康涅狄格電力 (ES) 2020 Q3 法說會逐字稿

Welcome to the Eversource Energy Q3 2020 Results Conference Call. My name is John, and I will be your operator for today's call. (Operator Instructions)

Please note that this conference is being recorded. And I will now turn the call over to Jeffrey Kotkin.

Thank you very much, John. Good morning, and thank you for joining us. I'm Jeff Kotkin, Eversource Energy's Vice President for Investor Relations. During this call, we'll be referencing slides that we posted last night on our website.

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 June 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 Phil Lembo, our Executive Vice President and CFO. Also joining us today are Joe Nolan, our Executive Vice President for Strategy, Customer and Corporate Relations; John Moreira, our Treasurer and Senior VP for Finance and Regulatory; and Jay Buth, our Controller.

Now I will turn to Slide 2 and turn over the call to Phil.

Thank you, Jeff. Good morning, everyone. I hope everyone on the call remains healthy, and that your families are safe and doing well. This morning, I'll cover a variety of areas, review the results of the third quarter, discuss recent regulatory developments, including the acquisition of the assets of Columbia Gas of Massachusetts and provide an update on recent developments around our offshore wind partnership with Ørsted.

I'll start with Slide 2, noting that recurring earnings were $1.02 per share in the third quarter of 2020 compared with recurring earnings of $0.98 per share in the third quarter of 2019. GAAP results, which include a charge of $0.01 per share, relating to the recently completed acquisition of the assets of Columbia Gas of Massachusetts, totaled $1.01 per share in the third quarter of 2020.

In the first 9 months of 2020, our recurring earnings, excluding Columbia Gas acquisition cost, totaled $2.80 per share compared with recurring earnings of $2.69 per share in the first 9 months of 2019 and excluding the Northern Pass Transmission impairment charge. GAAP results for September of this year were $2.76 per share.

Turning to our business segments. Our Electric Distribution segment earned $0.60 per share in the third quarter of 2020 compared with earnings of $0.61 per share in the third quarter of 2019. The lower earnings were a result of both higher storm restoration costs and property tax expense as well as the impact of some share dilution. Our Electric Transmission segment earned $0.36 per share in the third quarter of 2020 compared with recurring earnings of $0.33 per share in the third quarter of 2019. Improved results were driven by the continued investment in reliability in our transmission facilities, partially offset by share dilution.

Our natural gas distribution segment lost $0.04 per share in the third quarter of 2020 compared with a loss of $0.05 per share in the third quarter of last year. Improved results were due to higher revenues. I should note that because we didn't close on our acquisition of Columbia Gas of Massachusetts assets until October 9, the transaction had no impact on this -- the gas segment, during the quarter. Each quarter this year, we booked acquisition-related costs at the parent and have segregated them for increased transparency.

Beginning in the fourth quarter of this year, ongoing results of our new gas franchise, which is named Eversource Gas Company of Massachusetts, will be reflected in the natural gas segment. Integration-related costs, however, will continue to be recorded separately at the parent and excluded from our recurring GAAP earnings. Our Water Distribution segment earned $0.07 per share in the third quarter of 2020 compared with earnings of $0.06 per share in the third quarter of 2019. Improved results were due to a $3.5 million after-tax gain on the sale of our Hingham, Massachusetts area facilities to the town.

Eversource parent earned $0.03 per share in the third quarter of 2020, excluding the Columbia Gas of Massachusetts asset acquisition cost, equal to our earnings in the third quarter of last year.

As you probably noted in our earnings release and can see on Slide 3, we are reaffirming our 2020 earnings per share guidance of $3.60 to $3.70, and that is excluding the nonrecurring costs related to the purchase of Columbia Gas of Massachusetts assets. We are also reaffirming our long-term EPS growth rate of 5% to 7% from our core regulated business through the year 2024. We continue to expect to be somewhere around the middle of that range, largely due to the investments we need to make on behalf of our customers as we've outlined for you earlier in the year.

As a reminder, while we fully expect the Columbia Gas assets to be accretive to our earnings per share starting immediately in 2021, we have not yet updated our long-term financial outlook to reflect the acquisition of Columbia Gas assets in our CapEx or our earnings growth. In addition, as we've disclosed previously, earnings from offshore wind would be incremental to our core business growth. We'll provide a comprehensive update of our regulated capital investment forecast, adding in Eversource Gas Company in Massachusetts projections and provide an update of our offshore wind partnership during our year-end call in late February.

For the third quarter results, I'll turn to Slide 4 and our experience restoring power after tropical storm Isaias ravaged Connecticut on October 4. We serve 149 cities and towns in Connecticut, and every one of these communities suffered damage from Isaias, much of it catastrophic. As you can see on the slide, we had nearly 22,000 damage locations that we had to address and brought in an army of electric restoration and tree crews to restore power, all the while working on the restoration in a pandemic setting.

The restoration process lasted 9 days, meaning we completed our work 1 to 2 days faster than we had in the last 2 tropical storms that hit Connecticut, even though we had 30% to 35% more damaged locations. And most importantly, we completed that work safely with no serious electrical contact and no COVID exposure among the enormous workforce we brought to Connecticut. Just a tremendous effort by all of our employees from across all parts of Eversource.

At this time, we estimate that deferred cost across all three states will total more than $275 million, with the vast majority incurred in Connecticut. That figure will be adjusted as the actual invoices are received. We're still actively pursuing invoices from hundreds of vendors that assisted us during the state-wide restoration effort, where we were setting new poles or hanging miles of new wires or replacing hundreds of transformers, these related costs are to be capitalized. The ultimate recovery of storm costs and the evaluation of performance in safely and expeditiously restoring power to our customers is pending an ongoing review by the Connecticut Public Utilities Regulatory Authority, or PURA. That review is scheduled to be completed in late April of 2021.

Sticking with our regulated business. I'll turn to Slide 5 and a review of this year's distribution rate reviews. This past Friday, the Massachusetts Department of Public Utilities issued its decision in the NSTAR Gas rate review that we filed last year. It supports our continued investment in the NSTAR Gas system on behalf of our 300,000 customers. The decision allows NSTAR Gas to increase distribution revenues by $23 million on an annualized basis. The DPU approved an ROE of 9.9% and a capital structure with a 54.77% equity.

It also permits us to implement performance-based rate making for a 10-year term, that with sound operating performance by NSTAR Gas, will target annual base rate increases of inflation plus 1.03%. This is an earning-sharing mechanism that would return 75% of the benefit to customers should we exceed the ROE of 10.9% and the sharing mechanism on the downside, if our ROE falls below 8.4%. Also exciting is, the decision also approves our first ever geothermal pilot program.

Our other long-standing rate proceeding involves Public Service of New Hampshire. In New Hampshire last month, we and all the parties to the PSNH rate case filed a proposed settlement in the rate review that has been pending for nearly 1.5 years. As you can see from the slide, we settled on a $45 million annualized rate increase that includes a 9.3% return on equity and a 54.4% equity layer. Should regulators approve the settlement, a permanent increase would take effect in January 1, 2021. You may recall that the New Hampshire Public Utilities Commission allowed us to implement a temporary rate increase of approximately $28 million back in July 1, 2019.

The final approved rates would be retroactive back to that date or 18 months. We would recover that in a true-up over the course of the year 2021. We consider the settlement to be a constructive outcome to PSNH's first general increase in about a decade and have asked the New Hampshire PUC to approve the settlement before the end of November.

From the rate reviews, I'll turn to Slide 6, and our recently completed acquisition of the assets of Columbia Gas of Massachusetts for $1.1 billion of cash, excluding working capital adjustments. Most of these assets were assigned to Eversource Gas Company in Massachusetts, a new subsidiary, I mentioned that we formed in May of 2020. As you can see on the slide, much of Eversource Gas' service territories adjacent to NSTAR Gas or Yankee Gas service territories.

Additionally, NSTAR Electric already provides electric service to about 20 of the communities that Eversource Gas serves with natural gas. As a result, we expect to realize operational benefits for our newest 330,000 natural gas customers in the communities where they live. To finance the transaction, we sold approximately $500 million of equity in June, and we financed the debt portion of the transaction in August. And again, we are very confident that this transaction will be accretive to our earnings per share in 2021 and incrementally accretive in the years ahead.

A critical factor in ensuring that this transaction brings benefits to all stakeholders is an 8-year rate plan that we negotiated with the Massachusetts Attorney General and other key parties prior to our filing with the Massachusetts Department of Public Utilities. The key elements of that plan are listed on Slide 7. It will allow us to make the necessary investments in our Eversource Gas of MA system and reflect those investments in rates in a reasonably timely manner.

We are thankful that the DPU approved the settlement and the acquisition very quickly. Now that we have the keys to the property and a long-term plan in place, we are focused on providing our new Eversource Gas customers with the same high level of service that we provide our other 550,000 natural gas distribution companies' customers that we have in Massachusetts and Connecticut. As I noted earlier, we plan to integrate Eversource Gas of Massachusetts into our updated 5-year projections that we'll provide you in February.

We continue to project approximately $3 billion of regulated company capital investments this year, despite the challenges posed by the pandemic and the need to take crews off of capital projects for a significant part of August to deal with the aftermath of tropical storm Isaias. Through September, our capital investments totaled approximately $2.2 billion. That's approximately the same level as this time last year in 2019. We made considerable progress on our transmission capital program in the third quarter, putting several projects into service at or below budget, and these benefits of the lower cost will flow through to New England's electric customers.

From the regulated business, I'll turn to the offshore wind partnership with Ørsted on Slide 8. We've had a few developments since our July 31 earnings call. The most significant development was that in August, the Bureau of Ocean Energy Management posted a complete review schedule for our 130-megawatt South Fork project on Long Island. The schedule culminates in a decision on a Construction and Operations Permit, or COP, as it's known, in mid-January of 2022. We are also making progress on the other permits.

In September, we filed a settlement proposal with the New York Department of Public Service to resolve much of the stakeholder feedback related to the construction, operations and maintenance of the project that lies within New York jurisdiction. In October, several of New York state agencies signaled their support for this proposal by signing on to the agreement. We've structured an agreement on host community payments and the necessary real estate rents with the town of East Hampton, where the offshore cable would land and will be connected to the Long Island grid.

New York Public Service Commission siting hearings for South Fork is scheduled to commence the first week of December. We continue to expect the state siting process to be completed in 2021, before BOEM issues the COP. Based on that schedule, we now expect the project to enter service in the fourth quarter of 2023. This is consistent with the expectations we disclosed during our May and July earnings calls, while we were still waiting for the review schedule.

Turning to our other projects. You recall that we filed our BOEM application for Revolution Wind in March. We expect BOEM to establish a review schedule for that project in the first quarter of 2021. We do not expect to provide an updated in-service date for this project until the schedule is issued. But at this point, it's unlikely that the project will enter service by the end of 2023.

Also, we filed our Sunrise Wind application with BOEM on September 1 and expect BOEM to establish a review schedule for the project next year. Once we receive that review schedule, we'll be able to better estimate a more up-to-date in-service date. But again, at this time, it would seem that the end of '24 in-service is not likely. We are very optimistic about our offshore wind business and expect to have many opportunities over the coming months and years to expand our offshore wind partnership beyond the 1,714 megawatts currently under contract.

As we've mentioned before, we have enough lease capacity to construct at least 4,000 megawatts on the 550 square miles of ocean tracks that we have under long-term lease on the southeast coast of Massachusetts. To this point, on October 20, we submitted a number of alternative bids into the second New York offshore wind RFP, where the state is looking for between 1,000 and 2,500 megawatts. New York state officials have indicated that they expect to announce the winner or winners before the end of the year.

Our Sunrise project, as a reminder, won of the largest portion of New York's first RFP last year, 880 megawatts. Additionally, just last week, Rhode Island Governor, Gina Raimondo announced that her state will target early next year for issuing an RFP for 600 megawatts of additional offshore wind. As you know, the majority of our Revolution Wind capacity, 400 megawatts, will be sold to Rhode Island, with the balance going to Connecticut.

Thank you very much for joining us this morning, and I'll turn the call back over to Jeff.

Thanks, Phil. And I'll turn the call back to John just to remind you how to enter questions in the Q&A queue.

(Operator Instructions)

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

So a couple of questions here. Just on some of your language around sort of the growth rate, obviously, which still excludes Columbia Gas and offshore wind. Obviously, these are very accretive, and you're already conservatively kind of well within your band. So should we sort of be thinking about these incremental items as potentially raising your growth rate to maybe 6% to 8% or something that will get you to the top end and then sort of extend that runway with your current trajectory. I mean, the reason why I ask is, 6% to 8% seems to be sort of that new top quartile bucket in our space, where 5% to 7% is becoming a little bit more typical. So curious how you're sort of thinking about this? Do you see value to be a -- to be in the top quartile? Or you don't think you're going to get rewarded for it. So curious on that as we think about delayering its plant.

Sure. Shar, thanks for the question and I hope you are doing well. Certainly, the addition of Columbia Gas will be additive to our existing forecast. So we're working through all the details of that so we're able to provide you with a full update in February, but we expect to get a significant benefit from that franchise. And as we say, we also expect, as those offshore wind projects come online, to also be additive. To remind folks, I know I said it, but -- the 5% to 7% growth rate is from the existing core business, which doesn't include Columbia assets. It also doesn't include grid modernization activities that are currently pending in Connecticut and New Hampshire or AMI that could be a potential to move forward relatively soon in Massachusetts in terms of taking a look at that by the regulator. So I'd say that we have a number of levers to grow and grow at even a higher rate than we had expected before.

Got it. That's helpful. And then, Phil, just lastly for me is, can you just maybe talk a little bit about your expectations for the legislation in Connecticut. I mean, the legislation that passed was more constructive than the draft legislation. But obviously, some disappointment with the refunds and penalties, offset by the potential upside from like PBRs. So sort of how are you guys thinking about this internally?

Sure. The energy legislation, we've said consistently that PBR is a formula and a template that we think is effective. We have PBR structures in other states, and we think that having a robust discussion on PBR in Connecticut makes a lot of sense. So we're very, very supportive of that provision. Really, the energy legislation directed PURA to evaluate that and open a docket by the middle of next year, so June of 2021. And it authorizes PURA to establish storm standards and potential penalties, as you mentioned. There is an increased potential of penalties. Currently, those penalties are 2.5% of our distribution revenues in Connecticut, and that goes up to 4%. So it also gives PURA some additional time to review cases. So -- which is also something that seems to be appropriate. So the legislation, as you indicated, is out there, and PURA is working through the details of it. And we expect to be working through that in a constructive way with them over the next several months.

Our next question is from Steve Fleishman from Wolfe.

Phil, can you hear me?

Yes, Steve, I can.

Okay. Great. So just a question on the delays in your offshore wind projects. Could you maybe talk to -- I know we don't know the exact timing, but how should we think about the impact on the economics of those projects from delay or puts and takes? And is it hurting the economics of the projects you already have signed up to?

Yes. Thanks for your question, Steve, and I hope you and your family are doing well. I guess to go to the puts and takes piece, I don't think that folks should automatically think that schedule changes result in ups or downs. There are some benefits that people may not consider in that. So certainly, if you are looking at adjusted schedules, you might be able to adjust your installation vessel optimization better, the turbine sizes themselves are getting larger. So you could move to larger turbine sizes if projects are due at a later time period versus an earlier time period. And certainly, the cost supply chain and availability of materials and supply chain is only getting better. So I'd say that there are opportunities for improved cost economics as you move into a schedule that you may not think of. I think people generally think of projects as if there is a delay, there's a cost increase, but there are other elements that work here on the offshore wind business that offset that.

How about any negatives? Is it -- how about -- like do you lose -- are you going to lose any tax credits or anything else, I guess, just time value?

Yes. Certainly, depending on -- yes. In terms of the schedules we're looking at, we don't expect to have any impact on our tax assumptions, but certainly, significant delays. Delays could have impacts on your tax assumptions. Delays could also have impacts on contracts that you have with counterparties. But in our specific case -- so that's the general case. In our specific case, we're confident that we have the ability to work within both of those, the tax area and the contract area in an effective way with where we see the schedules going in the future.

Our next question is from Angie from Seaport Global.

So I had a question about Massachusetts. You guys had this very constructive decision for NSTAR Gas, but the state is clearly looking at the future of gas LDCs. And so how do you guys see it, especially in light of the fact that you just acquired an additional gas utility in Massachusetts?

Thank you for your question, and hope you're doing well. The way that I would position it or the way that I think people should think about it is that there is nobody, first of all, who's more aggressive in terms of looking at clean energy strategies and carbon reduction than Eversource, in terms of having a carbon neutral goal by 2030. We have worked effectively with all parties in all states, but in Massachusetts, where the Attorney General and others want to take a look at sort of the future or the outlook in terms of the gas business, we've been working with these intervening parties for many years, and we'll continue to work with them on what we think an appropriate strategy is there.

So this is a long-term outlook in terms of what the state wants to be -- have aggressive clean energy and carbon reduction targets. We're fully supportive of that, and we look forward to working with all the parties there. But we don't see it as a threat to the gas distribution business in the region at all.

Okay. And in Connecticut, this recent back and forth between you guys and PURA about the extension of the lack of basically disconnections on the back of COVID. I mean, it sounds a bit concerning that PURA is pushing back so strong that they don't need to sign off on that extension. I mean, I would assume that it's a natural practice -- normal practice for a regulated utility to seek recovery of these under recovered revenues. I mean, can you give us a sense how you see it in Connecticut, given the latest legislative changes and also some deterioration in regular relationships in the state?

Yes. So we are not doing shut-offs across all of our franchises at this point. And specifically, we're working with customers. We're working with fuel agencies, assistance agencies on an approach here that will work best for customers. We've also engaged with PURA, as you mentioned, and other government officials on this issue. So I'm confident that we'll get to a good place here. Nobody wants to burden customers with any more than we're all ready -- all of us are burdened with in terms of the economic conditions and COVID, et cetera. So we're working through the issue. We're working with customers, as I say, and some of the assistance agencies, and I'm sure we'll get to a good outcome here.

Next question is from Julien from Bank of America.

I hope all of you are doing well and safe families as well. Perhaps, just to pick up off of a -- perhaps, clarify, if I can, some of the last rounds of questions. When you talk about the 4Q roll forward, are you going to be rolling to 2025? And then more specifically, how do you think about including or excluding offshore wind in light of the uncertainties described? Should we expect that offshore wind should continue to be at least for those projects where there is an undetermined date to continue to be excluded there?

Julien, thanks for your question and your comments. And I hope -- and hope you're -- you and your family are doing well, too. Just to clarify, we will -- our history has been to add another year into the outlook. So 2025 would be that year since our forecast goes through the 2024 time period. So that is something that you should expect to see. And really, our view on how to look at offshore wind, it doesn't change by any of the schedule items we talked about today. Or if -- we've looked at it as showing the core business as the driver and the foundational element of the growth rate, and then to show that wind is additive to that in what way. So that would be the intent going forward.

I think that -- well, I've been asked this question before, the answer is, was and still is, as more years of wind come in to the actual results of that particular year, then to me, it makes more sense to roll it all together. But at this stage, the expectation, especially in this upcoming February update, would be to have the core business extend that through 2025, and then show offshore wind in addition to that.

And if you don't mind elaborating a little bit further, I know that there is a certain degree of uncertainty on exactly the permitting schedule that inhibits your ability to say when these projects are going to reach in-service. Can you at least try to put some more parameters around what each of these pieces of the process could take? Such that there is like a window, if you will, it may be too early.

Yes. So in terms of -- there is -- people have realized out there, and we've been asked questions. I think you've asked us the questions in terms of with delays on Vineyard Wind and other things, there's been some delays in terms of BOEM's Notice of Intent and to prepare their environmental impact statement. And frankly, we would've expected in our original schedules that some of these NOIs to prepare -- the environmental impact statement would be out by now. So these are expected. I believe the planned schedule for reviewing and releasing these is underway. So I wouldn't expect a significant change in the schedule. But at this stage, it would be prudent to wait to see that the schedule that comes out of the BOEM before we commit to a final in-service date. But I wouldn't expect it to be significant.

Next question is from Durgesh from Evercore.

Just following up on the offshore wind here. What to expect -- this EIS decision, I suppose, that is going to be out or you stated rather this month or early December. What to expect there? And then how does that impact your future project timelines?

Yes. These notices of intent, they contain a planned schedule that -- in the NOIs, they have contained BOEM's planned schedule for reviewing each of the COPS. So that would be an important piece of information to have available. So that's really what's included in that is a planned schedule for reviewing the cost that comes out with the notice of intents.

All right, Phil. I guess, maybe I'm talking about the environmental impact statement. Isn't there an environmental impact statement that BOEM is supposed to sort of put out here in the next few weeks?

You're talking about the one for Vineyard, right?

Yes. Yes, please. Yes.

Okay. Yes, and I apologize, you probably have to ask Vineyard Wind about that.

Okay. But that doesn't have a read-through for you or your offshore wind projects? I guess that's what my question was.

Well, certainly, all of the developers off the coast that -- we've been going through this cumulative impact study and looking at spacing and -- of wind turbines, and we came up with a 1 nautical mile by 1 nautical mile spacing. So certainly, there could be components that come out in any decision for Vineyard Wind that you'd have to take a look at to see if it has any impact to other developers, including us. But in terms of what might be in that or the exact timing, I think Vineyard might have a better perspective of that.

Next question is from Jeremy from JPMorgan.

Just want to start off with, what are the benefits of looping Con Ed into the proposed Sunrise 2 -- Sunrise Wind 2 RFP here. Eversource has experience with building transmission but curious what additional competitive advantages Con Ed provides here to this specific project. Can you provide details on potential ownership interest for each entity? And does ownership interest change once construction is complete and the project is in service?

Thanks for your question, Jeremy. I hope you're doing well. I guess, I would say on the first part of the question, sort of, obviously, Con Ed has local knowledge of New York in their service territory, in the network, in the operation of the transmission and delivery system that are valuable to any party if you're operating in New York. So I'd say, they bring a knowledge and skill set of the area that certainly, we don't have as deep a knowledge of as they would. So sort of skill sets there that the local player would bring. So in terms of what the components of a relationship would be, those things are all to be discussed as we move through, but it's certainly beneficial, I think, to the project to have somebody with Con Ed skill sets involved.

Got it. And as far as potential ownership interest, is there any kind of thoughts on how that could develop?

Not at this time, no.

Got it. And then will the delay in offshore wind permitting have any impact on the current financing plans? Is it fair to assume the $700 million of equity in your current 5-year plan moves to the back end here? And how is offshore wind CapEx spending tracked year-to-date versus the $300 million to $400 million range that you expected?

We haven't disclosed a range that we've expected. We've talked about how much we expect it to spend this year, just for the year 2020, and it's tracking somewhat close to that. I'd say, it's probably a little bit under what we expected at this time. In terms of the financing, you're right that we announced a year ago, this $2 billion of equity need that would support the forecast that we issued $1.3 billion of that, so there's $700 million remaining that -- and I would say the same thing as I've said all along is, we'd be opportunistic and consider what our capital forecasts are and what the market conditions are as we look to fulfill the rest of that offering that we discussed.

Next question is from Paul Patterson from Glenrock.

I just wanted to follow-up on the draft decision in Connecticut on Monday, and what your thoughts were on it? Any -- if it were, in fact, to become a final order, what the potential impact could be?

Are you talking about the draft information on rates or what? Can you be more specific?

Sure. There was a draft decision on Monday in the PURA case associated with the rates, right? The rate review that was reversed that proceeding. I can tell you the specific name.

No, that's okay. I just wanted to be specific because as somebody else mentioned, there's been a number of different...

Yes, I know there were.

So the -- so as you recall, PURA suspended the rates that we had implemented over the summer, both we and UI to take an additional look. I think this is what you're referring to. So we did receive the draft order, and really, it's kind of hot off the press. We're currently evaluating that, and we're going to see what comments we might have and comments on the draft to do. I think it's the 12th of November. So we have some time to flush out anything. But it's consistent with -- on first blush, I'd say. It's consistent with PURA's desire to have some rate changes -- move -- instead of implementing rates at peak times of usage maybe such as July, implement them on. Change the timing of it to implement it maybe in a shoulder month like May or something and move to annual reconciliations as opposed to semiannual.

So this would -- if there are delays, this could have -- effectively, this is a cash flow item, it could have an impact on our deferrals that we have in place there. But I think, generally, it's consistent with the desire, as we said, to move off of these peak periods for making rate changes in the shoulder periods, and see what we build from there. But we were actively reviewing that last night and today and we will be -- and have any comments that we would have with you, as I said, on the 12th.

Okay. There was one part of it that would reduce the carrying charges from WACC to a prime rate on a variety of reconciliation mechanisms. Is there any -- do we have any -- I know this is all off the press and everything, but do we have any sort of forecast as to what those reconciliation mechanisms -- like how much capital might be tied up in those?

No. That you did -- there is a point, too. The carrying costs at prime, which is consistent in some of the jurisdictions, I guess. So no, it's not a significant item, but it's certainly one that PURA had put out there in the draft to recover the deferred balances with a prime rate versus a WACC.

Okay. And then just -- we don't know who the President's going to be at this point. But if there was a change in administration, do you think that could have or not have maybe a significant impact on the BOEM permitting process with respect to offshore wind?

The permitting process. I mean, when we meet with BOEM, the Bureau of Ocean Energy Management, that people are active. We're actively working. We're actively having Zoom meetings or Teams calls or whatever the video capabilities are that we're using. But we're actively working that, and I can assure you that the people and the agencies are working full speed, regardless of who's President or what the election results are. But certainly, it would be good to have the results of the election. I think we've all, as a country -- that the election results are something that we've all targeted out there. And wherever you fall on the political spectrum, it's good to have certainty as opposed to uncertainty. So I think we're all looking forward to what the final outcome is there so we can move forward.

Okay. But just so for my clarity, the process of the BOEM is pretty much the agency, the sort of the bureaucratic process that's going on, really you don't see a significant change one way or the other, regardless of the outcome of the presidential election. Is that right understanding there?

Yes. I'd say, the work at the agencies is going on. There -- we've been meeting regularly, going through questions, we're working through the various state agencies. So no, I'd say that the work is continuing at the, as you say, the bureaucrat level.

Next question is from Mike Weinstein from Crédit Suisse.

Maybe you could just give a quick 2-second update on what you think the outcome at FERC might be for transmission ROEs, considering, I don't know, if the election outcome has any effect on any of this accelerating an outcome?

Well, Mike, that's a very big crystal ball that you're asking. So -- but again, thanks, and I hope you're doing well. Thanks for your question. I wish I had a better answer than to say that it's working its way through. We don't really have a specific clarity as to when FERC might come out with something on the four pending New England cases. And certainly, impact of the election, one way or the other, what that could have in terms of commissioners and that type of thing. So the only thing I know for certain is, we're booking at our 10.57% rates, reserving to that level, and an 11.74% cap. And we'll just have to wait and see what the final outcome we'll look at, but I don't really have an answer. I know, in years past, when I tried to think that one was coming or it was going in a certain way, it really hasn't materialized. So I think it's best to wait until the final order comes out at this point or orders as it may be.

Right. And bigger crystal ball question would be, I know that Hydro-Québec has a pretty big long-term construction plan for hydro generation up there. And I know that their long-term plans included lots and lots of Northern-Pass-type transmission lines. Do you think there is ever a time at some point where there might be another WACC or another go at transmission at some point, a big transmission project?

I think a lot of that is dependent upon what the states want to get, right? So these are going to be processes now that are driven by state's Clean Energy policies and the state's desire to have either offshore wind or solar or hydro in the mix. So there are certainly -- there is a lot of activity at the states now. I mean, the states in our area, all want aggressive carbon reduction targets. So it wouldn't be out of the question to see if they want to contract for more of that, but there is nothing planned on our end. There is nothing that I see at this stage on the states' agenda that would say that, but when you say the word ever, that's a long time.

Right. So it seems like the offshore wind program really has kind of supplanted that, at least for the time being?

Yes. I'd say that's a good way of looking at it.

Our next question is from Insoo Kim from Goldman Sachs.

My only question is -- and apologies if I missed this, but could you give just an update on the Connecticut grid mod filings and any updates on expected decision from the commission and timing of investments, et cetera?

Thanks for your question, Insoo, and I hope you and your family are doing well. You didn't miss it. I mentioned, in terms of what items could be additive to our 5% to 7% core business growth rate, I alluded to grid mod in Connecticut or New Hampshire or potentially, additional AMI dockets in Massachusetts. But there has really been no change that we -- all the parties filed comments and plans back in July, and certainly, you can understand there's been a lot going on. And I think I may have said Isaias was in October, but we all know that Isaias was in August.

So since August, there's been a lot of focus on storms, and there's been a lot of dockets. And as somebody else mentioned, we have dockets going on in terms of moratoriums and whatnot. So the expectation was, there was going to be another sort of go round and another process in Connecticut towards the end of the year. I really haven't seen anything that would indicate specific schedule on that. So I guess, our best guess is still -- it's still in the pipeline, and you may see more activity on grid mod here in Connecticut as we move over the next several months.

But in terms of it being in our forecast, I want to be clear that there is currently no -- 0, there is no grid mod spending in our capital forecast for any grid mod programs that haven't been approved like in Connecticut or New Hampshire. So once they are approved, and once we see what our role would be in them, and once we see what that looks like, then we have more confidence in putting in the plan. So that could be something we have information on by the time we get to the February update. So we'll have to stay tuned on that.

Next question is from David Arcaro from Morgan Stanley.

A quick follow-up on offshore wind. In light of some of the recent delays, I was wondering if that changes how you're strategizing around other bids that you're putting into future RFPs, like baking in more contingency, anything that might give a greater level of comfort around the economics of future projects that you might win?

Thank you, Dave, for your comment, and I hope you and your family are doing well. Certainly, every piece of information that you get -- and this isn't just offshore wind, this is on all our business, but I'll focus on offshore wind since that's the question. Every month that goes by, every quarter that goes by, we gain more insight and information about the construction, about the rates, about lots of factors in all of those things. All of the things are factored into subsequent bids. So the information that we have available to us as we're moving into a bid -- recent bid in New York is different than we had from bids that we made in Rhode Island or Connecticut or Massachusetts. So every data point is important to us, and we factor that into the next bid. So I'd say that absolutely, that schedules and how you make it through the siting process and all of that informs subsequent bids. So I can assure you that all those things get up to the minute attention before the bid goes in.

Okay. Got it. That's helpful. And I just wanted to touch on just O&M costs and the O&M budget. Could you remind us how you see that trajectory just for the overall business going forward? You've been -- you've got a great track record of controlling O&M. So what are the key levers in your tool belt that you would focus on going forward for managing O&M?

So there is a -- we've got a people process and technology, right? So all those things are leveraged to help our capital program as well as our operating program. So we continue to implement systems and technology that improves processes that makes it more efficient and effective workforce. So we have still a robust, I'd say, series of technology improvements. I'll start off by just setting the stage that in the guidance we gave, we said that we expected O&M cost to be down this year, and then just for the forecast period, kind of flat going forward.

So how are we able to do that? It is by some of these technology changes, and we've been implementing more productivity management tools and tools for our individual line workers and gas fitters and -- in the field to get their work, to update their work that we can then take that and automatically update drawings and files. We don't need to hand it off to somebody. So there is still these productivity technology changes that are happening, some went in last year, some going in this year and more planned for next.

So that will be, I'd say, the lever of the underpinning for us to have the ability to continue to improve processes and take unneeded costs out of the business.

Next question is from Travis Miller from Morningstar.

A quick clarification on the storm cost. That $275 million number, if I heard you correctly. How much did you expense in the quarter? And how much was either deferred or capitalized or will be pending the regulatory filing that you mentioned?

Sure, that amount that you repeated was a deferred. That's how much of storm cost that we deferred in both tropical storm Isaias, and that was across all states, but primarily, in Connecticut. So that's our deferral. That would be -- once the storm gets to a certain level, it triggers a deferral. So that all is deferred storm cost right now.

In terms of -- there are other storms. Certainly, we had an active quarter for storms in general, but there are other storms other than Isaias that did impact the quarter. I mean our storm costs were up about $10 million for the quarter that went through our O&M. So for the quarter, it's at that level and then the $274 million or $275 million that you mentioned is the deferral across the system.

Okay, great. That's very helpful. And then a quick follow-up to the discussion on the Connecticut legislation. There is some language in there, as I understood, it's about the general assembly having some review power there. What's your thought in terms of the scope of what the general assembly, separate from PURA, could do in terms of either taking back some earnings or rate changes and stuff like that, separate from what's going on in the PURA?

Well, certainly, the general assembly can enact legislation that it feels is appropriate in any manner. So I do think specifically to the energy legislation that was enacted recently in Connecticut that most things -- all were, for the most part, moved to PURA, so the regulator. So the -- I guess I'd look at it as the legislation would provide the intent, the framework, the direction, and then PURA is the one who's going to be implementing -- they're going to be the one to evaluate the performance-based rates. They'll be the ones who initiate the storm standards and things like that, and look at should there be penalties or should there be food penalties and things like that.

So I think that effectively, the general assembly can certainly enact any and all legislation it feels it should. And the way that this legislation seems to have turned out was that then the implementation of that legislation is in the hands of PURA.

Okay. So the potential for any of the risk, for any kind of clawbacks would likely go through PURA instead of going through the general assembly, based on that Connecticut legislation that you talked about. Great.

Yes. As I say, the PURA, the dockets are active in -- and will be active over -- there's certain time -- dates that the legislation has given PURA. So I would expect that PURA will have the pen on this. But again, as I say, legislation can always be enacted in any area.

Next question is from Andrew Weisel from Scotia.

First question is with the 2 rate cases now completed. Can you remind us which subsidiaries might be next to file general rate cases? We have plenty of regulatory items, of course, with grid mod and other initiatives, but for general rate cases?

Well, according to the requirements in Connecticut, Connecticut could be an area that is required to file by the existing framework that's there, and that would be something that would be a next year event. But other than that, we're pretty much out of the regulatory arena.

Okay, great. Then on offshore wind, can you just thinking -- sorry, can you share your latest thinking on how big you're willing to let that business get? You talked a lot about the opportunities that you're pursuing beyond the 3 existing projects. Any thinking as far as from an earnings mix perspective, if there is a limitation? Or would you -- will you plan to just bid, bid, bid and get as many projects as your leases will support?

Well, I want to be clear on this because I think it's a very important point that bid, bid, bid isn't the strategy. Our strategy is to have a financial discipline about growing that business in a way that provides appropriate levels of returns that benefit our shareholders. So just by winning a bid doesn't do it, it has to be -- we have to and we continue to maintain financial discipline in terms of the amounts that we bid and the returns that we're looking for.

So as long as the returns are at an appropriate level that -- for that business, it makes sense to make the bid, win the bid and expand the business there. The -- what we've said is, our track, what we own off the coast of -- or what we have access to in terms of the lease areas, we could do about 4,000, at least 4,000 megawatts of offshore wind. So that's the maximum capability that we have. So it's not an infinite growth type of thing.

And we had indicated that when leases were available that are not in our region that we were not interested in them. So leases in our region, like the ones we're involved in, are good. But other lease areas, that's not for us in other parts of the Mid-Atlantic, et cetera. So it's -- we're constrained by the lease area, and we're guided by the financial discipline to -- on our bids and our returns.

Got it. That's really helpful. I guess, I should have said, bid, bid, bid responsibly.

Okay. Well, yes.

That sort of wraps up today. If you have any follow-up questions, please give us a call or send us an e-mail, and we look forward to speaking and seeing many of you during the Virtual EEI Conference next week.

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

Thank you.

All right. Thank you.