康涅狄格電力 (ES) 2020 Q4 法說會逐字稿

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. (Operator Instructions) 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 1, some of the statements made during this investor call may be forward-looking as defined within the meaning of the Safe Harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on management's current expectations and are subject to risk and uncertainty, which may cause the actual results to differ materially from forecasts and projections. These factors are set forth in the news release issued yesterday.

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 3 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 Buth, 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 a 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 more than 9,000 Eversource Energy colleagues for their exceedingly hard work in extraordinary difficult circumstances in 2020. Not only did they 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 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 NiSource 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 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 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 2 operating companies that have struggled in recent years to earn their allowed returns. And we also maintained that track record, dating back to the 2012 merger that created Eversource, of 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 were 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 compared 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 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 a 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, continue 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 of the states of New England, which are targeting greenhouse gas reductions within their borders of at least 80% by 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 states' 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 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 are noted on Slide 11. As you can see, our South Fork project received a draft environmental impact statement, 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 a state siting decision in the first half of 2021. And on the local side, our Host Community Agreement with the Municipality in 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 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 Ørsted 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 were 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 the 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 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. And 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 the Department of Interior to conduct a full assessment of offshore wind siting processes so they are aligned with the administration's goals to advance renewable energy production.

The President has also established a White House Office on 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 commenced construction before January 1, 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 policies 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 [14] (corrected by company after the call) illustrate the recognition that we've 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 $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 $0.01 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 nondeferrable storm costs totaled $0.17 per share in 2020, compared with on average of about $0.10 per share 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.

I should note that 2020 was a very successful year for our transmission segment, placing into service more than $1 billion of investment, including 3 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 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 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 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 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 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 5-year capital plan is shown on Slide 18. It shows projected investments of $17 billion over the 5-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 are 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 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 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 pipe with a 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 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 5-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. So, Slide 21 highlights many of these. As we get clarity of these opportunities, we'll update our subsequent forecast.

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 a 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 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.

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. 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.

NSTAR 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 of New Hampshire, in addition to the permanent rate increase that took effect January 1, 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 PSNH 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 & 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 4 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 PURA 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 I, that was later vacated by the DC 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, NSTAR Electric and PSNH, 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 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 9 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 this 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 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?

(Operator Instructions)

Thank you, Brandon. Our first question this morning is from Shar Pourreza From Guggenheim.

Just a couple of 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. 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 maybe, let's say, 6% to 8% or simply a higher rebase 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 COPs.

Yes. Shar, the revised schedule will obviously give us some certainty and definitions 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. 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 CMA, 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 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 spend?

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 to bring the safety and performance of the infrastructure to the state 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, this was an asset purchase, not sort of a purchase of the company. So, 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. And then just lastly for me. Obviously, you highlight there's a couple more RFPs coming this year, likely in 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 so -- but you still do have a lot of excess lease capacity. So, 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 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?

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 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 buildout of offshore wind. So, I think we're in a very good position.

Next question this morning is from Jeremy Tonet from JPMorgan.

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-megawatts turbines originally discussed?

Yes, I'll take a shot at that, and others could add. But fundamentally, we've been talking about the lease capacity as being 4,000 megawatts, historically. When you increase the capacity of the turbines from what was an 8-megawatt turbine to 11, and as you mentioned, potentially 13 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 BOEM, when we're spacing the mile up 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 it to -- we expect to fully build it out at that level, more than 4,000 megawatts is what the guidance we're giving.

Got it. Understood. At least 4,000. That's helpful. And just want to turn over to CL&P for a quick minute here. The CL&P 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. 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 PURA will be looking at new rate designs, including possible low-income or economic development rates and it 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 commence with a full rate review actually within the next 12 months. I think it still mention the first quarter of 2022, a full review is needed.

So, our understanding -- our expectation is that any rate design changes that come out there would not necessarily be punitive to the company, especially as we continue to underearn.

Our next question is from Steve Fleishman from Wolfe.

I apologize in advance if I missed some comments related to my questions. But just 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 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 beyond for 2025, I guess, is my question.

Yes. I mean 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 hope that we expect to be in by the end of 2023. But it's clear that Revolution Wind will not be by the end of 2023, 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, clearly, a mid-'20s event and ITC kicks in there as well. So, we're not talking about the wave here. It's just the impact 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 to read more into my comments than that and step up.

Yes. 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 -- significantly improves it based upon what we're assuming for ITC at the time of our bids. As you mentioned, there's 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 ITC level was vulnerable. So, we see it as certainly as a major positive.

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

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

It's Julien here. So maybe to follow-up in order here. Can you talk about the run rate level of contribution from the offshore projects? I know that the timing 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 update, the ITC, how would you characterize that run-rate level of net income contribution, if you will?

Yes. And again, it's another way, Julien, I guess, to get at the question of providing guidance 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 earnings profile of each of the projects.

Got it. Understood. And then...

What we have said is consistent on -- is that we anticipate these projects to provide mid-teens ROEs, which would be sort of the highest of our 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 of 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 you very clearly about your equity needs and where it positions your balance sheet over the full five-year period, if I can ask more directly.

Yes, I'll ask Phil to answer that for you.

Yes. Great. I was going to jump in there, Jim. So, Julien, for the plan that we put out in terms of the $17 billion capital forecast over the 5 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 periodic at-the-market-type program. And what I suggested was that, that would be based upon what market conditions look like, what our metrics are looking like, what our -- 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, I would expect that it would be 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 slightly more definitively. This puts your metrics where from an FFO-to-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...

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 million. All right. Sorry, I don't mean to overemphasize that. I just want to make sure it's clear.

No, that's fine.

Our next question this morning is from Angie Storozynski.

So I just wanted to follow-up on the equity needs. So, the delta between the rate base growth and the earnings growth, that's purely about the equity dilution or there's some changes in realized ROEs as well?

Say that again, Angie.

Because you're saying that the rate base is growing at 8%, right? And then you're saying the earnings growth is the upper half of the 5% to 7%, right? So, let's just say, 6.5%, right? So, I'm trying to understand it, the delta between 8% and then, say, 6.5% is solely a function of the equity dilution or is it some, I don't know, assumed lower ROE or something to that effect?

No. It's primarily the equity issuance would be the driver there. I mean, even for 2021, you have to keep in mind that, as I mentioned in my comments, we closed out a forward contract in March, and then we had additional shares that we issued in June. So, all of those now get into a full year of 2021 that didn't impact us in 2020. And then as we do the treasury shares and move in the $700 million that I discussed, that would be the primary mechanism that would be causing the difference.

Okay. 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 that you're going to be working on incremental CapEx updates. But can you give us a sense how big of a delta we could see there? Is it doubling of the $275 million a year? Is it just some tweak to the current CapEx estimate that you'd expect?

Well, that process, as I said, 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 that identifies that. So, I'd say it's a little premature to speculate on what that might look like.

In terms of sizing, we're certainly active in terms of looking at that right now. I'd say that we've not been -- there's been no surprises in terms of taking the keys. 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 we're just not at the final stages of that assessment so that I could give you a good answer.

Okay. The only thing I'd add is that, as Phil mentioned earlier, in that $275 million, we have some one-time items over the next couple of years to fully integrate the shared service functions that are currently being supported by NiSource 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 maybe less aggressive, but still electric-driven construction in the state. How do you see it impacting both your electric utility and gas utility in the state with -- I mean, it is a Republican Governor who seems to be pushing for less natural gas connections for new build -- new construction?

Well, I think first of all, both our gas and our electric business in the state of Massachusetts operate under a decoupled rate regime. So, to the extent volume goes up or down 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 businesses and homes in Massachusetts heat with oil. And there's a significant improvement, if you don't go to electric, but even go to gas, the emissions uptick on -- improvement, if you will, is significant. So, I think we'll work with the state as we work with the other states to make sure that we can aggressively decarbonize the supplies, but we're comfortable with where that legislation is. And as Phil mentioned, one of the components 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.

Next question this morning is from Durgesh Chopra from Evercore.

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 tariff that you mentioned? So, what is the time line? And what should we be sort of looking for in terms of calendar?

Jeff, I don't know, do you have any specifics there, the calendar on that proceeding? I know we're early on in the process.

Yes. We put the docket up, but I don't think there's really any, 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?

Sure. The remaining schedule there is, I think, the reply briefs are actually due this week. I think, we would expect the tentative decision about a month later, so mid-March. Written exceptions would probably follow that a few weeks later. And then oral arguments, maybe mid-April with the final decision on the 28th.

I think PURA is investigating the prudence of the costs. We're confident that the -- 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, the cost recovery would be allowed for these costs as they are prudent.

Next question is from Ryan Levine from Citi.

A couple of 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 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 mean, I thought there was some component of that 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 kind of roughly about an 80-20 split. So, you kind of look at the total CapEx, about 80% of that will be the offshore piece 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 it to that onshore piece, that's deemed onshore.

And is that 80% statistic 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 kind of depends on how we look at where we're going to land and how we look at kind of the profile that's out there with what we build in the lease area.

Next question is from Nick Lubrano from BMO Capital.

It's James Thalacker, actually. Real quick question. Just, I guess, just confirming, it doesn't sound like the equity needs that you are 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've got a pretty large rate base growth at the Columbia Gas business right now. Is part of the reason that your equity needs aren't 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 settlement?

Yes. I'd say that 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, things like that. So, because of the timely tracker cash recovery, that is very beneficial.

Next question is from David Arcaro from Morgan Stanley.

A couple of quick ones. So, I was just curious on offshore wind. To the extent there are items that improved 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 a 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 up in our geography for that technology.

Next question is from Travis Miller from Morningstar.

I just want to follow up on an earlier question, I think, it was Angie's question about that 8% rate base CAGR and then the earnings guidance of 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 that side. Just wondering if you could take us through some variables that might get you to the lower end of that range?

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, 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 in terms of AMI or additional grid modernization and those are more things that can take you to the higher end of the range.

Certainly, how you do as a company, any company does on their O&M management is important. And I think you might agree that you can't really find anybody better than Eversource in controlling costs. So certainly, if there's cost O&M pressure, that could move you around in the range. So, I think those are some of the bigger variables that could move you into 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.

Great. That's helpful. And then real quick on electric vehicle charging. If you look out over the 5 years, you had mentioned a 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 chargers in the state of Massachusetts, and we're finishing up a 3-year program that brings that number up to 5,200. But the targets in Connecticut and Massachusetts, both have for 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 focus on distribution build-out for these charges, and I wouldn't expect any near-term transmission needs created by that growth.

Next question is from Paul Patterson from Glenrock.

Certainly 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 storms and stuff. But if we would look like on sort of this level, I mean, 2021, I know you're not giving guidance for 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?

Paul, this is Phil. The last filed -- we filed sort of on the quarters in Connecticut was about 8.6%. We're allowed 9.25%. So, we're certainly below the allowed return in the settlement that we had. So 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 Isaias were deferred because there're triggers that if you're above $4 million in Connecticut, you defer the cost. So, we'll be disclosing -- 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 100-plus other storms, and some of those don't trigger a deferral. So, those would impact all franchise -- all electric franchise ROEs.

Okay. That's great. That's helpful. And then also just on the CLP transmission CapEx, 2021 and 2022 seemed like they jumped a lot over your last forecast. And I was 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 was 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 CL&P. 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 from 2021 and maybe it went from $209 million to $443 million. And for 2022, $184 million to $264 million. I can follow-up later. I mean, I'm not -- but that's what I -- it just looked like to me like there was a -- it could be timing too or something, I don't know. Anyway, I just -- I was wondering if there's anything in particular.

And then 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 -- I mean, 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 have delivered? Or I just wanted to sort of get a sense as to how it works since basically, what -- but maybe think about this, of course, is what we're seeing in Midwest and stuff?

Yes. I guess 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 many incentives to -- the power plant operators to prepare for the winter. They have an electric grid that put an emphasis on cheap prices over reliable service. In New England, as you know, we have a robust capacity market where the ISO locks in adequate supplies to maybe 4 or 5 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 are dealing with, I think, either the nuclear unit went down, but the gas plant were probably 5 or 6x the load that was lost in wind. I think wind is only 10% of the load in Texas.

I hear what you're saying. I'm not suggesting that there's some particular issue with it. I was just wondering, though, if -- 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 want to...

Yes, it's the former. 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.

Next question is from Mike Weinstein from Crédit Suisse.

A couple -- one more question on offshore wind. CEO of Total today came out and said that the IRRs on offshore wind are very -- like most competitive than the entire renewable industry, 2% to 3% IRRs. Is that something you guys are seeing as well in your analysis of your -- the project opportunities from 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. And 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 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 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. 2% to 3% IRR is not something that we would want to win, frankly, in an RFP. We're still targeting that mid-teens ROE for our investors.

Right. 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?

Yes. I don't think it's essential. 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 rates -- into their roles rather. Clearly, the Biden administration is supportive of offshore wind and accelerating the approval process. But you have 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 won. So yes, I wouldn't read much more into it other than new people, new roles. So, we'll see what the schedule is.

Great. And then for 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?

I think they're independent -- go ahead, Phil.

Go ahead, Jim. You finish.

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

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.