Eversource Energy (D/B/A)

Good morning and welcome to the Eversource Energy fourth quarter and year end 2020 results conference. My name is Brandon and I'll be our operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session during which you may dial star 1 if you have a question. Please note this conference is being recorded and I will now turn it over to Jeffrey Kotkin. You may begin, sir.

Thank you, Brandon. 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 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. 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, 2019, and our Form 10-Q for the three months ended September 30, 2020. 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. Speaking today will be Jim Judge, our Chairman, President, and CEO, and Phil Lembo, our Executive Vice President and CFO. Also joining us today are Werner Schweiger, our EVP and Chief Operating Officer, Joe Nolan, our EVP for Strategy and Customer and Corporate Relations, John Marrera, our Treasurer and Senior VP for Finance and Regulatory, and Jay Booth, our VP and Controller. Now I will turn the slide to and turn over the call to Jim.

Thank you, Jeff, and thank you, everyone, for joining us today for our review of 2020 results and our updated long-term outlook. First, let me say I hope that all is well with you and your families after what's been a challenging year for everyone. I'll start my comments by thanking more than 9,000 Eversource Energy colleagues for their exceedingly hard work and extraordinarily difficult circumstances in 2020. Not only did they have to deal with the first pandemic to strike the country in more than a century, but they also had to address the highest level of storm activity ever for our company, as well as the hottest summer on record in large parts of our service territory. Through it all, they worked safely and professionally, keeping their fellow workers and our customers first in mind. As you can see in slide four, despite 107 major and minor storms that struck our service territory in 2020, We successfully executed our $3 billion capital program. These expenditures are critical to enhance the resilience of our energy and water delivery systems, as well as to connect new customers and to support state clean energy initiatives. 2020 was also a year during which we advanced a number of our strategic initiatives. At the end of February, we executed an agreement with NYSOS to buy its Columbia Gas of Massachusetts assets. And we closed on that acquisition in early October, just seven months later. The acquisition added about 5% to our regulated business, and it's been extremely well received by state policymakers and by the more than 330,000 customers that Eversource Gas Company of Massachusetts now serves. We continue to expect the transaction to be accretive in 2021. It's progressively more accretive in the years ahead. as we steadily increase our level of investment in the Eversource gas system. Phil will profile some of these investments shortly. Over the past 12 months, we've also moved ahead on the permitting of our three offshore wind projects, and we are developing strategies to meet our industry-leading target of achieving carbon neutrality by 2030. On the financial side, we achieved balanced outcomes in rate cases affecting our two operating companies that have struggled in recent years to earn their allowed returns. And we also maintained our track record, dating back to the 2012 merger that created Eversource, of posting attractive earnings and dividend growth. Turning to slide five, you can see some of the very solid operating metrics that we achieved in 2020. Despite the unprecedented challenges of COVID and incessant storm activity, I am extremely proud of the operating record our employees achieved on behalf of our customers. Slide six illustrates what we're able to achieve on behalf of our shareholders. 2020 was far from the best year for utilities, as you know, but we were able to achieve a 4.5% total return for our shareholders, keeping us in the top tier of our EEI peers in the short, medium, and long-term. Medium and longer-term returns also compare favorably to the S&P 500. A key element in achieving that long-term return record is our steady and attractive dividend growth. As you can see on slide seven, last week, the Eversource Board increased the quarterly dividend by approximately 6.2 percent. You can also see that our payout ratio remains at about 62 percent a relatively conservative level that allows about $500 million of our earnings to be invested in our delivery systems each year. We continue to target dividend growth to be in line with earnings growth, which continued in 2020 at a roughly 6 percent pace. As you can see on slide eight, we expect that growth rate to be enhanced in the coming years by our Eversource gas acquisition and our offshore wind investments. The math associated with the acquisition is quite straightforward. Adding Eversource gas increased our total regulated rate base by about 5%. And to finance it, we only added about 1.8% to our outstanding share count. Since we already operate natural gas and electric utilities adjacent to the Eversource gas service territory, there are considerable opportunities to bring our high level of service and strong safety culture to our newest customers. Phil will discuss the impact on our capital program in a moment. I'll now turn to our long-term strategy of being the principal catalyst for greenhouse gas reductions in New England. Slide 9 shows how far we as a company have come over the past 30 years as we have divested all of our fossil generation, continued to reduce methane leaks from our distribution system, and taken other steps to improve the efficiency of our delivery systems, our facilities, and our vehicles. This has enabled us to be in sync with all the states of New England, which are targeting greenhouse gas reductions within their borders of at least 80% of the year 2050. Our long-term strategy is built around being a principal enabler of that reduction. While our company operations are not a significant contributor to our state's greenhouse gas emissions today, We have set a goal of driving our direct emissions to net zero. The left side of slide 10 highlights our five primary areas of focus in that effort. More significant to the region are the items on the right side. Over their lifetime, the more than $500 million that we invested in customers' energy efficiency initiatives in 2019 alone will reduce greenhouse gas emissions by 3.2 million metric tons. Efforts to significantly expand our zero-emissions vehicle charging infrastructure and reduce the number of homes heated with oil offer very significant additional opportunities to reduce the region's emissions. But the most significant initiative we have underway is our partnership with OSTED that we expect to result in at least 4,000 megawatts of offshore wind facilities being built off the coast of Massachusetts. That will reduce greenhouse gas emissions by approximately 6 million tons annually. The current status of our offshore wind efforts are noted on slide 11. As you can see, our South Fork project received its draft environmental impact statement. The comments on that draft are due next week. The U.S. Bureau of Ocean Energy Management continues to target January 2022 for issuing a decision on South Fork's construction and operations plan And assuming a positive decision, we continue to target an in-service date by the end of 2023. I should note that all the steps in the South Fork review process have been met either on or ahead of schedule since BOEM established its revised schedule last summer. On the state side, New York hearings on South Fork were completed in December, and we expect a state siting decision in the first half of 2021. And on the local side, our host community agreement with the municipality of East Hampton has been approved. On Revolution Lend, we filed our state signing application with Rhode Island at the end of December, and it was formally documented last month. We filed our federal application with BOEM in March of last year and expect BOEM to establish a review schedule for Revolution later this year. On Sunrise, we filed our application with BOEM in September, and our state siting application with the New York Public Service Commission in the fourth quarter. Later this year, we expect BOEM to establish a review schedule for Sunrise Wind. Our partnership with Orested has never been stronger, and we continue to work closely on both the siting and procurement for the projects we have won and our bids for additional contracts. While we're disappointed that we did not win additional capacity in the latest New York RFP, we will remain very disciplined in our bidding and know that there are likely to be several additional RFPs over the next 12 months, including Rhode Island, Massachusetts, and possibly New York. You can see on slide 12 why we can be so disciplined with our bidding strategy. The 550 square miles of ocean that we have under long-term lease from the federal government are the closest to shore and should be the least expensive to develop and maintain. Moreover, one lease costs us a million dollars. Areas that are smaller and much further from shore were leased a few years ago for $135 million apiece. This slide shows the current status of Megawatts One and megawatts still to be bid among the four states where we compete. And the number of megawatts being sought will continue to rise, pending legislation in Massachusetts, likely adding another 2,400 megawatts to the state's already approved 1,600 megawatts of upcoming RFPs. President Biden continues to express strong support for renewable energy in general, and offshore wind specifically. On January 28th, the President issued an executive order requiring the Department of Interior to conduct a full assessment of offshore wind siting processes so they align with the administration's goals to advance renewable energy production. The president has also established a White House Office of Domestic Climate Policy and created a federal government-wide task force to coordinate actions between agencies. Additionally, actions taken by Congress and the IRS late last year provide additional financial incentives for offshore wind development. As you can see on slide 13, those incentives include 30% investment tax credits for projects that commence construction before January 2026, and a 10-year safe harbor on projects eligible for tax credits. Taken together, these changes add more certainty to the tax benefits available for offshore wind and underscore the federal government's support for these projects. Lastly, before I turn it over to Phil, I want to emphasize the strong strategic position of Eversource for the coming years. Our corporate strategy is fully aligned with the energy policy of the states we serve. Our execution continues to be extremely strong. Our employees and Board of Trustees are fully engaged. Last week, our Board's Corporate Governance Committee became the Governance, Environmental, and Social Responsibility Committee, with additional direct charter oversight responsibilities for our expanding ESG initiatives. Five years ago, we said we wanted to be viewed as the country's premier energy company, And some of the citations noted on slide four illustrate the recognition that we received from a number of well-regarded third parties. I'm very confident that our future remains exceedingly bright. Now I'll turn the call over to Phil.

Thank you, Jim. Good morning, everyone. And I'll be covering several topics. Our 2020 financial results. I'll be discussing our 2021 guidance, our long-term growth rate, our capital investment plan, and recent regulatory developments. So, starting with a quick review of our full-year results, our GAAP earnings were $3.55 per share, excluding 9 cents per share of transaction costs associated with our October purchase of assets of Columbia Gas. I should say that's including the $0.09 of transaction costs. Excluding those costs, we earned $3.64 per share in 2020, consistent with consensus and with guidance we gave you a year ago. Slide 16 summarizes both the year and fourth quarter. Electric distribution earnings totaled $1.60 per share in 2020, up a penny per share from 2019. Higher distribution revenues were largely offset by higher O&M, depreciation, property tax expense, interest costs, and dilution. The higher O&M was primarily attributable to record storm expense as a result of more than 100 major and minor storm events that affected our three electric service territories last year. Non-deferred storm expense totaled nearly $77 million and was the highest level we've experienced in recent years in each of the three states we serve. These non-deferrable storm costs totaled 17 cents per share in 2020, compared with an average of about 10 cents per share in, you know, if you look at the years 2016 through 2019 average. It particularly impacted the fourth quarter of 2020 when it was responsible for an incremental $0.05 per share in O&M compared with the fourth quarter of 2019. Electric transmission earnings totaled $1.48 per share in 2020, up from $1.43 per share in 2019, excluding the Northern Pass charge. The benefit of increased investment in our transmission system was partially offset by dilution there. I should note that 2020 was a very successful year for our transmission segment, placing into service more than a billion dollars of investment, including three major projects we've been working on for several years. They were the Greater Hartford and Greenwich substation projects in Connecticut, and the Seacoast Project in New Hampshire. Transmission capital expenditures totaled $964 million in 2020, up a bit compared with our projection that we had a year ago, which was $910 million of investment. Our natural gas distribution business earned 40 cents per share in 2020, compared with 30 cents per share in 2019. Much of that improvement occurred in the fourth quarter as a result of the addition of Eversource Gas Company of Massachusetts. Eversource Gas of Mass earned nearly $14 million in the fourth quarter of 2020. Our water segment earned $0.12 per share in 2020, with earnings up $6.3 million from 2019. Much of the improvement was due to small gains associated with the sale of our Hingham, Massachusetts system and the sale of a small parcel of property. Earnings from the parent and other companies totaled $0.04 per share in 2020, excluding $0.09 per share of acquisition-related costs compared to earnings of $0.02 per share in 2019. The improvement was due to a number of factors, including a lower effective tax rate in 2020 compared with 2019. From 2020 results, I'll turn to our 2021 guidance. As you can see on slide 17, we project earnings per share between $3.81 and $3.93. Excluding certain costs, we are incurring to transition our new natural gas franchise into the Eversource system. Key drivers include several distribution rate adjustments that were effective in 2020 or the first quarter of 2021. They also include the benefit from our transmission construction program, which I'll discuss shortly, as well as a full year earnings from Eversource Gas of Massachusetts. Offsetting these benefits will be higher depreciation and property taxes, which results from the significant upgrades to our energy and water delivery systems to better serve our customers. We'll also have a higher average share count in the first half of 2021 as a result of the shares we issued in March to close out our equity forward and in June to finance the Columbia gas acquisition. In terms of O&M, you should expect the numbers we will report you'll see will be higher because of the addition of Eversource Gas of Massachusetts. On a normalized basis, though, we expect O&M will remain relatively stable during the entire forecast period. Our long-term growth will be driven by the investments we make to modernize and harden our system. to serve our customers and to support clean energy policies of the states we serve our updated core business five-year capital plan is shown on slide 18. it shows projected investments of 17 billion dollars over the five-year period compared with 14.2 billion a year ago there are many changes from the forecast we provided you a year ago but the most significant is adding Eversource Gas of Massachusetts. Slide 19 reviews the capital forecast changes by segment during the 21 through 2024 period, which is the years that are common to both forecasts. The transmission segment accounts for $528 million of the increased investment during that four-year period. There are a number of drivers here. Unlike many of our past forecasts, increased transmission investment is not being driven by large regional projects. Many of those were completed in 2020 on or below budget. In the coming years, there will be more, I'd say, bite-size. We'll be replacing equipment that was installed 60 or more years ago that has reached the end of its life expectancy. and is vulnerable to more frequent and severe storms we're experiencing in new england we're making these types of investments as well as investments in cyber physical security and other areas across our service territory on the electric distribution side we need to continue to upgrade our facilities to ensure that the reliability gains we've experienced in recent years are continued Additionally, new legislation that passed the House and Senate in Massachusetts last month is expected to provide NSTAR Electric with an opportunity to build 280 megawatts of new rate-based solar generation. We expect the legislation will be enacted and have included $500 million of solar investment in our forecast. For the natural gas segment, The continued replacement of aging infrastructure in the form of steel, bare steel, or cast iron pipe with safer, more durable plastic remains a key component of our natural gas CapEx plan. The appendix includes a slide that presents the Eversource gas capital investment forecast separate from that of the entire natural gas distribution business, so you can better model and understand our newest subsidiary. And for the water segment, our capital plan increased due to capex required for ongoing main replacements, treatment facilities, and supply of improvements in southwest Connecticut. On slide 20, we show the impact on rate base, comparing our actual rate base at the end of 2019 with our projected rate base at the end of 2025. Our rate-based CAGR over those years, including the addition of Eversource Gas of Massachusetts, is projected to be 8% compared with just under 7% we showed you last year. We expect EPS growth to be in the upper half of the previously announced 5% to 7% CAGR range. The higher growth outlook is primarily due to Eversource gas earnings. This acquisition was immediately accretive, and we expect it will be incrementally accretive each year through the five-year forecast period as we migrate off of NiceSource systems and increasingly apply Eversource best practices to our newest operating company. There are a number of investment opportunities that would significantly benefit our customers but are not reflected in the plans because there's still some uncertainty around their scope and timing. So slide 21 highlights many of these. As we get clarity of these opportunities, we'll update our subsequent forecasts. In Connecticut, Pure is moving along on a number of grid modernization dockets. but there are no final outcomes at this time. Implementing AMI solely for our Connecticut and Massachusetts electric customers would involve an investment of approximately $800 million, but none of that sum is in the forecast. Additionally, Massachusetts and Connecticut have a commitment to have at least 425,000 electric vehicles on the road by 2025. There's only a fraction of that level currently on the road, but we are only including a limited amount of investment in electric vehicle charging stations in our plan, approximately $15 million a year. Two weeks ago, Massachusetts regulators approved extending our recent level of grid modernization investment through the end of this year. In mid-2021, we'll file our new three-year grid modernization plan in Massachusetts. Additionally, we are now thoroughly reviewing the Eversource gas of Massachusetts system since we have an obligation to identify the capital investment needs and report that to our regulators by September 1st of 2021. As a result of that review, incremental investments may be identified. Finally, as Jim mentioned earlier, BOEM's schedules for review of the Revolution Wind and Sunrise projects are expected this year. I expect that in next February's update, we'll have enough clarity to roll these offshore wind outlooks into our base forecasts. especially since the Biden administration stated a desire to accelerate offshore wind development. But to be clear, in our CAGR guidance today, we reflect no earnings contribution from offshore wind. From our forecast, I will turn to current regulatory items. 2020 was marked by achieving balanced outcomes in three rate reviews that are highlighted on slide 22. uh public service of new hampshire and nstar gas have been under earning their allowed returns in recent years but both companies were able to complete lengthy rate reviews towards the end of 2020 with new multi-year plans and star gas was also able to implement performance-based rate making similar to that of nstar electric we expect NSTAR gas to continue without a base rate review for up to a decade. Also in October, Massachusetts regulators approved an eight-year rate settlement in connection with our acquisition of the Eversource gas assets, formerly known as Columbia Gas of Massachusetts. With small rate changes in November of 21 and November of 22, and additional rate resets in 2024 and 2027, based on our investments in the system, we don't expect Eversource Gas to undergo a full base case review before 2028. So not in the rate arena for several years. At public service in New Hampshire, in addition to the permanent rate increase that took effect January 1st, The settlement approved in December by regulators allows three additional distribution rate changes to cover certain resiliency investments. The first of those changes took place last month and resulted in an additional $10 million of annual revenue for PS&H to reflect investments that were made in 2019. The next rate resets in August of 2021 and again in August of 2022 will reflect investments during the 2020 and 2021 periods, respectively. We do not expect to file any general rate reviews in 2021. The next review of Connecticut Light and Power rates would need to commence no later than the first quarter of 2022 under the Connecticut statute that requires rates to be reviewed every four years for electric and natural gas distribution companies. As you know, we have a large number of other dockets in Connecticut, some of which stem from Tropical Storm Isaias and subsequent legislation that passed in September of 2020 in a special session. We've listed several of the dockets on a slide in the appendix to help you understand which PURE inquiries cover which topics. From state regulatory reviews, I'll turn now to FERC. Many of the specifics concerning the New England ROE cases are shown on slide 23. We do not know when these cases will be decided. At this time, pursuant to FERC directive, the transmission owners in New England continue to bill their customers based on the 2014 ROE decision in the first complaint or Complaint 1 that was later vacated by the D.C. Circuit Court of Appeals. And we continue to record transmission earnings based on that decision. That is a base ROE of 10.57%, an RTO adder for the vast majority of our facilities of 50 basis points, and an ROE cap of 11.74% on all transmission investments in New England. Turning to our expected financings in 2021, we have about $1 billion of debt that comes due during the year. primarily at the Eversource Parent or NSTAR Electric and PS&H, and we expect to refinance all of these maturities. We will continue to fund our dividend reinvestment and employee incentive programs with Treasury shares, raising about $100 million a year each year over the forecast period. In 2019 and 2020, we issued just over 1 million Treasury shares through these programs. Additionally, we continue to expect that over the next several years, we'll issue about $700 million of equity through an at-the-market style program. We will continue to evaluate the timing of such equity issuances based on market conditions, our investment program, and credit metrics. Finally, turning to slide 24, we know that investors are primarily focused on future earnings and cash flow when evaluating investments. However, I mean, I also believe that a company's track record of performance must be considered in evaluating the credibility of these future forecasts. As you can see on this slide, we have a very strong track record of accomplishing what we say. When our merger closed nearly nine years ago, we said we would improve reliability, achieve a high level of safety performance, control our costs, support our communities and our region's sustainability initiatives, invest in the future, and provide very competitive earnings and dividend growth. As you can see on the slide, we have been successful in each of these areas, and we're confident We can accomplish the very ambitious goals we've set for ourselves over the coming years, delivering for all of our stakeholders, including achieving the carbon neutrality by 2030. Thanks again for joining today, and I'll turn the call back to Jeff for Q&A.

Thank you, Phil. And I'm going to return the call to Brandon just to remind you how to enter questions. Brandon?

Thank you. And we'll now begin the question and answer session. If you have a question, please press star 1 on your phone keypad. If you'd like to be removed from the queue, please press the pound sign or the hash key. If you're on a speakerphone, please pick up your handset first before dialing. Once again, if you have a question, please dial star 1 on your phone keypad.

OK. Thank you, Brandon. Our first question this morning is from Char Perez from Guggenheim. Good morning, Char. Good morning, Jeff. Good morning, guys.

Good morning. A couple questions to start off. Just one clarifying question on the growth rate on slide eight, when the larger offshore wind projects start to kick in. You know, when you obviously state higher than 5% to 7% growth, Are we inferring that we could see a step change in the growth rate to, you know, maybe let's say six to eight, or simply a higher rebase that year, and you would retain your five to seven percent? And do you have any sense on when you might be adding these projects to your plan? I think you're obviously waiting for the review schedules from BOEM to solidify the CODs.

Yes, Shadi. The reduced schedule will obviously give us some certainty and definitions in terms of the spending profile and the earnings profile. But, yeah, the expectation is that we will have higher growth as those projects kick in beyond 2025. So we're not sort of resetting or providing guidance as to what that looks like right now, but it clearly will be an incremental contributor to our earnings growth out in the late 20s.

Got it. So basically a step change in the growth rate. Okay, got it. And then just taking a look at your planned investments at EGMA, you point to $270 million in CapEx annually there, which is I think more than double the amount of capital that NYSource was investing in the system. What's sort of driving the increased CapEx? Is it just more safety and reliability? And just remind us if you need any sort of regulatory approvals for the spending.

The regulatory approval to the extent that capital trackers are in place is the norm, but the spending level is more than historically has been spent there, but it's our assessment that to bring the safety and performance of that infrastructure to the standards that the other eversource gas companies have been able to achieve will require that type of investment in the system.

I could add just a little color there, too, is that, as you know, it was an asset purchase, not sort of a purchase of the company. So we're, you know, some of the things where we do have some incremental maybe IT technology types of spend to move over to Eversource systems in the past, and we certainly spend and continue to spend on our gas safety enhancement program. That's the largest category of spending in that business.

Got it. Thank you for that. And then just lastly for me, obviously you highlight there's a couple more RFPs coming this year. We're relying on Massachusetts and New York. Just given the bids we've seen from obviously some of the oil majors, it may be difficult to be successful. But you still do have a lot of excess lease capacity. Can you maybe just elaborate a little bit more on your strategy with the lease areas? Do you sit on your leases until the other leases, you know, sort of are filled, which could take years? Or would you look to potentially monetize some of the space there? So maybe just, Jim, if you could just elaborate a little bit more around the strategy around those leases.

Yeah, the strategy has been consistently one of financial discipline. As I've So my board, and I've actually presented to the Orsted board in the past, that they should expect us to lose as many RFPs as we win because we're intent on having these awards be profitable. So we're excited about the increasing demand. It seems like every couple of months the numbers go up in terms of the state's appetite for this. And when we look at our situation, we have plenty of dry powder for those bids. I think I could be wrong, but I think our leases are undersubscribed compared to the others that are starting to fill up with their existing portfolio of contracts. So we will continue to be disciplined, and we're optimistic that the appetite is there for a significant build-out of offshore loans. So I think we're in a very good position.

Terrific. Thank you, guys. I'll jump back in the queue. Congrats.

All right. Thank you, Char. Next question this morning is from Jeremy Tenet from J.P. Morgan. Good morning, Jeremy.

Hi. Good morning.

Good morning.

I just wanted to start off with the offshore wind here and wanted to see if you might be able to help us. How much offshore wind can you fit on the leases using the new 13-megawatt turbines versus the 8-megawatt turbines originally discussed? Thanks.

Yeah, I'll take a shot at that and others could add, but, uh, fundamentally we've been talking about the least capacity of being 4,000 megawatts historically. Um, you know, when you, uh, increase the capacity of the turbines, uh, from, uh, you know, what was an eight megawatt turbine to an 11, as you mentioned, potentially 13s going forward, obviously that increases your capacity. At the same time, we have agreed to spacing of the turbines as part of the compromises to get the approval process at bone when we're spacing them a mile between each turbine. So that actually reduces your potential capacity. So net-net, we are saying it's at least 4,000 megawatts, and we expect to fully build it out at that level. More than 4,000 megawatts is what the guidance will give you.

Got it understood. At least 4,000. That's helpful. Thanks. And just want to turn it over to CLP for a quick minute here. The CLP rate case reopening appears really focused on low-income rate structures from what we can see, making it kind of a very low-risk event in our minds. Does it look like this to you, or are we missing something here? Just any color you can provide would be great.

Yeah, the guidance that we've seen is that the federal will be looking at new rate designs, including possible low income or economic development rates that may require a possible interim rate reduction. I think it's important to recognize that we're not earning our allowed return in that franchise and We're mandated or required to come in with a full rate review actually within the next 12 months. I think I still mentioned the first quarter of 2022, a full review is needed. So our understanding or expectation is that any rate design changes that come out there would not necessarily be punitive to the company, especially as we continue to under-earn. That's very helpful.

That's it for me. Thanks.

All right, thank you very much. Our next question is from Steve Fleischman from Wolf. Good morning, Steve.

Hey, good morning, and I apologize in advance if I missed some comments related to my questions. But just I think on one of the first questions asked about the long-term growth rate with the offshore wind, and I think you said, Jim, higher into the late 2020s. And not to be too picky, but just is that suggesting that you're not really expecting the projects to fully come on until after mid-decade? Like, should these projects essentially be on for 2025, I guess is my question.

Yeah, I mean, again, we're very hesitant, Steve, to commit to changing dates, especially since we think that we'll shortly have guidance from from the administration in terms of expected timelines. But what we've said and continue to say is that South Fork, we hope to expect to be in by the end of 2023, but it's clear that Revolution Wind will not be in by the end of 23, and Sunrise Wind is not expected to be in by the end of 24. So there's some slippage there. The full impact of the the offshore wind projects, especially the big ones, clearly a mid-20s event. And, you know, the ICC kicks in there as well. So, you know, we're not talking about the waves here. It's just a map of a project that comes in during the year. You don't get the full benefit of it until the full calendar year the next year. So I don't want you to read more into my comments than that. It's a step up.

Yeah, yeah. Okay. No worries on that. And I guess it doesn't matter as much anyway, given the ITC extension and safe harbors and stuff. And just maybe on that, I mean, is there, I know there's a lot of moving parts when you look at the economics of the projects you've done, but would you characterize the ITC order as kind of improving the economics overall from what you had expected before?

Yes, certainly. It significantly improves based upon what we're assuming for ITC at the time of our bids. As you mentioned, with a lot of puts and takes, you have costs that go up and down, and so we're encouraged that the ITC amount is the level that it's at now. And more importantly, the 10-year window, I think, de-risks quite a bit. The fear that some might have that our ITC level was vulnerable. So we see it certainly as a major positive.

Great. And then lastly, on the Connecticut rate review that's going on, I recognize that it's not kind of full rates and the like. I guess I don't really know how to size these issues, like what the basis would be to set any of these interim rates or other things. So do you have any idea how they would even calculate what to do, what the basis would be?

I don't. I mean, there are probably examples of low-income rates or economic development rates that other states have implemented that they could look at as models. You know, what I would say, Steve, is that we're very early on, early stages of this process, so it's hard for me to add any certainty there other than, as I mentioned earlier, that we clearly are not earning our allowed return that we have agreed to under a settlement that's been in place for three years now.

Okay. Thanks so much.

All right. Thanks, Steve. Our next question this morning is from Ryan Greenwald from Bank of America. Good morning, Ryan.

Hey, it's Julian here. Thanks so much for coming, guys. Hey, Julian. Hey, howdy. So maybe to follow up in order here, can you talk about the run rate level of contribution from the offshore projects? I know the timing is is obviously moving around. And I know you just said that there are lots of puts and takes, but in an effort to sidestep some of that debate, as best you see it today, including the latest updates to the ITCs, how would you characterize that run rate level of net income contribution, if you will?

Yeah, again, it's another way, Julian, I guess, to get at the question of providing guidance out beyond our forecast horizon here. So, I don't want to publish a number until we have a pretty good visibility into the annual cash flows and profile of each of the projects.

Got it. Understood.

What we have said and we're consistent on is that we anticipate these projects to provide mid-teens ROEs, which would be sort of the highest of business segments, which we feel is appropriate because they are the riskier of the business segments in our portfolio.

Got it. I appreciate the reaffirmation. On the balance sheet and equity, I just want to make sure I heard you right, because you made a couple comments, and I think you didn't say specifically over what period of time. So I think you said $700 million over the next several years. I just want to make sure I'm hearing very clearly about your equity needs and where it positions your balance sheet over the full five-year period, if I can't ask more directly.

Yeah, I'll ask Phil to answer that part.

Yeah, great. I was going to jump in there, Jim. So, Julian, for the plan that we put out in terms of the $17 billion capital forecast over the five years, the $700 million supports that plan, along with the $100 million a year that we do through the dividend reinvestment and DRIP. So if you add that up, that's $100 million a year through that, and then $700 million through a, you know, a periodic at-the-market type program. And what I suggested was that that would be based upon, you know, what market conditions look like, you know, what our metrics are looking like, what, you know, what our, you know, if there's changes in terms of puts and takes, in terms of the timing of the investment profile. So, those would be the considerations. So it would be sometime over the five-year horizon. I don't expect that it would be in 2021. You know, I would expect that it would be, you know, in years other than 2021 in terms of the $700 million. Obviously, we're doing the dividend reinvestment every year, so we'd have that number. Does that clarify it for you?

Maybe you can say it slightly more definitively. This puts your metrics where from a net-voted debt perspective, i.e., this should suffice to maintain your metrics at roughly the same level through the five-year outlook at that equity level, or you're not ready to take that statement?

That is correct. That is correct. We would be looking to target the metrics to support the current ratings and where they are today.

Okay, with the $700. All right, sorry, I don't mean to over-emphasize it. I just want to make sure it's clear.

Thank you. No, that's fine. You're welcome.

Okay, our next question this morning is from Angie Starovinsky. Good morning, Angie.

Good morning. So I just wanted to follow up on the equity needs. So the delta between the rate-based growth and the earnings growth, that's purely about the equity dilution, or there's some changes in realized ROEs as well? say i'm not to say that again because you're saying that the rate base is going at eight percent right and then you're saying the earnings growth is the uh upper half of the five to seven right so let's just say let's just say six and a half right so i'm trying to to understand if the delta between eight percent and then say six and a half is solely a function of the equity dilution or is it

some i don't know assumed uh you know lower roe or something to that effect um no it's primarily the equity issuance would be the driver there i mean even for 2021 um you have to keep in mind that um as i mentioned in my comments you know we closed out a forward uh contract in march and then we had additional shares that we issued in june so all of those now get into a full year know of 2021 that that you know didn't impact us in 2020 and then as we do the treasury shares and um you know uh move in the 700 million that i discussed that would be the the primary um mechanism that would be you know causing the difference okay thank you and then

On Columbia Gas, I'm sorry, I'm just going to keep calling it like that for now. Is it the $275 million of CapEx? I understand that this is your current assessment and that you're going to be working on incremental CapEx updates. But can you give us a sense, you know, how big of a delta we could see this? Is it doubling of the 275 a year? Is it just, you know, some tweak to the current CapEx estimate that you'd expect?

Well, that process, as I said, we're as part of the rate agreement that we had with Massachusetts when the deal got approved. In September of this year, we'll be filing a report, you know, that identifies that. So I'd say it's a little premature to speculate on what that might look like. You know, in terms of sizing, we're certainly active in terms of looking at that right now. I'd say that there's been no surprises in terms of taking the keys You know, we did it all remotely in a COVID environment, but we did a very in-depth due diligence job, so no surprises there. But I'd say it's, you know, we're just, you know, not at the final stages of that assessment so that I could give you a good answer.

Okay. The only add is that, as Phil mentioned earlier, in that $275 million, we have some, you know, one-time items over the next couple of years to fully integrate the shared service functions that are currently being supported by NYSOS through a transmission services agreement. So some of that spend in the next two years in particular is really merger integration related.

Great. And if I may, just one last question. In the climate bill in Massachusetts, the latest version of it at least, I mean, it still talks about conversions of numerous houses to electric heat and then you know, maybe less aggressive, but still, you know, electric-driven construction in the state. How do you see it, you know, impacting both your electric utility and gas utility in the state? You know, I mean, it is a Republican governor who seems to be pushing for, you know, less natural gas connections for new construction.

Well, I think, first of all, both our gas and electric business in the state of Massachusetts operate under a decoupled rate regime. So to the extent volume goes up or down, we drop to an approved revenue level. The biggest opportunity that we have in the state of Massachusetts is in the areas of transportation and home heating oil. More than 50% of the the businesses and homes in Massachusetts heat with oil. And this significant improvement, if you don't go to electric, but you can go to gas, the emissions uptake improvement, if you will, is significant. So I think we'll work with the state as we will the other states to make sure that we can aggressively decarbonize the supplies. We're comfortable with where that legislation is, and as Phil mentioned, one of the components in it allows utility-scale solar build-out, and we're confident enough in it being there and that we're putting it into our base forecast here for this guidance.

Good. Thank you.

Thank you, Angie. Next question this morning is from Durgesh Chopra from Evercore. Good morning, Durgesh.

Good morning, Jeff. Thanks. Two quick ones. First, maybe can you sort of what milestones should we watch for in terms of this rate review in Connecticut, the low income tariffs that you mentioned? So what's what are the timeline and what should we be sort of looking for in terms of calendar?

Jeff, do you have any specifics there of the calendar on that proceeding? I know we're early on in the process.

Yeah, we put the docket up, but I don't think there's really any. I mean, it's sort of open-ended right now.

Got it. Okay, perfect. And then just one quick clarification in terms of the, I believe the decision is in April on the storm investigation. Just what to expect there and how are you sort of accounting for that in your 2021 guidance numbers? Thank you.

Sure. The remaining scheduled areas, I think, reply briefs are actually due this week. I think we would expect the tentative decision about a month later, say mid-March. Written exceptions, we'll probably follow that a few weeks later. And then oral arguments, you know, maybe mid-April with a final decision on the 28th. I think we're investigating the prudence of the costs and We're confident that we assembled the largest workforce ever in the state of Connecticut for that storm response, and the vast majority of the costs that are being reviewed have to do with bringing in those external resources, either from other utilities or from contractors. So we expect, as we have in the past, that cost recovery would be allowed for these costs as they're prudent.

Understood. Thanks, guys. Much appreciate the time.

All right. Appreciate it, Dagesh. Next question is from Ryan Levine from Citi. Good morning, Ryan.

Good morning, Jeff. A couple questions. What percentage of the offshore wind CapEx do you expect to qualify for the ITC, and are there any steps that the company can take to increase this in the coming months or years? And then I guess the follow-up on it related to that is how does that differ for some of the prospective projects that you're looking to bid on?

You know, I'd ask Phil or John to provide any insights on that question.

Yeah, effectively, we would expect all or majority of the spending to qualify under the ITC provisions.

Okay. I mean, I thought there was some component of the portion that's not considered offshore that may not qualify in terms of the total CapEx deployed for the project. Are you saying that 100% of the CapEx is?

No, it's roughly about an 80-20 split. So if you kind of look at the total CapEx, about 80% of that would be the offshore piece that would qualify for the ITC.

Okay. And there's no opportunity to move that 80% closer to 100%? No.

I mean, the rules are pretty clear in terms of what would qualify and what wouldn't. And so kind of what it ties to is the onshore piece obviously wouldn't qualify. And so when you tie into that onshore piece, that's deemed onshore.

And does that 80% roughly apply to the prospective projects that you're looking to bid in the various states?

I mean, I think from a rule of thumb, it's probably safe. But, again, it all really kind of depends on, you know, how we look at where we're going to land and, you know, how we look at kind of the profile that's out there with what we build in the leased area.

Okay. Thank you. Great. Thank you, Jay. And thank you, Ryan. Next question is from Nick Librano from BMO Capital. Good morning, Nick.

Oh, hey, guys. It's James Thalicker, actually.

Hi, James.

Hey, Jeff. Real quick question. Just, I guess, just confirming, you know, it doesn't sound like the equity needs that you were forecasting, the $100 million of sort of Treasury shares and then the $700 million of incremental equity has really changed. I guess as we think about the, you know, you've got a pretty large rate-based growth at the Columbia Gas business right now. Is part of the reason that, you know, your equity needs aren't, you know, going up materially is because of the rider treatment you have there as well as the fixed rate increase that you have embedded in the settlements?

I'd say that we do have a number of, I'd call them timely recovery tracker programs, not just that Eversource gas of Massachusetts, but uh throughout the various subsidiaries whether they be for accelerated pipe replacement for you know safety and pull replacements things like that so um but because of the timely tracker cash recovery that is very beneficial okay great thank you very much you're welcome all right

Thanks, James. Next question is from David Arcaro from Morgan Stanley. Good morning, David.

Hey, good morning. Thanks so much for taking my question. A couple of quick ones. So I was just curious on offshore wind, to the extent there are items that improve the economics, like the higher ITC level or longer wind blades, would those benefits accrue to yourselves, or are there opportunities or chances that you would pass any of those back, like in lower rates within the contract mechanism or anything like that?

The current contracts don't call for adjusting the pricing based upon changes like that.

Okay, got it, understood. And then separate topic, I was curious, do you see any prospects for improved acceleration in heat pump use in your states? Anything that's on the horizon that might change the economics or be in favor of using more heat pumps to electrify space heating and potentially increase the electric load going forward?

We do have a pilot program that was approved in our Insta gas rate case. And so at this stage, I think we're exploring what those pilots will tell us in terms of the long-term prospects up in our geography for that technology.

Okay, got it. We'll watch that. Thanks so much.

All right. Thank you, David. Our next question is from Travis Miller from Morningstar. Good morning, Travis.

Good morning, everyone. Thanks. I just want to follow up on the earlier question, I think it was Andy's question about that 8% rate base CAGR and then the earnings guidance, the 5% to 7%. I understand the equity component, it seems like you've got good long-term rate plans in place, not a whole lot of regulatory risk on the other side. I was just wondering if you could take us through some variables that might get you to the lower end of that range.

There's a... Thanks, Travis, for your question. We talk about we're a regulated business, so certainly regulatory outcomes have an impact on where you end up in any kind of earnings growth or annual range. So, you know, outcomes of regulatory cases could move you higher or keep you in the middle or move you to a different end of the range. Certainly, incremental investment opportunities, we've identified several of them that are active now, you know, in terms of AMI or additional grid modernization, and those are more things that can take you to the higher end of the range. um certainly you know how you do as a company any company does on their on their o m management is important and you know i think uh you might agree that you know you can't really find anybody better uh mothers than ever source and controlling costs so certainly if if there's cost o m pressure that could move you around in the range so i think those are those are some of the bigger variables that could move you into different different parts of the range but We're confident in where we are guiding to. We're confident in our ability to execute on our investment plans and as well as run the business in a safe and efficient and effective manner.

Oh, great. That's helpful. Thanks. And then real quick on the electric vehicle charging. If you look out over the five years, you had mentioned the relatively small program you have now. What do you think about the upside potential in terms of capex and would we see that more in distribution or is there an opportunity to add transmission in terms of large substations, et cetera, that would support EV?

I think the benchmark, Travis, I mentioned is that I think there were only 1,400 charges in the state of Massachusetts, and we're finishing up a three-year program that brings that number up to 5,200. But the time is that Connecticut and Massachusetts both have electric vehicles are quite ambitious. We have a slide in here that shows that. So my expectation is that the investments will largely be in the distribution system. I think we'll be mindful about any potential impacts on transmission needs. But I think that would be focused on distribution build-up for these charges, and I wouldn't expect any near-term transmission needs created by the oil.

Okay, great. I appreciate it. Thank you, Travis. Next question is from Paul Patterson from Glenrock. Good morning, Paul.

Good morning, guys. How are you doing?

All right.

How are you? Good morning. So really quickly, on the – On the Connecticut, you guys mentioned that you don't think you're earning your ROE and stuff. And I was just wondering, I know last year you guys obviously had challenges with storms and stuff, but if we were to look like on sort of this level, I mean 2021, I know you're not giving guidance per sub, but just sort of roughly speaking, what kind of ROE or return range do you guys sort of expect to be in for 2021 in Connecticut?

Well, this is Phil. You know, the Our last filed, you know, we filed sort of on the quarters, you know, in Connecticut was about 8.6%. And we're allowed nine and a quarter. So, you know, we're certainly below the allowed return limit. you know, in the settlement that we had. So that, you know, we'll be finalizing the year. I don't expect it to change dramatically, but that was our last filed number in Connecticut.

But does that have the storms and stuff in there, or is that sort of a normalized number?

Well, as you probably know, that most of the storm costs for East IES were deferred because there's triggers that... You know, if you're above, you know, $4 million in Connecticut, you defer the cost. So we'll be disclosing, you know, there's about $228 million of deferred storm costs. So those wouldn't affect it. So it's not an abnormally low number because of that. In addition, as I mentioned and Jim mentioned, we had, you know, 100 – plus other storms, and some of those don't trigger a deferral. So those would impact all electric franchise ROEs.

Okay. That's great. That's helpful. And then also just on the CLP transmission capex, 2021 and 2022 seem like they jumped a lot over your last forecast. And I was just sort of wondering if there's anything – to call out on that? I mean, you guys mentioned you're not doing any large projects, really, or it's mostly sort of nuts and bolts. It sounds like I'm just wondering if there's anything in particular that, I mean, that seems to be one of the bigger moves in the slide deck.

I'm not. Actually, I think the projected transmission capital is decreasing at CLM. You know, there's some larger expenditures, or you could say larger in 21, but then those sort of decline. Is that the chart you're looking at, Paul?

Well, I think it's on – when I look at the chart, it looked to me when I was doing a comparison that, you know, from 2021, it went from 209 to 443, and for 2022, 184 to 264. I can follow up later. I mean, I'm not trying to – But that's what it just looked like to me. It could be timing, too, or something. I don't know. Anyway, I was wondering if there was anything in particular. And finally, on the offshore wind, given what we've seen in Texas and what have you, and I apologize for not knowing this, but I was just wondering, just in terms of how these contracts work, if there was some issue with not being able to provide power, is there... do you have to go in the spot market and make it up, or do you just simply not get paid for the power that you don't deliver? I just wanted to sort of get a sense as to how it works, since basically what made me think about this, of course, is what we're seeing in the Midwest and stuff.

Yeah, I think that from what I understand about Texas and what they're struggling with, I think the problems stem from the financial structure for power generation that really doesn't offer the many incentives to the power plant operators to prepare for the winter. They have an electric grid. They put an emphasis on cheap prices over reliable service. In New England, as you know, we have a robust capacity market where the ISO box and adequate supplies come in four or five years out. And in terms of the people talking about wind, from what I understand, the impact on the thermal plants dwarfs the wind freeze-ups that they that they're dealing with. I think the nuclear unit went down, but the gas plants probably five or six times the load that was lost in wind. I think wind's only 10% of the load in Texas.

Are you interested? I'm not suggesting that there's some particular issue with it. I'm just wondering, though, In terms of wind being kind of an intermittent resource, I'm just wondering, the way the contract works, if for some reason, whatever it may be, you don't have the production that you expected, would that be something where you just simply don't get paid if that production isn't happening, or would you actually maybe be short, so to speak, and have to make up the difference? My assumption is the former, not the latter, but I just wanted to make sure.

Yeah, it's the formal. We get paid on a per kilowatt basis. And so if we don't deliver it, we wouldn't have the revenue stream coming in.

Okay. Thanks so much. I really appreciate it, guys. All right.

Thank you, Paul. Next question is from Mike Weinstein from Credit Suisse. Good morning, Mike.

Hey, good morning. Hey, Paul. One more question on offshore wind. CEO of Total today came out and said that the IRRs on offshore wind are the most competitive of the entire renewable industry, 2% to 3% IRRs. Is that something you guys are seeing as well, your analysis of the project opportunities for Morristead? What do you see going forward?

Yeah, this is it. Clearly, the competition has increased, and I think the latest evidence of that was the New York RFP that I mentioned in my comments, and we continue to stay disciplined. I think people are bidding into this for multiple reasons, very small returns, but maybe some branding. Plus, I think it's appealed to some of the players in the business now. So, as I mentioned, we'll continue to participate in the RFPs. We will get creative about, you know, our cost structure going forward. More and more that the supply chain moves over to the U.S. from Europe, I think there are cost advantages there. So we'll be continuing to be disciplined. You know, 2% to 3% IRR is not something that we want to win, frankly, and we're still targeting that mid-teens ROE for our investors.

And for the BOEM review schedule, I know I think in the slide deck you said expected in 2021 for both Revolution and Sunrise. I think previously you had said early 21 for Revolution, but it looks like you forgot the word early. Is that intentional?

Yeah, I don't think it's intentional. I think it's recognizing that we're going to get more specifics on both of those projects as new leadership of BOEM and the Department of Interior settle into their roles. Clearly, the Biden administration is supportive of watching the wind and accelerating the approval process. But the Department of Interior, I don't believe the proposed secretary has been approved yet. We are encouraged by what we see as the new head of BOEM. She actually came out of the Cuomo administration and is very familiar with the offshore wind solicitations that New York has run. So, yeah, I wouldn't read much more into it other than new people with new roles, so we'll see what the schedule is.

Great. And then to the EV and AMI dockets, is that – I think you guys are expecting some comments in March in those dockets and – Also, is there any kind of interplay, or are they dependent on getting this rate review docket done first, or are they completely independent?

They're independent.

Go ahead, Phil. Go ahead, Jim. You finish.

Yeah, I think the AMI is early on in the process in terms of the calendar, but the electric vehicle deployment hearings going to take place on straw proposals at the end of February, and we would expect a decision in late March. I think they run totally separate from the other dockets that are on the table at Europe.

Okay, great. Thank you very much. Thanks.

All right. Thank you, Michael. And that was the last question we had this morning. So thank you very much for joining us today. If you have any follow-up questions, please call or send an email, and we'll get back to you. And have a good day.

Thanks. Stay well, everybody.

Thank you. Ladies and gentlemen, this concludes today's conference. Thank you for joining. You may now disconnect.