Welcome to the Eversource Energy 2021 year-end results conference call. My name is John. I'll be your operator for today's call. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session. During the question-and-answer session, if you do have a question, press star then one on your touch-tone phone. Please note the conference is being recorded. Now I'll 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. As you can see on slide one, 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 31st, 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 three 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 five-year forecast. We accomplished a great deal in 2021, as you can see on slide four. 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 five in operations, you can see that our electric service reliability and restoration performance were top decile and top quartile, respectively.
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 three states. We also continue to refine our emergency response efforts, which were on display again just two and a half weeks ago when a weekend blizzard clobbered southeastern Massachusetts with hurricane-force winds and snow depths up to 2.5 ft . 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 two days. Most of our storm damage was power-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 six, you can see that despite strong results, we, like many other high-performing utilities, underperformed both our peers in 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 5%-7% range. That earnings growth has enabled us to achieve attractive long-term dividend growth as well. As you can see on slide seven, 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 60s 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 eight.
Our offshore wind business had more positive developments over the past 13 months than we experienced over the previous three years combined. Last week, as you can see on the slide, New York Governor Hochul joined in breaking ground in 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 MW 12-turbine project will connect into Long Island Power Authority grid, 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 two much larger projects, Revolution Wind and Sunrise Wind.
As you can see on slide nine, we are well into the federal and state siting process for both projects. Last year, the Bureau of Ocean Energy Management set schedules for review of those two 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 three projects. We have 80% of the cost 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 two 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 two 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 improvement 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 Ørsted are funding a $200 million project to create an important staging area for offshore wind construction, including our South Fork Wind, Revolution Wind, and Sunrise Wind projects. It is probably the best site for this work between Norfolk, Virginia, and Halifax, Nova Scotia, and only 60-65 mi from our nearest turbine locations. As you can see on slide 11, the Connecticut Port Authority commenced onshore work last summer. 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 sq mi area, where we and Ørsted expect to build projects with at least 4,000 MW 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 two 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 pre-qualified 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 five 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 one and scope two 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 three-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 sq ft 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 and 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 policymakers. 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 2021 and January 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. This morning, I'm going to cover several areas. Our 2021 results, our 2022 earnings guidance, an update, an updated five-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. 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 Q4 of 2021, GAAP earnings were $0.89 per share, compared with GAAP earnings of $0.79 in the Q4 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 Q3 call, 2021 full-year results also include charges related to the settlement agreement in Connecticut. Excluding those non-recurring charges, we earned $3.86 per share in 2021. That's up 6% from $3.64 in 2020. For the Q4 , excluding these charges, we earned $0.91 per share in 2021, compared with earnings of $0.85 in the Q4 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. That's compared to just about $960 million, $964 to be precise, in 2020. That's 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. This compared to $1.60 in 2020. The higher revenues were largely offset by higher O&M, depreciation, property tax, and interest expense. 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 three 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 2021, 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 cost 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%-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. 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 systems safer, more reliable, and more resilient for our customers. We expect to invest approximately $18.1 billion in those systems over the five-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 five 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 five-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 forecast. Altogether, implementing AMI in the two 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 five-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 MW 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 three offshore wind projects, which as you saw in the earlier slide, connect through New York and Rhode Island. 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 MW 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 of the four 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 multi-year 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 currently in the second year of a multi-year rate plan. Our two Massachusetts natural gas delivery utilities are operating in the early years of eight- and 10-year rate plans.
Yankee Gas is nearing the four-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 1st, 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. Let me pause here to summarize. We expect to deliver another very positive year of 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%-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 Ørsted has signed contracts in place for about 1,760 MW of offshore wind, and we've locked in approximately 80% of the cost we need to bring our three 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 three projects.
In 2022, we expect to invest an additional $900 million-$1 billion in the three projects. Over the remaining years of our forecast, we expect to invest an additional $3 billion-$3.6 billion to complete and bring into service all three 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 cost 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 a range of the expected investment levels over the next several years is part of that. As we said before, the benefit on earnings from the large projects into service in 2025 is not projected to be significant.
However, assuming Revolution Wind and Sunrise Wind into service in 2025, we expect offshore wind earnings to add between 6%-8% to 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. 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 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 are higher, are achievable with enhanced clean energy benefits contemplated by the Build Back Better plan. Even with no changes to the current tax code, we now expect our offshore wind equity returns to be in the 11%-13% range.
Still accretive for the Eversource investor and highly supportive of our state's aggressive clean energy goals. 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 at the rating agencies. Given the level of investments contemplated in this five-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 three years ago, we outlined a multi-pronged 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 in employee stock programs.
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 in employee stock programs using treasury shares, and this is expected to be about $600 million over the next five 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.
Thank you, Phil. I'm gonna return it to John just to remind you how to enter questions. John?
Thank you. If you do have a question, press star then one on your touch-tone phone. If you wish to remove from the, from the queue, press the pound sign or the hash key. Once again, that's star then one on your touch-tone phone.
Great. Thank you, John. First question this morning is from Steve Fleishman from Wolfe. Good morning, Steve.
Yeah. Hey, good morning. Thanks, everybody. 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. Yeah.
It's all included in our 10-K, Steve, that is being released today, too. The nature of all those disclosures is included there. The combination of the comments and, the 10-K I think provide all the information.
Great. Then just to summarize, when I'm looking out to 2026 and thinking about the changes from the 6%-7% regulated growth or upper half of 5%-7%. We have in 2026 an incremental 6%-8% net income, so that from offshore wind. That's take the base of the growth rate of the regulated, add 6%-8% net income. Then my share count would basically be $500 million more of equity than we would have had previously.
Yeah. Is that your question? How do you get to the calculation? Yes.
Yeah. I'm just trying to kind of get to kind of thinking the, you know, pieces from a kind of EPS.
Yeah. It's okay. That's maybe. Yep. It's a little bit more than the five because what we did, we increased that dividend reinvestment about $100 million. Before, it was like $100 million a year for five years or $500 million. Now it's about $120 million for five years. It's the incremental ATM program and then $100 million more on the DRIP side.
I'm sorry. If I wanted to look at. Just on that, the part on the ATM, the DRIP side. My recollection is you were doing $100 million a year.
Yes. That's right.
Previously for treasury and DRIP, and now you're gonna be doing how much per year?
It's just 120.
120. Okay.
Yeah.
Basically, over five years, that's another $100 million of equity-
Right
incremental.
Another 100. Yeah.
That means $600 million overall incremental equity.
Yes.
Okay. That's helpful. Just in terms of how are you feeling about the timelines on Revolution? I think there's a comment in the 10-K about you're still analyzing those. Could you just give a little more color on that, please?
Sure. Good morning, Steve. You know, 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, you know, all indications are that you know, we continue to make great progress. You know, we expect a draft environmental impact statement July of this year. You know, and all our approvals are expected by 2023 with construction beginning shortly after that. So we don't anticipate, you know, although, you know, never say never, but things have been very, very smooth. As I had mentioned in my prepared remarks, you know, we've accomplished more this past year than we have in the three previous years. I'm very, very optimistic and 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. I just wanna kinda check that you expect that this should kinda keep stable ratings.
Yes. We have, as you can imagine, Steve, we're in frequent contact with the agencies, you know, whether it's on our capital spending plan, you know, the regulatory developments in the various states or and such. We have, and we will continue to keep them updated throughout this year.
Great. I will let other people ask questions. Thanks so much for your time.
Thank you, Steve.
Thanks, Steve. Next question is from Insoo Kim from Goldman. Good morning, Insoo.
Hey, good morning. First question, you know, 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-$3.5 billion over the remaining few years. Is that correct? If I think about, what? $4.5 billion for your stake, that's about $9 billion total for the entirety of the three different projects. Taking, you know, 1.7, 1.8 GW for those reflect about $5,000 per kW all in. Is that the right ballpark for math?
Doing the math that you just did, that's where you would get to. Yes.
Okay. Related to that, just thinking about the new offshore wind returns of 11-13 versus somewhere in that mid-teens you were talking prior. You know, 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, something that you'll have to lock in pretty, you know, soon, at these inflated levels that, you know, get your estimates to a lower level, or do you have more time to see if potentially there's some subsiding of costs?
Yeah. Good morning. Thank you. Well, you know, great question. You know, the remaining 20%, you know, we think we have opportunities there to look. We're not gonna rush to sign a contract just to sign a contract. You know, we are gonna be thoughtful and deliberate. I mean, one of the things that has taken place in this offshore wind business, you know, I was up in Albany for a foundation construction. We're onshoring it here in America.
There's a lot of the supply chain is really moving very fast. 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. 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. Just one quickly, if I could, on that upper half of the five-seven through 2026, that embeds, you know, that investment of the offshore wind and the financing costs that are associated with that as well?
Yes. Correct. Yes. During construction, you know, we basically capitalize the interest cost to the projects, but that does embed that in there into.
Oh, right. That makes sense. Thank you so much.
Thank you.
Thanks, Insoo. Next question is from Durgesh Chopra from Evercore ISI. Good morning, Durgesh.
Hey. Good morning, Jeff. 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, you know, your $4.5 billion roughly investment on the offshore side.
Well, what we've incorporated in terms of financing incorporates what we believe is an appropriate level, you know, for our long range outlook that we've outlined here. You know, it's not a plan that you set it and forget it, right? Like the commercial, you put it in the oven and set it and forget it. This is something we continuously will monitor. We'll look at our plan, including our financing needs. If there are adjustments that are needed as we move through the next few years, we'll do that. Right now what I've indicated to you is to support the full investment activities that I've outlined.
Got it. Thanks. That's all I had, guys. Thank you.
All right. Thank you, Durgesh. Next question is from Nick Campanella from Credit Suisse. Welcome to our call, Nick.
Hey. Thanks a lot, everyone. Really appreciate the time. I guess just, you know, thanks for all the color on the offshore wind stuff. Just looking at the base business, you know, O&M, combating inflation, you've done a pretty good job of keeping things flat historically. Just what's in your forecast in this five-year plan for O&M?
In the long range forecast, it's maintaining that same approach, you know, in that flat to maybe up slightly as we move through. Certainly well below sort of an inflation level. You know, we've been very good about finding efficiencies and opportunities in our processes. You know, when we go in for rate cases, distribution rate cases, you know, we'd like to be able to portray that costs are lower today than they were, you know, X years ago when we went in for the previous case. We're looking to maintain that discipline on our O&M costs and keep them flattish. They might, you know, go up slightly, but in that flat to less than 1% level.
Got it. That's really helpful. Then I guess just, like, looking at the guide, $4-$4.17, it's $0.17 range, I think it's just a bit wider than what you've historically provided in 2021 and in 2020. You know, is that just law of large numbers playing out, or are you kind of seeing higher, you know, volatility in the base businesses?
I think it's a combination. You know, some of it is just the numbers are bigger. And that range, if you go back, you know, four or five years, it was, you know, maybe $0.10, and then it was $0.15. It's. As the numbers have grown, sort of the range around it has grown. There's nothing to read into it other than that. As I said, the midpoint is really in that 6% area.
Thanks a lot.
All right. Thank you, Nick. Next question's from Angie Storozynski from Seaport. Good morning, Angie.
Good morning. I just had one follow-up on offshore wind. You guys mentioned the 11%-13%. Are we talking about levered IRRs? And then secondly, is there any difference in your expectations for profitability of the initial project versus those that are coming online in 2025?
I didn't catch the last part of your question, but the first part is the number is a return on equity. That's, you know, I think Ørsted may talk about IRRs, but, you know, we've always, you know, for our investor, investors, they like us to talk in terms of ROE. It's the return on equity numbers. What was the second part?
Yeah. The second question was, is there, I mean, I assume that it's an average return across the four projects. Is there, for example, higher profitability or higher returns on the initial, you know, projects coming online? As the time goes by, as those, you know, inflation pressures increase potentially, then, you know, 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 three projects. You know, just keep in mind, though, when you look at the size, South Fork is, you know, much smaller than the other two. You know, by definition, just due to size, it's gonna have a less contribution when it comes online. The numbers we're talking about are kind of a portfolio number.
Very good. Thank you.
Thank you, Angie. Next question's from Sophie Karp from KeyBanc. Good morning, Sophie.
Hi. Good morning, guys. Thank you for taking my question. I have a couple of questions for you. It's first on the offshore wind, and just broadly speaking maybe on your CapEx program. You have a sizable portion of it locked in, but could you discuss where you still have some sensitivity to price inflation from either pricing? Maybe 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.
Yeah. I'd say, essentially it's in the 20% that's not locked in. You know, that there's still discussions on certain contracts for certain projects that you know, we're working through with our joint venture partner. I'd say, you know, 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. Thank you. My second question was on the kind of surprise energy bills that people are receiving. Some of your peers in the Northeast have been in the press lately with their customers receiving surprise bills on the energy component predominantly, right? That creates potentially political overhangs for your peers. What are you seeing in your territory? Because you're pretty far north, and I know historically it could have been an issue. What are you seeing this winter, and how are you guys planning to address that situation if it arises?
Yeah, you know, 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, you know, alert our customers of this volatility in the marketplace. You know, I think I will tell you it was well received by all of our, you know, regulators and key stakeholders. I think we do a very good job in and around hedging, and I think that we had secured an awful lot. The shocks that I think some folks are seeing, I mean, it's certainly, you know, our customers, you know, although it's, you never like to have an increase. I do think that they understood, and they were able to prepare and plan for it.
You know, we did a lot of outbound calling to get our customers to look around to do some budget billing, so it allows them to kind of spread it out and take some of the peaks off. I think that went a long way. Obviously, you know, we spend a lot of time around energy efficiency. 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.
Terrific. Thank you.
Thank you, Sophie. Next question is from Julien from Bank of America. Good morning, Julien.
Hey, good morning, team. Thanks for the opportunity to connect. Just wanted to follow up, in brief here. I'm just reconciling the percentages that you talked about a moment ago. On the 6%-8% additive, say by 2026 here, 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 here, right? If you think about a, you know, a ballpark number of, 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% ROEs and, say, a 40% equity ratio, it looks like it might be, you know, the mid-200s of net income. 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 two approaches? I'm sorry to go back on the call here.
Yeah, no. That's a great question. Certainly, you know, your estimate of 2026 offshore wind would be based on your estimate of, you know, where we're gonna be in terms of the base core business, right? Because assuming, you know, whatever growth assumption you use within our guidance for what our net income will be in 2026, that could, that's gonna trigger, you know, your 6%-8% calculation. You know, that could be higher than the number that you've thrown out there, but that's certainly your calculation. There could be slightly better leverage contribution, you know, as we look out around the edges of the offshore wind capital structure versus the regulated business capital structure.
You know, as we, you know, we get approval for the regulated business capital structure, is also, you know, more beneficial tax benefits on the offshore wind side, that enable accelerated depreciation, MACRS depreciation. We're able to take that and use that efficiently given our tax profile. So those are just some of the things, you know. Yeah.
Got it.
Yeah.
Got it. Just to clarify that super quick. Is the five-seven in the upper half, that applies through 2026, right? Just to make sure I heard you right on that.
Yeah
This, if I can just to clarify the tax piece of it, 'cause you brought it up there a second ago. How are you thinking about electing it, right? I mean, given the higher like that might be beneficial for an ITC versus a PTC election here. Can you talk about the ITC election decision? Then w hat's the amortization period for that potential to calculate that ROE? I think that might be one of the other discrepancies in the-
It could be. Certainly, you know, those tax items are kind of evolving, Julien, as you can imagine. You know, there could be some, you know, if that, there's going to be benefits from a clean energy bill, maybe it's called Build Back Better or something like that could enhance the PTC rate. I think that's an issue that we ourselves in our models have run it different ways. I think that it'll become a lot clearer probably in the next 12 months, you know, what would be the best approach. Certainly, you know, it's something that is a consideration.
Got it. A 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 liking that?
Yeah. Typically, it's over the life of the asset.
Okay. Sorry. Thank you very much for the patience.
Yeah, no problem. Thank you.
All right. Thank you, Julien. Our next question is from Andrew Weisel from Scotia. Good morning, Andrew.
Hi, good morning, everybody. 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. A half a penny or a penny on a dividend may could make it a point something. It makes a difference. 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. That's the outlook that we would take going forward.
Okay. 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 know, you put another penny on 14, it brings it up to 6.2%. I mean, you know, traditionally, we've kept our dividend, you know, we've had a few years at one rate. You know, we had it a few years at $0.12 and a few years at $0.13. So, you know, we decided to just keep it two years at the $0.14. It's 5.8%. Another penny would have moved it over. So it. Do you raise it a half a penny to get it to exactly 6%? But overall, it, when you look at two or three years, you know, when you look at the trend, it's very consistent with our earnings growth.
Okay. Makes sense. Yeah, I'll try not to obsess over rounding. One other question. This might just be the math of it, but the rate-based 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. 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, you know, NiSource. In the previous five-year rate-based growth, there was kind of zero in there for that. Then we're adding a whole company to the CapEx plan. The growth is, you know, reflects that.
That makes sense. Thank you very much.
You're welcome.
Thanks, Andrew. Next question is from David Arcaro from Morgan Stanley. Good morning, David.
Hey, good morning. Thanks for taking my question. 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, you know, is that gonna be, or maybe talk about some elements of how it could be lumpy beyond 2026, or is that gonna be a fairly steady level to look for over the course of the contract? Thanks.
Well, David, you know, our guidance goes through 2026. I'll preface my answer by saying it that way. You know, it shouldn't be lumpy. You know, there are certain, you know, maybe tax items in particular years that could move things around a little bit. And I think to a previous question that was asked, you know, we're still finalizing sort of what the appropriate tax election would be. I mean, that could make it a little bit lumpy at some years. You know, one of our contracts has an escalator in it, that could, you know, that would vote towards improving that run rate going forward.
You know, once the projects go into service, the biggest cost that you're going, you know, out the door is sort of O&M costs. We think we would have some opportunities to, you know, enhance that. You know, we have a vessel strategy lined up for that, O&M activity. We think that that could actually improve you know, the years following, et cetera. You know, certainly if you have other tax changes, you know, going forward, that's not even considering if there's more tax implications. I think, you know, 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. 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. Also in 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 gonna be kinda spread around New England transmission owners potentially? Thanks.
Well, I'll start with the last one because there is a preference. You know, 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. Just the competitive process that the ISO ran for a power plant that was retiring in Everett, Massachusetts would demonstrate 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. We definitely believe that we're a leading candidate to provide that type of transmission build. Just to go...
To continue with transmission, there's kinda two components that's not in the forecast or that are not in the forecast. One is sort of the immediate, that's $500 million that's in the forecast period that has been identified for existing contracts. 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. We're working, you know, on some of those activities right now, but did not put anything into the forecast. That would be upside, and I would expect that you'll see that we will have upside in that, this $500 million range.
You know, in addition to that, the states are looking for more than the current offshore wind, you know, increasing to 9,000, you know, MW. There's going to be a need for even more incremental capacity. That cost is going to be probably higher in that, you know, the early years, you're using up some of the excess capacity or, you know, some of the existing, but when you start to now look for 9,000 MW more, that's going to require more significant build out, you know, to the interconnection points. That, you know, if it comes at, it would be near the end of our forecast but then that would extend for many years beyond. That's more of a longer term optionality for the company.
In terms of rate-based solar, you know, we're in our plan. We don't think right now there's opportunity to increase our five-year forecast. There could be opportunities beyond that. You know, we feel to build the 280 MW that we've identified for, you know, that's in our plan, that it's going to take us, you know, throughout that, our forecast period to do that. We can revisit whether incremental build would be available beyond that time period. Right now, that's all that's, you know, that's in the forecast.
Okay, great. That makes sense. Thanks.
All right. Thank you, David. Next question's from Paul Patterson from Glenrock. Good morning, Paul.
Hey, good morning, guys.
Hey, Paul.
Sorry to sort of go back to offshore wind, but I wanna make sure I've got the numbers correct. I'm sort of calculating, including what you guys have invested to date, a total number now of $4.3 billion-$5.8 billion. Is that correct? And is that 11%-13% ROE based on essentially 40% of that, roughly speaking? That's sort of the numbers? Are those the numbers?
Yeah. Some of the numbers would include development costs that are not associated with the projects. You know, there's some work done on unused lease areas that you know, we would allocate to future projects.
I guess that's why I'm sort of... Is 11%-13% associated with the 3.9-4.6, or is it a higher number? I guess it goes back to sort of the stock. It's not completely clear, I guess, to me, and I apologize for this, but just following along, I just... What's 11%-13% based on, I guess? What's the total CapEx that's based on that? I guess that's 40% of that's roughly speaking what you guys have.
Yeah.
Does that sound good?
It would be the first number you said, you know, 4.5, you know, five, you know, the total number. 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 or for future development. The project costs are slightly, you know, below that number. Then we're looking to spend, invest $900 million-$1 billion in 2022 and $3 billion-$3.6 billion over the forecast period.
Those, you know, adding those up, you know, $4.7-$5.4 in that range for the total project cost.
Okay, great. Just on the Massachusetts legislation, the Baker bill that you mentioned, I apologize, but what do you think the potential impact of that legislation might be? Could you clarify that?
Sure. Boy, Paul, Joe. You know, 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. That obviously really hampered the marketplace and the bids. That's why the last RFP ended up with only two bidders because it just wasn't productive. You know, 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.
I think that Governor Baker he recognized the fact that you know he was having an adverse impact on the potential group of bidders that could participate. He is removing that cap. He's also encouraging economic development. 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. That legislation is gonna basically 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. Thanks so much. Have a good one.
Thank you.
Thanks, Paul. Next question's from Jeremy Tonet from J.P. Morgan.
Hi, good morning. This is actually Ryan on for Jeremy. Thanks for the question.
Sorry.
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, you know, we are the first customer for that vessel. The team was down to Texas. They saw the construction underway. They're making significant progress. You know, Dominion Energy's 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 really beginning construction in 2024, so we feel very, very good, you know about that. If, you know, if the vessel's delayed, you know, 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 two projects.
Got it. Makes sense. Just one on Connecticut, and I appreciate all the kind of positive updates there. I know you guys kind of and it's still early stages, but this performance-based rates kind of proceeding that's you know in early stages. Any kind of expectations there how you know you think this kinda might evolve over time in the kind of changing the regulatory landscape?
Yeah, I mean, I think if you look at Eversource in the states where we do have performance-based rates here in Massachusetts, you know, we perform very, very well. You know, we were probably one of the early adopters of that in this state. You know, we feel very confident about it. You know, we're gonna 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, you know, as I had mentioned, you know, what we did in 2021 and what the team did was extraordinary. I think that, you know, all of our metrics, I think we hit the ball out of the park, and so we feel very, very good about it. You know, we'll play an active role when we do very, very well in environments where there is performance-based rates.
Got it. Very helpful. Thank you for taking my questions.
Yeah. Thank you.
Thanks, Ryan. Next question's from Steve Fleishman from Wolfe.
Yeah, thanks. I had one clarification question. Appreciate it. I believe your 5%-7% growth rate has included the billion the prior billion two of equity that was in your plan, and I wanted to clarify whether the updated 5%-7% growth rate includes the full $1.8 billion of equity in that?
Yes, it does, Steve. It does.
Okay.
It's all included.
Okay. 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.
Yeah. 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 five-year period. You know, we could, depending on, you know, what the plan looks like, if we have additional transmission investment, if the timing of certain offshore wind spend, you know, if we move forward with AMI, we're certainly gonna 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. 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, you know, we're looking to do that over the next few years, you know, type of issuance.
Yeah. Great. Thank you.
Thanks, Steve.
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 email. 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.