do we reconcile that? Is that just a higher rate -- the higher base starting point.

Yes, it is. And if you recall, last year, it was, I'd say, maybe unusually high in the sense that we added the Eversource Gas of Massachusetts, the assets that we purchased from NiSource. So in the previous 5-year rate base growth, it was kind of 0 in there for that. And then we put -- then we're adding a whole company to the CapEx plan. So just the math of it. Now we have that EGMA in the base, so the growth is -- reflects that.

Next question is from David Arcaro from Morgan Stanley.

I was wondering -- I appreciate all the disclosure around offshore wind and the net income contribution in 2026 -- I was wondering if you could just characterize how much of a run rate level that might be? In other words, is that going to be -- or maybe talk about some elements of how it could be lumpy beyond 2026? Or is that going to be a fairly steady level to look for over the course of the contract.

Well, David, our guidance goes through 2026. So I'll preface my answer by saying it that way. What -- it shouldn't be lumpy. There are certain -- there are certain maybe tax items in particular years that could move things around a little bit. And I think, to a previous question that was asked, we're still finalizing sort of what the appropriate tax election would be. So I mean, that could make it a little bit lumpy in some years. One of our contracts has an escalator in it, that would vote towards improving that run rate going forward. Once the projects go into service, the biggest cost that you're going -- out the door is sort of O&M cost. And we think we would have some opportunities to enhance that. We have a vessel strategy lined up for that O&M activity. So we think that that could actually improve the years following, et cetera. And certainly, if you have other tax changes going forward, that's not even considering if there's more tax implications. But I think tax items might be one of the things that moves the numbers around a little bit more than others.

Got it. That's helpful color. Then maybe on the regulatory CapEx side of things, I was wondering, did you mention that there could be more incremental utility scale solar in Massachusetts and would that be further upside to the plan? Wondering if there's any potential size or scale or quantification you might be able to provide around that? And then also a similar vein, just with the transmission in New England, the onshore transmission piece of bringing offshore wind into the system, the $500 million that you mentioned, is there any preference for Eversource to build that given it's in your service territory, or is that going to be kind of spread around New England transmission owners potentially?

Well, I'll start with the last one, because there is a preference. We believe that we're the premier transmission builder in the region. Our track record speaks for itself in our ability to plan projects, to work closely with ISO to get them in service, on time and below budget. And just the competitive process that the ISO ran for a power plant that was retiring in Everett, Massachusetts, would demonstrate that, that we're able to come up with the most creative solutions in the most cost-effective way and get them done on or ahead of schedule and below budget. So we definitely believe that we're a leading candidate to provide that type of transmission build. So just to continue with transmission, there's kind of 2 components that's not in the forecast -- that are not in the forecast. One is sort of the immediate this $500 million that's in the forecast period that has been identified for existing contracts. And even though we, on our development side, haven't won the contracts, there's regulated transmission that's needed, there's transmission build that's needed in our service territory in Cape Cod because the landing area for a lot of that is there. So we're working on some of those activities right now but did not put anything into the forecast. So that would be upside. And I would expect that you'll see that we will have upside in that -- this $500 million range. In addition to that, the states are looking for more than the current offshore wind, increasing to 9,000 megawatts. There's going to be a need for even more incremental capacity. And that cost is going to be probably higher in that the early years, you're using up some of the excess capacity or some of the existing, but when you start to now look for 9,000 megawatts more, that's going to require more significant build-out to the interconnection points. That, if it comes -- it would be near the end of our forecast, but then that would extend for many years beyond. So that's more of a longer-term optionality for the company. In terms of rate-based solar, we're -- in our plan, we don't think right now there's opportunity to increase our 5-year forecast. There could be opportunities beyond that. We feel to build the 280 megawatts that we've identified for -- that's in our plan, that it's going to take us throughout our forecast period to do that. We can revisit whether incremental build would be available beyond that time period. But right now, that's all that's in the forecast.

Next question is from Paul Patterson from Glenrock.

Just -- sorry to sort of go back to offshore wind, but just I want to make sure I've got the numbers correct. I'm sort of calculating, including what you guys have invested today, a total number now of $4.3 billion to $5.8 billion. Is that correct? And is that 11% to 13% ROE based on essentially 40% of that, roughly speaking? So are those the numbers?

Yes. Some of the numbers would include development costs that are not associated with the projects. So there's some work done on unused lease areas that we would allocate to future projects.

Okay. So I guess what I'm -- okay. So that's why I'm sort of -- so is the 11% to 13% associated with the 3.9% to 4.6%? Or is it a number higher? I guess it goes back to sort of it's not -- it's not completely clear, I guess, to me, and I apologize for this, but just following along, I just -- what's the 11% to 13% based on? What's the total CapEx that's based on that? And I guess that's 40% of that, that's roughly speaking, what you guys have [indiscernible]

It would be that the first number you said, 4.5%, 5% -- the total number. So we've already invested some through 2020 -- through the end of 2021. That's about $1.2 billion. But what I was saying is some of those costs in the $1.2 billion we've invested to date is for work on our unused leased area for future development. So the project costs are slightly below that number. And then we're looking to spend -- invest $900 million to $1 billion in 2022 and $3 billion to $3.6 billion over the forecast period. So those -- adding those up you get like 4.7%, 5.4%, in that range for the total project cost.

Okay. Great. And then just on the Massachusetts legislation, the Baker bill that you mentioned, it wasn't -- I apologize, but what is the -- what do you think the potential impact of that legislation might be? Could you clarify that?

Sure. Paul, it's Joe. So as you know, Massachusetts had a provision in the legislation that allowed -- it didn't allow any future bids to be any higher than the previous bid. And that obviously really hampered the marketplace in the bids, and so that's why the last RFP ended up with only 2 bidders because -- it just wasn't -- it wasn't productive. You look at other states like Connecticut, you look at New York, where they introduced the idea around economic development and other factors. It's not strictly price. And I think that Governor Baker, he recognized the fact that he was having an adverse impact on the potential group of bidders that could participate. So he is removing that cap. He's also encouraging economic development, and I think he sees all the benefits that states like Connecticut, states like New York and Rhode Island have witnessed with serious investments in the kind of supply chain around offshore wind. So that legislation is going to -- basically, it's going to remove the cap and allow a much more vibrant RFP process and bidding process.

Okay. My rest of the questions, I think, have been answered.

Next question is from Jeremy Tonet from JPMorgan.

This is actually Ryan on for Jeremy. Just one maybe mechanical one on the schedule. Can you just remind us on the Dominion vessel and the availability there, and what are the logistics on utilizing that?

Sure. We are the first customer for that vessel. The team was down to Texas. They saw the construction underway. They're making significant progress. Dominion is very confident that the ship will be delivered to us on time. It was scheduled to be completed in 2023. As you know, our schedule, it really begins construction in 2024. So we feel very, very good about that. If the vehicle -- if the vessel is delayed, we have a day for day carry on that. So it will just move forward and allow us to utilize it for the period of time that we need for those 2 projects.

Got it. Makes sense. And then one on Connecticut -- and appreciate all of the positive updates there -- but I know you guys kind of -- and it's still early stages, but this performance-based rates kind of proceeding that's in early stages, any kind of expectations there, how you think this might evolve over time in kind of changing the regulatory landscape?

I mean I think if you look at Eversource in the states where we do have performance-based rates here, in Massachusetts we've performed very, very well. We were probably one of the early adopters of that in this state. So we feel very confident about it. We're going to play an active role, obviously, in any proceeding around performance-based rates. But I think if you look at our record, you look at our performance, as I had mentioned, what we did in 2021 and what the team did was extraordinary. I think that all of our metrics, I think we hit the ball out of the park. And so we feel very, very good about it. And we'll play an active role, and we do very, very well in environments where there is performance-based rates.

Got it. Very helpful.

Next question is from Steve Fleishman from Wolfe.

I had one clarification question. I appreciate it. The -- wanted to -- I believe your 5% to 7% growth rate has included the $1 billion -- the prior $1.2 billion of equity that was in your plan. And I wanted to clarify whether the updated 5% to 7% growth rate includes the full $1.8 billion of equity in that.

Yes, it does, Steve. It does. It will include...

Okay. So essentially, the offshore wind net income benefit would all be net income without any more share count beyond what's the shares that are already embedded in your core growth rate funding?

Yes. Well, the core growth rate, when I say the shares are included in the core growth rate, those shares, or the plans for issuing equity, covers sort of our investments that we are planning to make over the 5-year period. We could, depending on what the plan looks like, if we have additional transmission investment, if the timing of certain offshore wind spend, if we move forward with AMI, we're certainly going to have to look at that CapEx and investment plan and make adjustments. But that is the plan at this stage for the foreseeable future.

That's good. And just any sense on kind of the pace of the equity issuance? I guess it would just be the ATM part of it?

It's hard to say. The nature of an ATM is to be opportunistic in the marketplace. But I would think that we're looking to do that over the next few years type of issuance.

All right. Folks, thank you very much. We don't have any more questions in the queue. If you have any follow-ups, please give us a call or send us an e-mail. And have a great rest of your day.

Thank you, ladies and gentlemen. That concludes today's conference. Thank you for participating, and you may now disconnect.