Good morning and welcome to the Eversource Energy fourth quarter and year-end 2020 results conference. My name is Brandon and I’ll be your 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, one if you have a question. Please note this conference is being recorded. 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 to 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 risks 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 Moreira, our Treasurer and Senior VP for Finance and Regulatory; and Jay Booth, our VP and Controller. Now I will turn to Slide 2 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 in what’s been a challenging year for everyone. I’ll start my comments by thanking our more than 9,000 Eversource Energy colleagues for their exceedingly hard work in 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 on Slide 4, 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 safe, 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 NiSource to buy its Columbia Gas and 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 has 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 and 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. We also maintained our track record dating back to the 2012 merger that created Eversource while posting attractive earnings and dividend growth. Turning to Slide 5, 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 6 illustrates what we’re able to achieve on behalf of our shareholders. 2020 was far from the best year for utilities, but we were able to achieve a 4.5% total return for our shareholders, keeping us in the top tier of our 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 7, last week the Eversource board increased the quarterly dividend by approximately 6.2%. You can also see that our payout ratio remains at about 62%, 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% pace. As you can see on Slide 8, we expect that growth rate to be enhanced in the coming years by our Eversource Gas acquisitions 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%, but 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 it to our long-term strategy of being the principal catalyst to 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, continue to reduce methane leaks from our distribution system, and taken other steps to improve the efficiency of our delivery system, 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% by 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 with more than $500 million that we invested in custom energy efficiency initiatives in 2019 alone will reduce greenhouse gas emissions by 3.2 million metric tons. Efforts to significantly expand our zero-emission vehicle charging infrastructure and reduce the number of homes heated with oil offer very significant additional opportunities to reduce the region’s emissions. The most significant initiative we have underway is our partnership with Ørsted 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 is noted on Slide 11. As you can see, our South Fork project received its draft environmental impact statements and 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 the state siting decision in the first half of 2021. On the local side, our host community agreement with the Municipality of East Hampton has been approved. On Revolution Wind, we filed our state siting application with Rhode Island at the end of December and it was formally docketed last month. We filed our settlement 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 new schedule for Sunrise Wind. Our partnership with Ørsted has never been stronger and we continue to work closely on both the siting and procurement for the projects we have won and in our bids for additional contracts. While we are 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 500 square miles of ocean that we have under long-term lease with the federal government are the closest to shore and should be the least expensive to develop and maintain. Moreover, one lease cost us $1 million. 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 won and megawatts still to be bid among the four states where we compete. The number of megawatts being sought will continue to rise with 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 28, the President issued an executive order requiring that the Department of the Interior 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 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 with 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 and 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 4 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. 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. Starting with a quick review of our full year results, our GAAP earnings were $3.55 per share, excluding $0.09 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. High 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 expenses 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 $0.17 per share in 2020 compared with an average of about $0.10 per share if you look at the years 2016 through 2019 averaged. 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 $1 billion 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 $0.40 per share in 2020 compared with $0.30 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 a 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 of 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 and 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 of earnings from Eversource Gas of Massachusetts. Offsetting these benefits will be higher depreciation and property taxes which result 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’ll report, you’ll see will be higher because of the addition of Eversource Gas of Massachusetts; but on a normalized basis, 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 systems 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 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 2021 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, they will be more, I’d say bite-sized. 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 are 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 pipes 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. For the water segment, our capital plan increased due to capex required for ongoing main replacement, treatment facilities, and supply 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 base 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 NiSource 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. Slide 21 highlights many of these. As we get clarity of these opportunities, we’ll update our subsequent forecasts. In Connecticut, PURA 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 1, 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 this offshore wind outlook into our base forecast, 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.

Thank you Phil. I’m going to return the call to Brandon just to remind you how to ask questions. Brandon?

Thank you, Phil. I’m going to return the call to Brandon to provide instructions on how to ask questions. Brandon?

Okay, thank you Brandon. Our first question this morning is from Shahriar Pourreza from Guggenheim. Good morning, Shahriar.

Good morning Jeff, good morning guys. Just a couple questions to start off. Just one clarifying question on the growth rate on Slide 8, when the larger offshore wind projects start to kick in. Obviously, you state higher than 5% to 7% growth. Are we inferring that we could see a step change in the growth rate to, maybe let’s say 6% to 8%, or simply a higher rebased that year and you would retain your 5% to 7%, 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 Shahriar, the review schedule will obviously give us some certainty and definition in terms of the spending profile and the earnings profile, but yes, the expectation is that we will have higher growth as those projects kick in beyond 2025. We’re not resetting or providing guidance as to what that looks like right now, but it clearly will be an incremental contributor to our earnings growth in the late ‘20s.

Got it, so basically a step change in the growth rate? Okay, got it. 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 NiSource was investing in the system. What’s driving the increased capex - is it just more safety and reliability, and just remind us if you need any sort of regulatory approvals for this spend.

The regulatory approval to the extent that capital cap is 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 are able to achieve will require that type of investment in the systems.

I could provide a bit more context by noting that this was an asset purchase rather than a company acquisition. We are incurring some additional spending, particularly in IT technology, to integrate with Eversource systems, and we are also investing in our gas safety enhancement program, which represents the largest portion of our expenditures in that area.

Thank you for that, Phil. Lastly, I want to ask about the upcoming RFPs, particularly in Massachusetts and New York. Given the competitive bids from some of the oil majors, it might be challenging to succeed. However, you have significant excess lease capacity. Can you share more about your strategy regarding these lease areas? Will you keep your leases until the others are filled, which might take years, or are you considering monetizing some of that space? Jim, could you provide additional details on the strategy for those leases?

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

Terrific, thank you guys. I’ll jump back in the queue. Congrats.

Great, thank you Shahr. Next question this morning is from Jeremy Tonet from JP Morgan. Good morning, Jeremy.

Hi, good morning. Wanted to start off with 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.

Yes, I’ll address that and others may contribute as well. Essentially, we’ve previously stated that the lease capacity is 4,000 megawatts. Increasing the turbine capacity from 8 megawatts to 11 megawatts, and potentially to 13 megawatts in the future, obviously enhances your capacity. However, we have agreed to space the turbines a mile apart to facilitate the approval process with BOEM, which actually limits your potential capacity. Overall, we are affirming a minimum of 4,000 megawatts and we anticipate it will exceed that amount.

Got it, understood - at least 4,000. That’s helpful, thanks. Just wanted to turn it over to COP for a quick minute here. The COP rate case reopening appears really focused on low income rate structures from what we can see, 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 could provide would be great.

Yes, the guidance that we’ve seen is that COP will be looking at new rate designs, including possible low income or economic development rates, and 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 and required to come in with a full rate review actually within the next 12 months, I think as Phil mentioned, the first quarter of 2022 a full review is needed. 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.

Thank you very much. Our next question is from Steve Fleishman from Wolfe. Morning, Steve.

Hey, good morning, and I apologize in advance if I missed some comments related to my questions. I think 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 ‘20s. Not to be too picky, but is that suggesting that you’re not really expecting the projects to fully come on until after mid-decade? Should these projects essentially be on for 2025, I guess is my question?

Yes, again we’re very hesitant, Steve, to commit to changing dates, especially since we think that we’ll shortly have guidance from the administration in terms of expected timelines. But what we’ve said and continue to say is that South Fork, we 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 offshore wind projects, especially the big ones, is clearly a mid-‘20s event, and ITC kicks in there as well, so we’re not talking about the dozen 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 a full calendar year the next year, so I don’t want you to read more into my comments than that, but it’s a step up.

Yes, that’s fine. I don’t think it’s a big deal anyway, considering the ITC extension and Safe Harbors. However, regarding that, I understand that there are many factors at play when evaluating the economics of the projects you’ve undertaken, but would you say that the ITC order has positively impacted the overall economics compared to what you were expecting before?

Yes, certainly it significantly improves based upon what we were assuming for ITC at the time of our bids. As you mentioned, there’s a lot of puts and takes - costs 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. 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 full rates and the like. 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. There’s probably examples of low income rates or economic development rates that other states have implemented that they could look at as models. 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.

Yes, okay. Thanks so much.

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

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

I’d ask Phil or John to provide any insights on that question.

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

Okay. 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 look at the total capex, about 80% of that will be the offshore piece that would qualify for the ITC.

Okay, and there’s no opportunity to move that 80% closer to 100%?

No, the rules are pretty clear in terms of what would qualify and what wouldn’t. What it ties to is the onshore piece obviously wouldn’t qualify, and so tying to that onshore piece, that’s deemed onshore.

Thank you Ryan. Next question is from Nick Lubrano from BMO Capital. Good morning Nick.

Hey guys, it’s James Thalacker actually.

Hi James.

Hey Jeff. I just want to confirm that it seems your equity needs forecast, which includes $100 million for treasury shares and $700 million for incremental equity, hasn't really changed. Considering the significant growth in the rate base at the Columbia Gas business, is one reason your equity needs aren't increasing substantially due to the rider treatment there, along with the fixed rate increase included in the settlement?

Yes, I’d say we do have a number of, I’d call them timely recovery tracker programs, not just at Eversource Gas of Massachusetts but throughout the various subsidiaries, whether they be for accelerated pipe replacement, for safety and pole replacements, so because of the timely tracker cash recovery, that is very beneficial.

Okay, great. Thank you very much, Phil.

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 quick ones. 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 contracts don’t call for adjusting the pricing based upon changes like that.

Okay, got it. Understood. 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 NSTAR 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 in that 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 wanted to follow up on an earlier question, I think it was Andy’s question about that 8% rate base CAGR, and then the earnings guidance, the 5% to 7%. 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. Just wondering if you could take us through some variables that might get you to the lower end of that range.

Thank you, Travis, for your question. As a regulated business, regulatory outcomes certainly influence our earnings growth and annual range. The results of regulatory cases could either boost our position or keep us in the middle, or shift us to a different part of the range. We have identified several incremental investment opportunities that are currently active, such as Advanced Metering Infrastructure and additional grid modernization, which could help us reach the higher end of the range. Additionally, how well a company manages its operational and maintenance costs is crucial, and I believe Eversource excels in controlling these expenses. However, if there are pressures on operational and maintenance costs, that could affect our positioning within the range. These factors are some of the key variables that could impact our place in the range. Nevertheless, we are confident in our guidance, our ability to execute our investment plans, and to operate the business safely, efficiently, and effectively.

Great, that’s helpful. Thanks. Then real quick on the electric vehicle charging, if you look out over the five years, you’d 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, etc. that would support EV?

I think the benchmark, Travis, I mentioned is I think there were only 1,400 chargers in the State of Massachusetts, and we’re finishing up a three-year program that brings that number up to 5,200. But the tie is Connecticut and Massachusetts both have electric vehicles - they’re 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 we’d be focused on distribution build-out for these chargers and I wouldn’t expect any near-term transmission needs.

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?

I’m managing. Really quickly 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 the storms and stuff, but if we were to look on this level, 2021, I know you’re not giving guidance, but just roughly speaking, what kind of ROE or return range do you guys expect to be in for 2021 in Connecticut?

Paul, this is Phil. Our last file we filed on the quarters in Connecticut was about 8.6%, and we’re allowed 9.25%, so it was certainly below the allowed return in the settlement that we had. We’ll be finalizing the year. I don’t expect it to change dramatically, but that was our last filed number in Connecticut.

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

As you may know, most of the storm costs related to Isaias were deferred due to triggers that mandate deferral if costs exceed $4 million in Connecticut. We will disclose that approximately $228 million of storm costs were deferred. These do not impact the figures, so the number is not unusually low for that reason. Additionally, as both I and Jim mentioned, we experienced over 100 other storms, some of which do not qualify for deferral, and these will affect the returns on equity for all electric franchises.

That's great and helpful. Regarding the COP transmission capex, it seems that 2021 and 2022 experienced a significant increase compared to your previous forecast. I was curious if there’s anything noteworthy to mention about that. You indicated that there aren’t any major projects happening, and it primarily involves smaller tasks. I’m just wondering if there’s anything specific that stands out, as that appears to be one of the more substantial changes in the presentation.

I think the projected transmission capital is decreasing. There are some large expenditures in 2021, but then those decrease. Is that the chart you’re referring to, Paul?

I think when I looked at the chart, it appeared that in 2021, it increased from 209 to 483, and in 2022, it went from 184 to 264. I can follow up on this later; I'm not trying to imply anything.

Okay.

It seemed to me that timing could be a factor, but I’m not certain. I was curious if there was anything specific to consider. Also, regarding offshore wind and the current situation in Texas, I apologize for my lack of knowledge, but I wanted to understand how these contracts function. If there's an issue preventing power delivery, do you have to enter the spot market to compensate, or do you simply not receive payment for undelivered power? My interest in this was sparked by recent developments in the Midwest.

Yes, 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 any incentives for power plant operators to prepare for the winter. They have an electric grid, they’re putting emphasis on cheap prices over reliable service, and as you know, we have a robust capacity market where the ISO locks in adequate supplies, maybe four or five years out. In terms of the thing we’re talking about, wind, which from what I understand the impact on the thermal plant dwarfs the wind freeze-up that they’re dealing with. I think the nuclear unit went down, but the gas plants are probably five or six times the load that was lost in wind - I think wind’s only 10% of the load in Texas.

I’m not suggesting there’s a specific problem, but I’m curious about how the contract works regarding wind as an intermittent resource. If, for any reason, you don’t achieve the expected production, would that result in not being paid at all, or would you be required to make up the difference? I believe it’s the former, but I want to confirm.

Yes, it’s the former. We get paid on a per-kilowatt basis, so if we don’t deliver, we don’t have the revenue stream coming in.

All right, thank you Paul. Next question is from Mike Weinstein from Credit Suisse. Good morning Mike.

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

Yes, clearly the competition has increased, and I think the latest evidence of that was the New York RFP that I mentioned in my comments. We continue to stay disciplined. I think people are bidding into this for multiple reasons - very small returns, but maybe some branding uplift, I think has appeal 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 our cost structure going forward. More and more as 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. Two to three percent IRR is not something that we would want to win, frankly, in an RFP. We’re still targeting that mid-teens ROE for our investments.

Great. For the BOEM review schedule, I think in the slide deck you said you expect it in 2021 for both Revolution and Sunrise. I think previously you had said early ’21 for Revolution, but it looks like maybe you took out the word early. Is that intentional?

Yes, 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 offshore 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 I wouldn’t read much more into it other than new people in new roles. We’ll see what the schedule is.

For the EV and AMI dockets, are you anticipating any comments in March for those dockets? Also, is there any relationship between them or are they completely independent from the completion of the rate review docket?

They’re completely independent. Go ahead, Phil.

Go ahead, you finish.

Yes, I think the AMI is early on in the process in term of the calendar, but the electric vehicle deployment hearings are going to take place on 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 PURA.

Okay, great. Thank you very much. Thanks.

All right, thank you Michael. 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. 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.