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Welcome to the Eversource Energy Q3 2020 Results Conference Call. My name is John, and I will be operator for today call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions]
Please note that this conference is being recorded. And I will now turn the call over to Jeffrey Kotkin.
Thank you, John. Good morning and thank you for joining us. I’m Jeff Kotkin, Eversource Energy’s VP for Investor Relations. During this call, we’ll be referencing slides that we posted last night on our website.
And as you can see on slide one, some of the statements made during this investor call may be forward-looking as defined within the meaning of the Safe Harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995.
These forward-looking statements are based on management’s current expectations and are subject to risk and uncertainty, which may cause the actual results to differ materially from forecasts and projections. These factors are set forth in the news release issued yesterday.
Additional information about the various factors that may cause actual results to differ can be found in our annual report on Form 10-K for the year ended December 31, 2019, and our Form 10-Q for the three months ended 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 two 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 will cover various [ph], review the results of the third quarter, discuss recent regulatory development, include the acquisition of the assets of Columbia Gas of Massachusetts, provide an update on recent developments around our offshore wind partnership with Ørsted.
I will start with slide two, 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, total $1.01 per share in the third quarter of 2020.
In the first nine 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 nine months of 2019 and excluding the Northern Pass Transmission impairment charge GAAP results for September of this year were $2.76 cents per share.
Turnings our business segments, our electric trans -- 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 results of both higher storm restoration costs and property tax expense, as well as the impact of shared 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 and 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 9th, the transaction had no impact on this -- the gas segment -- this 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 as a parent and excluded from our recurring GAAP earnings.
Our water distribution segments 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 $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 costs equal to our earnings in the third quarter of last year.
As you probably noticed in our earnings release and can see on slide three, we are reaffirming our 2020 earnings per share guidance of $3.6 to $3.70 cents and that is excluding the non-recurring 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 be 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 capital or CapEx and our earnings growth.
In addition, as we’ve disclosed previously, earnings from offshore wind would be incremental to our core business growth. We will provide a comprehensive update of our regulated capital investment forecasts, 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 four, and our experience restoring power after Tropical Storm Isaias ravaged Connecticut on October 4th. 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 nine days, meaning we completed our work one day to two days faster than we had in the last two tropical storms that hit Connecticut, even though we had 30% to 35% more damage location.
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, but the vast majority of that’s 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 statewide restoration effort.
Where we were setting new poles or hanging miles of new wires or replacing hundreds of transformers, these related cost to be capitalized. The ultimate recovery of storm cost 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.
Speaking on our regulated business, I’ll turn to slide five 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 54.77% equity. It also permits us to implement performance based ratemaking for a 10-year term. That would 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 see the ROI of 10.9% and sharing mechanism on the downside if our ROE falls below 8.4%. And 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 a year and a half.
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 the permanent increase would take effect in January 1, 2021.
You may recall that the New Hampshire Public Utility Commission allowed us to implement a temporary rate increase of approximately $28 million back in July 1, 2019. The final approval rates would be retroactive back to that date for 18 months. We would recover that in a true-up over the course of the year 2021.
We can settle -- consider the settlement to be a constructive outcome to PSMH’s first general increase in about a decade and have said the New Hampshire PUC to approve the settlement before the end of November.
From the rate review -- reviews, I’ll turn to slide six 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 territory is 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 service 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 finance 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 eight-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 seven. It allows us to make the necessary investments in our Eversource Gas of mass system and reflect those investments and rates in a reasonably timely manner. We’re 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 company customers that we have in Massachusetts and Connecticut. As I noted earlier, we plan to integrate our Eversource Gas of Massachusetts into our updated five-year projections that we will 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. These benefits of lower costs will flow through to the New England’s electric customers.
From the regulated business -- I will turn to offshore wind partnership with Ørsted on slide eight. We’ve had a few developments since July 31st earnings call. The most significant development was that in August, The Bureau of Ocean Energy Management posted a complete review scheduled 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’re 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. Restructured in agreement on host community payments and the necessary real estate rights with the town of East Hampton, where the offshore cable was land and will be connected to the Long Island grid.
New York Public Service Commission citing here in the South Fork is scheduled to commence the first week of December. We continue to expect the state signing 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.
Turned into 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 is unlikely that the project delivers service by the end of 2023.
Also, we filed our Sunrise Wind application with BOEM on September 1st, 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 schedule. But again, at this time, it would seem that the end of ‘24 in service is not likely.
We’re very optimistic about our Australian 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 mentioned before, we have enough lease capacity can construct at least 4000 megawatts on the 550 square miles of ocean tracks that we have under long-term lease off the Southeast Coast of Massachusetts.
To this point, on October 20th, we submitted a number of alternative bids into the second New York Offshore Wind RFP where the state is looking for between 1,000 megawatts and 2,500 megawatts. New York State officials have indicated that they expect to announce the winner -- winners before the end of the year. Our Sunrise project, as a reminder, one 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 first date will target early next year for issuing an RFP the 600 megawatts of additional offshore wind. As you know, the majority of our revolution wind capacity of 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.
Thank you. [Operator Instructions]
Thank you, John. Our first question this morning is from Shahriar from Guggenheim. Good morning, Shahriar.
Good morning, Jeff. Good morning, Phil.
Good morning, Shahriar.
So a couple questions here. Just some -- Phil some of your language around sort of the growth rate, obviously, which still excludes Columbia Gas and offshore wind. Obviously, these are very creative and you’re already conservatively kind of well within your band. So should we sort of be thinking about these incremental items as potentially reducing your growth rate to maybe 6% to 8% or something that will hit you to the top end and then sort of extended 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% becoming a little bit more typical. So curious how you’re sort of thinking about this, do you see value to be taught to be in the top quartile or you don’t think you need a rewarded for it? So, curious on that as we think about you are laying into plan?
Sure. Shahriar, thanks for the question and I hope you are doing well.
Yeah.
Certainly, the addition of Columbia Gas and 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 significant benefit from that franchise.
And let me say, we also expect as those offshore wind projects come online, it also be additive. To remind folks, I know I said it, but -- and you gave 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 our 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 see that we have a number of levers to grow and grow at an even higher rate than we had expected before.
Got it. That’s helpful. And then also just last 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 entitlement?
Sure. The energy legislation, we have 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 so that goes up to 4%. So, it also just PURA have 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.
Got it. Terrific. That’s all I had today. Thanks, guys.
All right. Thanks, Shahriar.
Thanks.
Our next question is from Steve Fleishman from Wolfe. Good morning, Steve.
Good morning. Folks, can you hear me?
Yes, Steve. I can.
Yeah. Great. So just 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?
Yeah. Thanks for the question, Steve and I hope you and your families are doing well. I guess, Steve, if we 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’s some benefits or 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. Turban sizes themselves are getting larger. So you could move to larger turban sizes, if projects are due at a later time period versus an earlier time period. And certainly, the cost of supply chain and availability of materials and supply chain is always getting better.
So I’d say that, there’s opportunities for improved cost economics, as you move into a schedule that, you may not think of and I think people generally think of projects as get delay. It’s a cost increase. But that -- there are other elements that works here on the offshore wind business that offset that.
How about any negatives is -- how about like you lose, you’re going to lose any tax credits or anything else?
Yeah. Certainly.
Like just time value.
Yeah. 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.
Okay. Thank you.
Thanks, Steve.
Thank you. Our next question is from Angie from Seaport Global. Good morning, Angie.
Good morning. I have a question about Massachusetts. You guys have this very constructive decision for INSTAR Gas. But the state is clearly looking at the future of gas LDC. And so how do you guys see it, especially in light of the fact that you just acquired an additional gas utility in Massachusetts?
Good morning, Angie, and 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’s nobody, first of all, who’s more aggressive in terms of looking at clean energy strategies and carbon reduction and 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 the -- that the states wants to have aggressive clean energy and carbon reduction targets. We are 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 PUA is pushing back so strong that they don’t need to sign off on that extension. I mean, I would assume that it’s an actual practice, normal practice for a regulated utility to seek recovery of these under recovered revenues. Can you give us a sense how you see it in Connecticut, given the related legislative changes and also some deterioration and then negative relationships in the state?
Yes. So we are not doing a shut off across all -- any 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 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 already all of us are burdened with in terms of the economic conditions and COVID, et cetera. So we’re working through the issue. We are working with customers, as I say, in some of the assistance agencies and I’m sure we’ll get to a good outcome. Yeah.
Very good. Thank you.
Thank you, Angie. Next question is from Julien from Bank of America. Good morning, Julien.
Hey. Good morning, team. Thanks for the time. I hope all of you doing well and safe families as well. Perhaps just to pick up off of or perhaps clarify if I can some of the last rounds of questions. When you talk about the 4Q roll forward, can you give me roll into 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’s an undetermined data continue to be excluded there?
Julien, thanks for your question and your comments, and I hope you and your family are doing well, too. Just to clarify, we will -- our history has been to add another year into the outlook of 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 kind of 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 intense going forward. I think that what 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 age, 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.
Okay. And if you don’t mind elaborating a little bit further, I know that there’s a certain degree of uncertainty on exactly the permitting schedule that inhibits your ability to say, when these projects going to reach in service. Can you least try to put some more parameters around what each of these pieces of the process to take such that there’s like a window, if you will, it may be too early?
Yeah. 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 notice of intent to prepare their environmental impact statement. And frankly, we would have expected in our original schedules that some of these analyze it, you know, 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 significant change in the schedule. But at this stage, it would be prudent to wait to see the schedule that comes out on BOEM before we commit to a final in services. But I wouldn’t expect it to be significant.
Got it. Excellent. All right. I’ll pass it from there. Thank you so much.
Yeah. Okay.
Thanks, Julien. Next question is from Durgesh from Evercore. Good morning. Durgesh.
Hey. Good morning, guys. Thanks for taking my question. Just following up on the offshore wind here, what to expect, there is this EIS decision, I suppose that is going to be out OUS state and rather this month or early December. What to expect there and then how does that impact your future project timelines?
Yeah. These notices of intent, they contain a plan schedule that in analyze, they have contained BOEMs planned schedule for reviewing each of the costs. So that would be an important piece of information to have available. So that’s really what’s included in that is a plan schedule for reviewing the cost that comes out with the notice of intent.
Great. So 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.
Oh! Okay. Yeah. I’m not. I apologize. You probably have to ask Vineyard about that.
Okay. But that doesn’t have a read through for you or you’re also in project? I guess that’s sort of what my question was?
Well, certainly, all of the developers off the coast that we’ve been going through this huge cumulative impact study and looking at spacing of wind turbines and we came up with one nautical mile spacing. So certainly, they 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 impacts 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.
Okay. Perfect. That’s all I had guys. Thank you so much.
All right.
Thank you.
Thanks, Durgesh. Next question is from Jeremy from JP Morgan. Good morning, Jeremy.
Good morning. Thanks for having me. Just want to start off with what are the benefits of looping Con Ed into the proposed Sunrise to or Sunrise Wind to RFP here. Eversource has the experience of building transmission. I am curious what additional competitive advantages Con Ed provide to you to this specific project? Can you provide details on potential ownership interests for each entity? And does ownership interest change once construction is complete and the project is in service?
Thanks for the question Jeremy. Hope you are 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 and 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 up knowledge and skill set of the area that certainly we don’t have as in-depth of knowledge as they would. So certain 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 and 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 countenancing plans? Is it fair to assume the $700 million of equity in your current five-year plan moves to the back end here? And how is offshore wind CapEx spending track 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 expected to spend this year -- just for the year 2020. And it’s tracking somewhat close that, I’d say, it’s probably a little bit under what we expected it at this time.
In terms of the financing, you’re right, that we announced a year ago the $2 billion of equity need that would support the forecast and we issued 1.3 of that, so, the $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.
Got it. That’s helpful. I’ll leave it there. Thank you.
Thank you.
All right. Thanks, Jeremy. Next question is from Paul Patterson from Glenrock Associates. Good morning, Paul.
Good morning, guys.
Good morning, Paul.
I just want 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, right, I can tell you the specific name…
No. That’s okay. I just wanted to be specific as somebody else mentioned. There has been a number of different…
Yeah. Make sure well…
Yeah. So the -- so as you recall the PURA suspended the rates that we had implemented over the summer, both we and UI to take an additional look like 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 they 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 enough shoulder month, like May or something and move to annual reconciliations as opposed to semi-annual.
So this would -- it is delay, this could have effect at least to the cash flow item and it could have an impact on our deferrals that we have in place there. But I think it generally is consistent with the desire as we said this to move off of these peak periods for making rate changes to shoulder periods and see what we’ve built in here. But we’re actively reviewing that last night and today and we will be -- and it has any comments that we’ll have with you as I said on the 12th.
Okay. There was one part of it that would reduce the carrying charges from the -- from whack to a prime rate on a variety of reconciliation mechanisms. Is there any -- do we have any I know this is off the press and everything. But do we have any sort of forecasts as to what the -- those reconciliation mechanisms like how much capital might be tied up in those?
No. That you did -- that is a point to the carrying costs at prime, which is consistent in some other jurisdictions, I guess. So, no, that -- it’s not a significant item, but it’s certainly one that PURA has put out there in the draft is to recover the deferred balances with a prime rate versus the whack.
Okay. And then just we don’t know who the President is going to be it seems. But if there was a change in administration, do you think that could have or not have maybe a significant impact on the OEM permitting process with respect to offer win?
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 are actively having Zoom meetings or teams calls or whatever -- the video capabilities that we’re using. So we’re actively working at and I can assure you that the people in the agencies are working full speed, regardless of, who is the 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 is going 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 at the BOEM is pretty much the agency that of the bureaucratic process is 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 the right understanding there?
Yeah. I’d say that the work at the agencies is going on. There -- we’ve been meeting regularly, going through questions. We’re working through various state agencies. So, no, I say that the work is continuing at the -- as you say, the bureaucratic level.
Okay. Awesome. Thanks so much.
You’re welcome.
Thanks, Paul. Next question is from Mike Weinstein from Credit Suisse. Good morning, Mike.
Hey. Good morning. Good morning, Phil.
Good morning, Mike. How are you?
Hi. Good, I hope you’re doing well. Hey. Maybe you could just give a quick two second update on what you think the outcome at FERC for transmission ROEs considering 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 New England before 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 looking at our 10.57 rate, reserving to that level and 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 any answer.
I know in years past when I tried to think this one was coming or it was going a certain way, and it really hasn’t materialized. So I think it’s best to wait for the final outcome at this point [inaudible].
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’s ever a time at some point where there might be another whack or another go at transmission at some point, 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 is driven by…
Yeah.
… 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’s a lot of activity in 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 state want to contract for more of that. But there’s nothing planned on our end, there’s nothing that I see at this stage on the state’s agenda that would say that. But when you say that word ever, that’s a long time.
Right. So it seems like the offshore wind program really is kind of planted that at least for the time being?
Yeah. I’d say that a good way of looking at it.
Okay. Great. Thank you very much.
Okay, Mike.
Thanks, Mike. Our next question is from Insoo Kim from Goldman Sachs. Good morning, Insoo.
Hey. Good morning, guys. 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 decisions from the commission and timing of investments, et cetera?
Thanks for your questions and I hope you and your families are doing well. You didn’t specify -- I mentioned, in terms of what items could be additive to our 5% to 7% core business growth rate. I alluded to a grid mod in Connecticut or New Hampshire or potentially additional AMI dockets in Massachusetts.
But there’s really been no change there. We all the parties filed comments and plans back in July. And certainly you can understand there has 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 has been a lot of focus on storms. We’ve done a lot of dockets. And somebody else mentioned we have dockets going on in terms of March volumes and whatnot.
So the expectation was there is going to be another sort of go round, another process in Connecticut towards the end of the year. I really haven’t seen anything that would indicate a 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 line there in Connecticut as we move over the next several months.
But in terms of it being our forecast. I want to be clear that there is currently no zero. There’s no grid mod spending in our capital forecasts 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 them 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.
It makes sense that’s all I had. Thank you guys and stay safe.
Thanks.
Thanks, Insoo. Next question is from David Arcaro from Morgan Stanley. Good morning, David.
Good morning. Hi, Jeff. Hi, Phil. Thanks so much for taking my question.
Thanks Dave.
I had 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 families 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 construction, about rates, about lots of factors and all of those 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 sighting process and all of that informs subsequent bids. And so I can assure you that all those things get up to the minute attention before we bid go there.
Okay. Got it. That’s helpful. And I just wanted to touch on just O&M costs in 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 so that you would focus on going forward for managing O&M?
So there is -- we’ve got people process and technology, right, so all those things are our levers to help, our capital programs, as well as our operating programs. So we continue to implement systems and technologies that improved processes that makes it more efficient and effective workforce.
So we have still a robust, I’d say, series of technology improvements. If you -- I’ll start out by just setting the pace, 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 we able to do that 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 field 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’s still these productivity, technology changes that are happening, some winning last year, some going in this year and more plan for next. So that will be, I’d say the lever, the underpinning for us to have the ability to continue to improve processes and take unneeded costs out of the business.
Okay. Great. That’s helpful. Thanks so much for the call.
You’re welcome.
Thank you, David. Next question is from Travis Miller from Morningstar. Good morning, Travis.
Good morning. Thank you.
Hey, Travis.
Quick clarification on the storm cost, the $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 it will be pending at the regulatory filing that you mentioned?
Sure. That amount that you repeated with a deferred that’s how much of a 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 we -- 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 cost were up about $10 million for quarter that went through our O&M. For the quarter, it’s at that level and then the $274 or $275, you mentioned is deferred across the system.
Okay. Great. That’s very helpful. Thank you. And then quick follow up to the discussion on the Connecticut legislation. And 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 taking back some earnings or rate changes stuff like that, separate from what is going on in the PURA?
Well, certainly, the General Assembly can enact legislation that it feels is appropriate in any matter. 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 PUA.
And so the regulator, so the -- I guess I look at 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 ones who evaluate the performance based rates. They’ll be the ones who initiate a storm, standards and things like that, and look at, should they be penalties or should there be include 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 in 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 other risk for any kind of call backs would likely go through PURA instead of going through the General Assembly based on that Connecticut legislation that you talked about, right?
Yeah. As I said, PURA the dockets are active in -- 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, what legislation can always be enacted in any area.
Yeah. No. Okay. Great. I appreciate.
All right.
Thanks.
Thank you, Travis. Next question is from Andrew Weisel from Scotia. Good morning, Andrew.
Hey. Good morning. Thanks for squeezing me in. First question is, with the two 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 sort of a next year sort of event. But other than that, we’re pretty much out of the regulatory arena.
Okay. Great. Then on offshore wind, can you just, 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 three existing projects? Any thinking as far as from an earnings mix perspective, if there’s a limitation or 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 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 amount that we bid, and the returns that we’re looking for. So as long as the returns are at an appropriate levels, but -- for that business, it makes sense to make the bid win the bid and expand the business there.
The -- what we’ve said is, we -- are tracks what we own off the coast of 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 there’s kind of a -- 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 a -- we’re constrained by the lease area and we’re guided by the financial discipline to on our bids and our return.
Got it. That’s really helpful. I guess I should have said bid, bid, bid responsibly.
Okay. Yeah. Yeah.
That’s -- thanks a lot guys.
Thanks. And I hope you stay well Andrew. Thanks.
All right. Andrew, thank you very much. That sort of wraps up today. If you have any follow up questions, please give us a call or send us an email 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.