Eversource Energy (ES) Q1 2020 Earnings Report, Transcript and Summary

Welcome to the Eversource Energy Q1 2020 Results Conference Call. My name is Richard, and I'll be your operator for today's call. [Operator instructions] Please note that this conference is being recorded. I'll now turn the call over to Jeffrey Kotkin, vice president for investor relations for Eversource Energy. Mr. Kotkin, you may begin.

Thank you, Richard. Good morning and thank you for joining us today. I'm Jeff Kotkin, Eversource Vice President for IR. During this call, we'll be referencing slides that we posted last night on our Web site, and as you can see on slide one, some of the statements made during this Investor Call may be forward-looking as defined within the meaning of the Safe Harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on management's current expectations and are subject to risk and uncertainty, which may cause the actual results to differ materially from forecasts and projections. These factors are set forth in the news release issued yesterday. Additional information about the various factors that may cause actual results to differ can be found in our Annual Report on Form 10-K for the year ended December 31, 2019. 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 Phil Lembo, our Executive Vice President and CFO. Also joining us today are Joe Nolan, our Executive Vice President 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. We are generally speaking from different locales this morning across Massachusetts and Connecticut. Now, I will turn to slide two, and turn over the call to Phil.

Thank you, Jeff, and we all hope that everyone on the phone is healthy and remains healthy and that your families also are safe and doing well. This morning, I'll review the results of the first quarter. I'll talk about our efforts to build and operate in our critical electric and natural gas and water infrastructure during this COVID-19 pandemic. I'll talk a little bit about the recent regulatory developments, and finally, provide you an update on our offshore wind investment partnership with Orsted. I'll start with slide two, and our significant and comprehensive efforts to deal with the impact of the coronavirus. Our country and our region, I guess, it's an understatement to say we're in the midst of an incredibly challenging period, and Eversource, as a provider of critical services for nearly half New England, is taking its responsibility to its customers and its employees extremely seriously, and as you know, Massachusetts and Connecticut are two of the states most impacted by the virus. More than 100,000 cases have been confirmed across those two states and an additional 2,600 in New Hampshire. Our priority is at Eversource start with the health and safety of our employees, our customers, and our communities. We're closely following the guidance provided by the CDC and local health authorities in our daily work activities. Although we are actively accomplishing all of our essential work, we have suspended certain less time-sensitive work, such as upgrades to our own work centers and offices, as well as, some work interior to customers' locations for energy audits and alike. We've undertaken extensive efforts to expand our facility sanitizing efforts, and have enhanced the availability of personal protective equipment, including face coverings and masks, so our employees can continue to maintain our energy systems in a safe manner. We took early and aggressive actions in accordance with our well-defined pandemic action plan, and we have continuously refined and adjusted our playbook as we moved through the situation. Nearly all of our employees who normally work in an office setting are working remotely; a practice that's been in place since early March. Approximately 4,500 employees continue to work in the field to support the reliability and safety of our energy and water delivery systems, but significant changes have been made in their work patterns as well. They've been able to receive their daily work assignments without having to enter our buildings. Their line trucks and other vehicles are disinfected before and after every shift. Employees traveling in Eversource vehicles are now driving one-person per vehicle, where we previously had a two-person, it's one-person per vehicle, and when at the work site, maintaining a six-foot social distancing and face coverings when conditions require them, and those are all enforced as standard work practices. We've been very clear in our communications that if any employee feels ill, they should stay home, while also implementing temperature checking and other health screening before anyone enters our electric and gas control rooms. We're equipped to initiate a quarantine process early line to isolate those who potentially were exposed to COVID-19, either at work or at home. We believe this has been a very positive -- has resulted in very positive impacts on our ability to minimize the spread of the virus to others. To date, more than 400 employees have returned to work following their quarantine period in medical clearance. To date, we've had 30 employees who have been confirmed positive for COVID-19, and actually, 18 of those are now back to work. We've successfully maintained our high level of service and safety and also kept up with the necessary pace to achieve our capital investment work program for the year. I'll talk more about this in a minute. When we have experienced significant weather events, we were able to deal with them safely, promptly, and effectively. A mid-March heavy wet snowstorm resulted in more than 56,000 New Hampshire customers losing power, but crews from all three states responded and restored power within 24 hours. Also an intense Nor'easter battered our service territory and many others on April 13, but we were able to restore power to nearly all of the 240,000 impacted customers within the first 24 hours after the storm hit. There are many other areas where we changed our traditional practices to accomplish key work during the pandemic threat. We've moved all electronic permission-gathering programs for our annual clearance program in Connecticut. We held our first virtual annual meeting yesterday. Above all, we continue to execute our business plans and strategy successfully. As shown on slide three, our total return through the first four months of the year compares very favorably to our peers and to the broader market. This follows our very strong performance in 2019 and the three-year, five-year, 10-year total returns that far outpaced both the EEI index and the S&P 500. In this period of uncertainty, our business model resonates very well. Well over 90% of our business is revenue-decoupled. We have pension recovery trackers for our FERC transmission and Massachusetts distribution businesses. Much of our capital improvement program is tracked and we are operating under multiyear rate plans for our three largest distribution franchises. Additionally, under existing approved mechanisms, we recover all bad debt associated with power supply or medical or financial hardship accounts. We continue to receive strong support from our customers, regulators, and policymakers in the face of this unprecedented challenge. Last week, Connecticut regulators issued an interim decision that calls to utilities to offer payment programs during the COVID-19 crisis that are available to any customer requesting financial assistance. Requiring no initial down payment and have a duration of 24 months and waive any fees or interest in calculation of the monthly payment amount, essentially what we've already been doing. Recognizing the possible increase in utilities receivable balances and bad debt expense, the Connecticut Power directed utilities to maintain a detailed record of these costs incurred and revenues lost as a result of implementing its orders, and said it will allow utilities to establish a regulatory asset to track incurred costs. These costs will include working capital costs which will be calculated in accordance with the utilities' most recent rate case. However, as you can see on slide four, there has been some impacts on our regulatory dockets. In New Hampshire, the electric rate case schedule has been delayed. We were originally scheduled to receive a final order in May and implement permanent rates on July 1st, 2020, but the governance executive order in late April now provides the New Hampshire PUC additional time, or up until November, to issue a final decision in our first general rate case in a decade in New Hampshire. As you may recall, that Public Service New Hampshire implemented a temporary $28 million rate increase effective July 1st, 2019, that increase will remain in effect until permanent rates are set at the end of this case and any difference between the temporary rates and the permanent rates will be reconciled back to that July timeframe. So, the delay will not affect the earnings over the long-term. In Massachusetts, we agreed to a one-month delay in our NSTAR gas rate case. So the decision is now expected at the end of October, 2020, with rates effective on November 1. Since the transaction for Columbia Gas was announced shortly after our year-end earnings call, we've not had the opportunity to review it with many of you on this call. The key elements of our deal are reflected on slide five. We are acquiring the assets of Columbia Gas of Massachusetts, not any of the liabilities associated with the tragic September 2018 incident in the Meramec Valley. We'll pay $1.1 billion for the net assets and assume none of the company's debt. The $1.1 billion is 1 times rate base. The transaction has received extensive support within Massachusetts and we are highly confident it will close. We believe the transaction is an excellent one for customers, as Columbia Gas customers will now become part of a larger, well-respected local owner. We expect the transaction to be immediately accretive and continue to be accretive over the coming years. As we complete our integration and transition to our -- excuse me, transition to our operating systems at Eversource, as well as, making needed investments in the infrastructure to provide safe and reliable service. We expect to file the application with the Massachusetts Department of Public Utilities shortly. We filed in March with the U.S. Justice Department for review under the Hart-Scott-Rodino Act, and the 30-day waiting period expired a couple of weeks ago. We expect to finance the $1.1 billion initially with a combination of debt and equity issued at Eversource parent. The percentage or the ratio of that financing will be roughly equivalent to the capitalization ratio on Eversource as a whole. The precise timing and size of the equity and debt will depend on market conditions as we go forward. Over time, we expect the new gas company to issue its own debt, most likely in the private market, the same way that NSTAR Gas or Yankee Gas currently raise long-term debt capital. Turning from Columbia Gas to slide six, we raised approximately $1.2 billion of cash in the first quarter. We sold $350 million of 30-year notes at Eversource parent and $400 million of green bonds at NSTAR Electric. Additionally, we closed out the forward element of last year's $1.3 billion block equity deal; we did that in late March, bringing in an additional $420 million in cash, and today, just today, we're closing on $190 million first mortgage bond offering at NSTAR Gas. Now, the new issuance will help repay short-term debt that was incurred went $125 million, 4.46% NSTAR Gas bond matured in January. And the new issuance was at very attractive rates versus that 4.46%. Our cash position is further enhanced by the fact that we have only $25 million of maturities remaining over the balance of the year 2020. Eversource and NSTAR Electric continued to meet their daily liquidity needs very effectively in the commercial paper market, although borrowing rates increased late in the first quarter, rates today are well below those average first quarter levels, which bodes well for short-term debt interest expense going forward. Our capital program remains on track for the year. As you can see in a slide in the appendix, we continue to project capital investment of approximately $3 billion in 2020. In large part because of the very mild winter weather, we had a very strong start for the year, with reliability enhancements and system improvements totaling $600 million in the first quarter of 2020, compared with about $550 million in the same period of 2019. Due to the critical nature of our infrastructure and regulated investments, we have continued to work safely and effectively throughout the stay-at-home requirements in place over our three states. Regulators recognize that some long-term initiatives will need to move forward to ensure that we have a grid capable of serving our customers' increasingly sophisticated needs. A new three-year grid modernization work plan for 2021 through 2023 will be filed in Massachusetts this summer. Just yesterday in Connecticut, Connecticut regulators issued an order requesting proposals on program designs for a number of initiatives related to grid modernization. They include such topics as advanced metering infrastructure, energy storage, and zero-emission vehicles. Proposals are due in -- by the end of July, July 31st. We have included Massachusetts grid modernization expenditures in our five-year forecast, but we have not included grid modernization work in Connecticut in that forecast. So, now let's turn to first quarter results, and that's on slide seven. We earned $1.02 per share in the first quarter of 2020, excluding $0.01 per share of expense related to our acquisition of the assets of Columbia Gas of Massachusetts. In all segments, the higher share count partially diluted the benefits of higher net income. In total, the share dilution for the quarter was $0.04. On so in each segment, let's go through that. Earnings for our electric distribution segment were $0.39 per share compared with earnings of $0.38 per share, a $0.38 per share in the first quarter of 2019. The increase is primarily related to higher distribution revenues, partially offset by dilution and higher depreciation, interest and property tax expense. The transmission segment earnings rose to $0.38 per share in the first quarter of 2020 from $0.37 in 2019. The higher earnings primarily reflect an increased level of investment in our transmission facilities. Earnings from our natural gas segment totaled $0.25 per share in the first quarter of 2020 compared with $0.24 per share in the first quarter of '19. Higher distribution revenues were partially offset by higher O&M and higher depreciation expense. Earnings in our water business were $2.1 million in the first quarter of 2020, up from $0.9 million in the first quarter of '19. Improved results were due to higher revenues from capital-tracking mechanisms and lower depreciation expense in Connecticut. A small first quarter loss at Eversource parent of $0.01 per share in 2020, and that's exclusive of the acquisition charge, compares to a loss of $0.02 per share in the first quarter of '19, and this was due in part to lower interest expense. As you saw in our news release and on Slide 8, we continue to project earnings per share in 2020 of $3.60 to $3.70 and we continue to foresee earnings growth through 2024, around the middle of our 5% to 7% range, based on our regulated core business. Earnings from offshore wind and Columbia Gas of Massachusetts would be incremental to our long-term guidance. Turning to offshore wind in slide nine, there have been a few developments since our year-end call in February. On March 13th, we filed our construction and operations plan, or COP, with the Bureau of Ocean Energy Management for the 704-megawatt Revolution wind project. So, BOEM's review of that project has begun. We expect to have a full schedule for that review later this year. We have not yet received a new schedule from BOEM on its review of the 130-megawatt South Fork project. The COP on that was filed back in 2018 and -- but the process was paused last year so that we could update the project for our new one nautical mile by one nautical mile configuration. We expect the new schedule to be posted by midyear. Additionally, due to travel and meeting restrictions stemming from the COVID-19 pandemic, the administrative law judge overseeing the New York Public Service Commission review of South Fork has extended the near-term schedule, adding another 10 weeks until the state hearings can begin. As a result, [intervenor] [Ph] testimony will be due in early August, and hearings are now to commence at the end of September. As a result of these items and as Orsted said on its call last week, these delays will make it very unlikely that the South Fork project will enter commercial operation by the end of 2020. We continue to have a target filing date on our COP for Sunrise Wind with BOEM in the second half of this year. That timetable may affect -- may be affected by New York's current restrictions on both onshore and offshore survey work. We expect to have more insight into the timing of that cost filing and the schedule for Sunrise by late this summer. Despite these near-term scheduling headwinds, we remain strongly convinced that the opportunities in offshore wind off the Northeast coast are excellent, with 15,000 megawatts likely to be built over the coming years to supply the significant clean energy needs of New England and New York. Our partnership with Orsted has won more than 1,700 megawatts of offshore wind contracts across the region. As any future RFPs are issued, we will continue to evaluate those opportunities and will exhibit the same financial discipline we've demonstrated time and time again for many, many years. We continue to view offshore wind initiatives as a unique and very positive opportunity to provide clean energy and significant economic development stimulus to the region while providing investors for a very attractive long-term earnings and cash flow benefit. Let me emphasize that the earnings from offshore wind are incremental to the 5% to 7% EPS CAGR that we expect on our existing regulated business. Our regulated business model works because of the constructive regulatory environment we operate within and consistently high levels of execution we've achieved. This model is particularly attractive in uncertain times, such as where we are today. I want to emphasize that a critical factor in our success over the past decade has been providing excellent service to our 4 million customers. This is accomplished by having a tremendous team of 8,300 employees who have a singular focus on providing safe and reliable service to our customers and addressing the energy policy imperatives of our region. I'm very proud. I'm very proud of the early aggressive actions we took as a company over the past several months to protect employees, customers and our communities. I'm very grateful for the dedication, innovation and passion our employees have demonstrated as they have continued to work safely and effectively to execute our essential work on behalf of our 4 million customers, and as if the pandemic wasn't enough, they've also been called upon to respond very quickly to two significant storm events that blew through our three states over the last few weeks, and although the pandemic situation remains uncertain, Eversource is very well-positioned to be successful. We remain committed to the care and safety of our employees, our customers, and communities, while we continue to execute the essential services that our customers expect. Most importantly, I wish all of our listeners today and their families of safe and healthy spring, and I look forward to coming out at the back side of this pandemic as soon as practical and seeing you all again. Thanks again for your time. I'll turn the call back over to Jeff for Q&A.

And I'm going to turn the call over to Richard, just to remind you how to enter questions. Richard?

Thank you. [Operator instructions] And we're standing by for questions.

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

Hey, it's actually Kody Clark on for Shar. Good morning.

Hey, Kody.

Good morning.

So, first on the offshore wind solicitation in New York, is that still on track for the second-half of this year, hasn't seen any headwinds given the COVID situation?

I think that's the expectation that's out there, although nothing -- no official schedule has come out, but I think that the direction is clear that that's where the state would like to go but final dates haven't been established yet.

Got it, thank you, and then, could you give some color on how you're thinking about any water deals outside of New England? Are you seeing an increase in opportunities given the current macro backdrop?

I think the current macro backdrop really emphasizes the importance of -- to me, the issue of size and scale and the ability of a company to have the financial capabilities to -- for its liquidity, we're able to access capital markets, its ability to respond to storms when you have a pandemic going on. So, certainly, there may be some smaller entities that are out there that may find that it's difficult to move forward in a world like that where there's uncertainty, so that there could be opportunities there. Going forward, there's nothing that is in front of us at this moment, but I can assure you that the water business is a business that we like. The water business is one that we see as very synergistic to our electric and gas businesses and it's one that we think that we can operate very effectively going forward, and whatever comes in front of us, we'll be disciplined about whatever financial characteristics are associated with a deal like that, as well as, making sure that there's benefits for customers. So nothing in front of us right now, but given the situation that's out there, you could see some smaller companies look for a way out.

Great, thanks so much. Congrats on the quarter and stay safe.

Thank you. You too.

Thanks, Kody. Our next question this morning is from Sophie Karp from KeyBanc. Good morning, Sophie.

Good morning, guys. Congrats on the quarter. Thanks for taking the question.

Thank you, Sophie. I hope you're well.

Yes. I was just curious if you could comment on the volume trend, even though you decoupled, but just to get a sense of what kind of what you've seen in the service sector as far as the economic hurt that's been experienced by the rate peers.

In terms of sales volume trends, is that your question, Sophie?

Yes.

Yes. So I will say that sales in the first quarter were down, both -- you'll see that on the electric side, they were down close to 6% and on the gas side, nearly 14%. And I'd say 95% of those numbers are due to the incredibly mild weather we had in the first quarter. It's nothing to do with rail COVID impacts. We really were only a couple of weeks into COVID in the first quarter. I mean, in the weather in the first quarter in our service territory was -- the heating degree days were the lowest in 50 years. That's five zero. They're about 18% or 19% below the previous year and below normal. We have the longest January in 90 years. There's probably a hundred different statistics that can -- so the one benefit, as I mentioned, was it enabled us to execute very well on our capital plan, but it didn't do much for us in terms of sales. So that's really what we've seen there. I will say kind of going forward, April was actually pretty cool here in our region. So in a strange way, even though it's a shoulder month, I would expect maybe our gas business sales to be up in April despite COVID. I do think what you're going to see is a downward trend or downward pressure on the commercial sales, but where everybody is working at home, probably some upside benefit on the residential sales in the electric business, but as you suggest, folks should keep in mind that well above 90% of our revenues are not associated with sales that decoupled. And so, we have on the distribution side, and certainly, the transmission revenues are not association -- not associated with sales volume. So from a regulatory protection and program standpoint, we're in good shape, but the trends are as I described.

Right. Thank you, helpful color. And then on NSTAR rate case, I'm just curious if it's -- it's been delayed by a month, right? Is that important for you as far as guidance and your projections, that you have those rates in place before the winter season begins, or is that not sort of material enough for guidance? Just how should we think about that in case there are future delays?

Yes. It's not material enough. I mean, we expect that the new rates will be in place, as I mentioned, that there is just a one-month delay and we're optimistic that we'll be hitting that target well ahead of the winter heating season. And really, the winter heating season is just getting started at the end of the year. So we're expecting the order to come out, as we've described, with a one-month delay, but if it didn't, we don't see that as being material to the guidance.

Got it. Terrific, thank you, this is all for me.

Great, thank you, Sophie. Our next question is from Mike Weinstein from Credit Suisse. Good morning, Mike.

Hi. Good morning, guys.

Hi.

Good morning.

And I just wanted to confirm, my understanding is that also wins, even if there are delays, right? That your guidance, your long-term guidance, growth rate is not affected by that, right? The offshore wind has always been additive and incremental and the long-term guidance for EPS growth is really based on just the utilities in isolation. Is that right way to think about it?

That is correct, Mike. Your understanding is absolutely correct. The 5% to 7%, and being in the middle of that range is from our core regulated business, offshore wind is -- would be incremental to that.

Is there any impact on financing plans? I think you've already issued all the equity in the five-year plan, right? So is there any impact at all in financing plans from any potential delayed projects?

No. If I heard you correctly, I think you may have said we've issued all of the equity from our long-term projections on that. We talked about issuing $2 billion of equity last year. We issued $1.3 billion. So we still had some of equity left over to issue during the remainder of our long-term plan. So, we'll be opportunistic about that and do that when the spending dictates. So, if we're not spending the money, that's going to make an impact on the timing of when we do any kind of financing.

What's left? Is the ATM plus -- the ATM portion of equity?

Yes. We said that the $1.3 million was the only block equity per se in our forecast, but I do want to be clear that subsequent to that guidance, we did announce the acquisition of Columbia Gas, and we will do equity and debt associated with that transaction.

Right. And that timing is this year, right, [indiscernible]?

Yes. That timing depends on the market conditions, but yes, this year, we're expecting to close on that transaction later on in the third quarter of 2020.

Got it. Have you gotten any sense as to any potential changes to grid monetization priorities as a result of COVID? Now that I understand those dockets are going on right now. The one in Connecticut is ongoing, but is there any sense of maybe that priorities might be different currently as a result of the crisis that we're all going through?

No. My personal sense there would be that programs that emphasize social distancing and technology would be even more value to customer and to the grid. So that -- what fits into there could be AMI, obviously, that there's nobody out there even driving around, or you've got much more visibility of the system to its furthest reaches with an AMI-oriented system. That certainly would be a way to improve, I guess, our social distancing, but I don't -- there's nothing -- there's no dramatic changes at this point in terms of the focus on grid mod. AMI has been part of the discussion anyway in Connecticut, and as I mentioned, Connecticut is moving forward, and we should see some program designs and proposals by the end of July time frame.

Great, Okay, thanks very much.

Thanks, Mike. Our next question is from Caroline Bone from Evercore. Good morning, Caroline.

Good morning, guys and thanks for taking my questions. And I also just wanted to say thanks to all of your employees for all of their hard work right now. We're all at really grateful.

Thank you, Caroline. That's very nice of you.

So, my first question is really on Columbia Gas. I was wondering if you could comment on what sort of spending you're anticipating going forward on these assets, and apologies if I missed this earlier in the call, I just want to get a sense of how that impacts your long-term capital plan.

Well, as I said, the -- Columbia is really not in our guidance at this point. So, as we move through the approval process to closing, then we'll include that in our plans going forward, but I would say, if you just look at what we spend in the gas business, on the Yankee Gas or in Massachusetts already on NSTAR Gas, the capital spending programs are somewhat higher than they are currently at Columbia. So I would expect, once we get through our process and all the integration efforts and we put everything all down on paper, that you're likely to see some higher capital spending requirements on that system than is currently historically existed.

Okay.

The other side of it is as we look at integration efforts, we could -- we'll be incorporating some of the, I'd say, corporate service activities into Eversource. So, there could be some savings there, but I would expect on the capital side that the plans would be increasing from the previous plans that -- on a normal run basis of Columbia that they've had in the past.

Okay. That's very helpful. And then my other question is just, do you guys expect these potential delays of the larger offshore wind projects to impact capital cost? Or is it really too early to say at this point?

I'm sorry, Caroline, I didn't catch that.

On the offshore wind, the Sunrise that might be delayed, do you expect that to impact the capital cost for that project?

I didn't talk about Sunrise. I will say that South Fork, and I may have said 2020, I'm not sure, but…

Oh, no. Yes. Okay. Sorry, I thought like I said on the slide, it kind of implied that Sunrise might -- could be delayed as well.

We're going to file the COP in the second half of this year and then a schedule will come out. So that those schedules are not -- dates are not changing. It's South Fork where the commercial operation date, we had expected to be the end of 2022, that given the COVID situation, et cetera, it's unlikely that that will happen at the end of 2022, but no change in the other dates at this time.

Oh, got it. Okay, that's helpful. That's it for me. Thanks so much guys.

Thanks, Caroline. Stay well.

Thanks, Caroline. Appreciate it. Next question is from Julian from Bank of America. Good morning, Julian.

It's Alex Morgan calling in for --

Hey, Alex.

Thanks so much for taking my question. Hey, congrats on the results.

Thank you.

My first question is about Connecticut AMI. I know you spent a little bit of time talking about it with the prepared remarks. I was wondering if you could potentially take it a little step further and talk about what the potential time line on this could be and maybe your expectation on the size of the first six of the RFPs.

The -- what we've said in terms of AMI has been that a full rollout of AMI in Connecticut and Massachusetts is about $1 billion. And we have -- and that's electric and gas and we have about the same amount of customers in each state. So even if you assume that that's a 50-50 split on that. So it's a program that would be a significant improvement in terms of visibility to the grid. It would be a significant opportunity for us to better able to manage distributed energy resources on the grid, and it would be, I think, a customer satisfier, and it is part of the -- as you point out, of the ongoing discussions, probably ahead in Connecticut than where it is in Massachusetts right now, although, Massachusetts will likely take up something to do with AMI in the near term. So, in Connecticut, I can't give you any more specific than that other than it is on the agenda. Plans are being formulated and being filed in those first areas of interest for the Connecticut regulator, which are really, advanced metering infrastructure is one of the items, so that, along with energy storage and electric vehicles. So, I think you'll start to see more unfold on that as we get through the summer and into the year.

Okay. Thank you. And my second and last question is just a little more detail on the South Fork offshore wind project. I was wondering if you could talk through maybe some of the almost pros and cons of the project potentially being delayed because of COVID and BOEM. My expectation on the positive side would be you could share vessel CapEx with, potentially, Revolution Wind, but on the negative side, I was wondering how that might impact your contract details with LIPA and if there's any ability for that price to be renegotiated or revisited. And that's it from me. Thank you so much.

Thank you. Thank you for those questions. As you suggest, in terms of their sharing vessel plans and vessel CapEx could be a potential benefit. Also, larger turbine sizes as we move forward could be a potential benefit that would require less poles in the -- to be erected in the ocean. So there could be some benefits there. The contract terms that we have on all of our offshore wind contracts allow us some time to -- because of delays that are caused outside of our control, like at BOEM, or in this case, you've got a pandemic adding to it. So, we feel very comfortable with the provisions that are in the contracts that would enable us to move the dates in a way such that we can still deliver the power according to the term of the contract, and we could see some benefits, as you point out.

All right, thank you so much. Thanks, Alex. Our next question this morning is from Neil Kalton from Wells Fargo. Good morning, Neil.

Good morning. Thanks. Two quick questions on offshore. First, I have it in my notes that the plan to make about $300 million to $400 million in investment this year in offshore. Is that correct? And then, should we think about that as being substantially shifted out, given the delays? And then second, any further thoughts about involvement in future offshore lease auctions going forward?

Thanks for those questions, Neil. I hope you're doing well. You're right that in our disclosures and in the 10-K, we talked about our capital program. And then, we also included some guidance that talked about $300 million to $400 million on offshore wind. Certainly, if there are -- it would be -- some of those costs, I would expect, would get shifted out of this year into subsequent years. So, either you could see us be at the lower end of that range at a minimum and maybe potentially under the low end of that range, but those details would be worked out once we move a little forward more forward during the course of the year. So, in terms of future auctions, as you know, there were auctions a year or so ago. That other bidders paid a significant amount of money to acquire above a price that we and Orsted felt was appropriate. So certainly, in New England, or if there are additional opportunities within those New England leased areas, we'd certainly take a look at it, but again, I can't emphasize enough that we would use the same financial discipline that we've always demonstrated in terms of our bidding for those.

So just a quick follow-up, so you said New England. Would you look at New York or no?

Right now, we're focused on the New England leases, Neil.

Right, thank you.

Right. Thanks, Neil. Our next question is from Paul Patterson from Glenrock. Good morning, Paul.

Good morning.

Good morning.

Good to hear things are going well for you guys. Listen. So I just -- a lot of questions have been answered. Just sort of if you could give a little more flavor on the bill payment experience you guys have seen in the last month or so in terms of your customers, and if there's any regional or any significant difference between the types of utilities and how people are paying their bills or not.

Sure, Paul. And again, I hope you're doing well. I'd say we -- I feel very good about the regulatory constructs that we have in place in terms of delinquent accounts or delays or bad debts as you might want to call it. We have already in place mechanisms for hardship cases. So, people who fit different medical or income-oriented criteria already fall into kind of these hardships receivable categories. So, across Massachusetts and Connecticut, we have abilities already in place, sort of pre-COVID, to collect on these. So we feel good about that. And as I mentioned, we've had recently in Connecticut, an order coming out that would indicate we should collect all the costs and defer them for future recovery for incremental costs associated with COVID, and we have done some filings in Massachusetts and New Hampshire with sort of similar information in them. So I feel good about the regulatory mechanisms that we have in place. So I do think that each company across the country probably has differences, and I feel very good about what we have in place. In terms of our experience, I'd say that it's still a little early to tell, but we have implemented these long-term rate repayment plans. As I mentioned, in Connecticut, now those plans can go for 24 months, but we've set up -- we're not charging late fees. We're not shedding customers off and we're allowing them to be on flexible payment plans. We have not seen a significant reduction in customer payments. Our customers are doing a good job in terms of paying the bills that are sent out. So we haven't seen a significant deterioration, at least over the last month or so.

Answered too, thanks, again, have a great one.

Thanks, Paul.

All right, Paul. Thank you. Next question is from Travis Miller from Morningstar. Good morning, Travis.

Hi, how are you?

We're good, thank you.

I was wondering on that Columbia acquisition, how do you think about financing that $1.1 billion up at the parent level? I know you'll keep the utility structure the same, but how do you think about that at the parent level?

Good morning, Travis. I hope you're doing well. Thank you for your question. The -- how we think about it is to finance the $1.1 billion sort of in line with what the Eversource capital structure is. So, a combination of debt and equity would be issued there. Going forward, as I mentioned that the issuances going forward at that entity would likely be in the private market for debt, similar to how we finance the gas companies now under the Eversource family. So initially, the financing would be at the parent, but that -- just like all of our other franchises, they do their own sort of debt financings and they get their equity capital from the parent. So this will ultimately be no different.

Okay. And then, just to be clear on that equity side. So that's $2 billion plan obviously didn't include the Columbia potential equity financing, right? So --

That's correct.

So you'd have the Columbia acquisition, equity financing, plus that kind of $700 million, and then, plus anything that you'd want to do on the equity side for the offshore winds whenever material amounts of cash gets spent end of this year or next year. Is that the way I'm thinking about it correctly?

I think you've added one too many pluses in there. So let me clarify that the only thing in our plan is the remainder of the $700 million from the original $2 billion of equity that we announced last year. We executed $1.3 billion of that. We have $700 million and that -- so that's the base plan. And then with the acquisition of Columbia, that would be kind of a 60-40-ish. That's sort of the capital structure now, 60% debt, 40% equity -- let's call it 45-55 is probably the better, more precise, information: 55% debt, 45% equity. We're looking to finance the acquisition of Columbia along those lines, but that's it.

Okay. And then offshore winds, would you'd be able to fund out of cash flow to the extent that you had any kind of cash on that later this year or early next year?

Yes. It would finance that in our current forecast period, that's correct.

Okay, great. Just one quick technical question, on that -- the revenue decoupling you have, is there a difference when you think about and go back to regulators in terms of weather versus COVID-19 impacts? Do those fit in two different buckets in terms of decoupling, or is it just full demand decoupling?

There's no difference in the buckets. It could be for any reason, economic, weather, or otherwise. So, it's full decoupled.

Okay, great. Appreciate it. Thank you.

Thank you, Travis.

Thanks, Travis. Next question is from Andrew Weisel from Scotia. Good morning, Andrew.

Hey. Good morning, everyone.

Good morning.

Just want to clarify some of the stuff you just talked about there. If I remember correctly, the offshore financing plan was -- I'm going to paraphrase here, but the idea was you kind of had one project coming online in gear, the cash flows from revenues from the first would finance the second, and that would sort of trickle forward. My question is, if South Fork is delayed, who knows by how long, is there any kind of a short-term bridge issue where you'll need cash to finance Revolution Wind's construction before South Fork is actually generating revenues?

No, that's not anticipated. If you recall, South Fork is a fairly small in size project. It's 130-ish megawatts versus Revolution Wind being 700 and Sunrise 880. So, the South Fork for project is really sort of the smaller of the cash requirements and smaller of the cash receipts also. So no, we don't see any bridge issue there.

Okay, great. Then next on the slide showing progress on major transmission projects, slide 12, the Eastern Massachusetts completion date moved forward by a couple of years to 2023 and some smaller delays for a couple of the other ones. Can you just talk about, most of the Eastern Massachusetts one, but also the other ones and what drove those pushing out of the completion dates?

Sure. I'd say, with any of our transmission projects or any -- there's siting things, there's applications. They get moved, there's hearings that switch around. I think that you shouldn't read too much into it other than -- in the Eastern Mass, we had a whole bundle of projects, about 29 of them, right? So 22 of them or so are done, and we have some under construction. In one of those projects, there's been some delay in terms of getting started on the schedule that we want to be on. So it's the normal give and take that you go through in terms of the siting process and the towns and getting the permits and whatnot. So no -- nothing major there, but sometimes projects get delayed, and then, we move other projects forward. So we don't anticipate any significant impact on our transmission plan as a result.

Okay. Thank you very much and I appreciate all the detail on the downside protection. It's a good time to have all of those tools.

Yes. Thank you, Andrew. Stay well.

Thanks, Andrew. There are no more questions in the queue, so we want to thank you so much for joining us this morning, and if you have any follow-ups on this busy day, please send me an email. Take care and be safe.

Thank you, all.

And thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.