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Eversource Energy
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Welcome to the Eversource Energy Third Quarter 2018 Earnings Conference Call. My name is Hilda, and I will be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded.
I will now turn the call over to Mr. Jeffrey Kotkin from Eversource Energy. Sir, you may begin.
Thank you, Hilda. 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. Some of 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, 2017, and on Form 10-Q for the three months ended June 30, 2018. Additionally, our explanation of how and why we use certain non-GAAP measures 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 John Moreira, our Treasurer and Senior VP for Finance and Regulatory; and Jay Buth, our VP and Controller.
Now I will turn to slide 2 and turn over the call to Phil.
Thanks, Jeff. Good morning. This morning, I'll summarize our third quarter results and recap some recent state and federal regulatory proceedings.
Overall, we're very pleased with the results for the quarter and for the first nine months of the year. We've been consistent with our expectations and we continue to target full year earnings per share between $3.20 and $3.30 per share, as well as our 5% to 7% long-term earnings per share growth rate. We've also made very good progress on a number of important initiatives and continue to provide top tier reliability and service to our customers.
Starting with slide number 2, we earned $0.91 per share in the third quarter of 2018 compared with earnings of $0.82 per share in the third quarter last year. As noted in the earnings release, the $0.91 includes two non-recurring items. One involve the impairment of our investment in Access Northeast and the other involves some tax benefits. I'll provide more details on these impacts in a minute.
Turning to our core business results, our electric distribution segment earned $0.55 per share in the third quarter of 2018 compared to $0.50 per share in the third quarter of last year. The primary driver behind the improvement was higher distribution margin. This resulted from new rate plans in effect in Connecticut and Massachusetts, and higher sales at Public Service of New Hampshire where we're not yet decoupled.
Additionally, you may recall from our second quarter results that the implementation of decoupling this year for NSTAR Electric in lieu of our former loss-based revenue mechanism resulted in higher year-over-year revenues in peak use quarters, such as the third; and lower revenues in shoulder (00:03:55) quarters, such as the second quarter. Partially offsetting the higher margin was the absence of the New Hampshire generation earnings, and higher depreciation, amortization and property tax expense, mostly at Connecticut Light and Power.
Our electric transmission segment earned $0.34 per share in the third quarter of 2018 compared to $0.31 in the third quarter of 2017. Improved results were due primarily to an increased level of our investment in transmission facilities this year.
Our natural gas distribution segment lost $0.04 per share in the third quarter compared to a loss of $0.02 per share in the third quarter of 2017. The change was primarily due to higher operation and maintenance expense in the gas business.
Our water distribution segment, which is new this year as a result of our of last December's acquisition of Aquarion Water, earned $0.06 per share in the third quarter of this year. More than half of Aquarion's earnings are typically realized in the third quarter when customer usage is at its highest.
Eversource parent and other earned $1 million in the third quarter of 2018 or less than $0.01 a share compared with earnings of $0.03 per share in the third quarter of 2017. Parent and other results reflect two significant non-recurring items. First, the Access Northeast impairment of $26 million after tax or $0.08 per share represents all of our investment in the project. While we've made progress in most New England states in seeking natural gas capacity contracts with electric distribution companies, the Massachusetts Supreme Judicial Court ruled in the summer of 2016 that the state electric utilities cannot sign such contracts without a change in law
And at this time, despite projected regional energy savings of $1 billion a year, we do not see a clear path to achieving new legislation in Massachusetts, particularly in light of recent unfortunate events outside of Eversource's service territory in the Merrimack Valley region of the state. As a result, we've concluded that our investment in Access Northeast is impaired.
Also in the third quarter of 2018, we filed our final 2017 federal and state corporate income tax returns. There were several discrete items related to legislative tax code changes that reduced our tax obligations. Together, these reductions totaled $18 million or about – or $0.6 per share. Tax reform had no material impact on our 2017 results and we do not expect additional impacts going forward.
From financial results I'll turn to slide 3 in recent regulatory developments. In September, we joined with the Connecticut Office of Consumer Counsel and the prosecutorial unit of PURA in filing a settlement on our Yankee Gas three-year rate proposal. The settlement is now before regulators for a review and we expect the final decision in the fourth quarter.
The rate plan will be effective on November 15, 2018 and includes three moderate increases in distribution rates over a three-year period through calendar 2021. The authorized ROE will be at 9.3%, a slight increase from existing levels. We will also implement revenue decoupling and a capital tracker that will enable us to accelerate the replacement of older cast iron and unprotected steel pipe. We consider the settlement to be a constructive outcome of the rate review, and marks the second long-term rate settlement we've achieved in Connecticut just this year.
The CL&P review, as you may recall, was settled in January and new rates were effective in May. When you also consider NSTAR Electric's five-year rate plan that was effective in February of this year, we find ourselves in a position of having long-term rate predictability in three of our largest distribution jurisdictions, with both decoupling and capital trackers for certain major investments. It means that for several years we'll be able to focus on just running the business to the best of our customers rather than spending substantial time and resources on rate reviews.
We've also had what I would consider positive news at FERC in mid-October. FERC commissioners voted three to nil to implement a new methodology for reviewing and settling rate electric transmission ROE cases. Rather than solely relying on the commission's discounted cash flow methodology, FERC is now proposing that going forward it would average the DCF, the CAPM, and risk premium, and expected earnings methodologies in determining new authorized ROEs.
FERC's proposed ruling was a result of four serial complaints that were filed between 2011 and 2016 by complainants who asked FERC to lower the ROEs earned by the New England Transmission Owners. You may recall that while all four complaints moved through the hearing process and secured ALJ recommended decision, only the first one was voted on by FERC. That 2014 decision was appealed to the D.C. Circuit Court of Appeals which vacated the decision and remanded the case back to FERC in April of 2017.
FERC's new methodology addresses the issues raised by the appeals court in the first case, but has not yet produced a new authorized ROE for New England. In its ruling, FERC asked the parties through the ROE complaints to file briefs and their own calculations for a new ROE for the region using the core methodologies for each of the four complaint periods. The briefing process will likely continue through early next year, and it's not clear when FERC will actually decide on each of the four complaints, the oldest, which dates back to October of 2011.
Until we receive final rulings and as instructed by FERC, we'll continue to bill customers based on the commission's 2014 decision on the first complaint, which calls for a base ROE of 10.57% and a cap on what any single project can earn of 11.74%. Now FERC has not ruled on any of the four complaints yet, but in the illustrative calculation that FERC described in its order would result in a modestly lower base ROE of 10.41% and a higher cap of 13.08%.
We are still a ways away from a final decision, but such levels if ultimately approved by FERC would not result in a significant changes to our overall transmission ROEs. While we await FERC's actions settling our actual ROE, we applaud the commission's intention to reduce the volatility of its ROE methodology.
Using a DCF methodology exclusively resulted in wide swings in potential results depending on which companies were at the high-end or the low-end of the peer analysis, and whether the subject company was widely or lightly covered by sell-side analysts. And as you know, there were situations where a change in long-term growth rate estimates for a single company by just one analyst could result in tens of millions of dollars in higher or lower earnings for New England Transmission Owners.
Additionally, it appears that FERC is tightening the threshold to be applied to existing ROEs before it sets an ROE complaint for hearing. We anticipate that changes will provide more stability in transmission returns, thereby encouraging more investment in a critical industry sector.
This order follows the filing of a settlement in August regarding transparency of New England's transmission formula rates. The settlement provides increased transparency, simplicity and the opportunity for various stakeholders to review the annual rates. The settlement is now before the ALJ awaiting certification and after that it will go to the commission for a decision. It followed a lengthy and successful negotiation process between transmission owners and representatives of customers and state regulators, but it does not affect our ROEs.
Finally, I'll turn to our capital program in slide 4. As you probably recall during our August 1 earnings call, we updated our 2019 through 2021 capital program, adding about $600 million of spending in our core business. We continue to refine our estimates for those three years in anticipation of laying out a revised long-term capital investment plan during our February earnings call, and one that will also include estimates for the year 2022.
While we're not yet ready to provide revisions to years 2019, 2020 and 2021, I do expect that the February capital expenditures projection that we incorporate into our 10-K will be higher than the $7.1-billion estimate on this slide. More to come on that early next year as our plans get finalized.
With that, I'll turn the call back over to Jeff for Q&A.
Thank you, Phil. And I'll turn the call back to Hilda to just to remind you how to enter your questions. Hilda?
Thank you. Back to you, sir.
Thank you very much. Our first question this morning is from Greg Gordon from Evercore. Good morning, Greg.
Hey. Good morning, guys. I apologize I dialed in a little bit late because the Vistro call went a little long there. A little bit higher beta than you (00:14:53), so you got to listen to all the Q&A. One, can you just orient us a little bit on you know where the earnings growth targets are now and where your $7.1-billion rate base growth projection you think puts you inside that guidance range?
Yes Craig. Good morning. Thanks for taking this call. I missed this conference call. And as I said before, our earnings growth target is driven by our core business. Our earnings growth is 5% to 7% and we feel comfortable that we'll be in the middle of that range going forward. And really that is driven by the capital program that we have in place at the transmission business, as well as various operating companies. In addition, the strong emphasis that we have and focus on controlling our costs. So really 5% to 7%, in the middle of that is where we've been guiding to.
Okay. So you're in the – you feel like you're tracking to the – all the guidance range today but you just indicated that you're confident that there's additional capital spending that could be added to that plan that would be beneficial to customers. We'll see that in February. Is that going to sort of potentially just extend the growth rate as you move out a year in sort of the – from 2019 to 2021 to maybe 2022, or could that potentially be additive to earnings potential during the current forecast period?
Well it could be it could be both, Greg. As I said that in February we'll be adding a new year on so certainly we'll have to extend or talk about the extension of that 5% to 7% into that time period. And depending on where we land in terms of the customer program – the beneficial nature of these capital programs for our customers, depending on what that ultimately ends up being that could move you in the range. So, I do feel good about where we are and where we're headed.
Okay. One last question then I'll cede to the queue. Customers must be really suffering with high overall energy costs in the region just – especially during the winter months given the potential for ongoing scarcity events in terms of gas supply. How do you think about managing customer rate impacts? How tight do you expect the winter of 2018, 2019 to be, and how might that impact the reliability and how do you plan for that?
Well, certainly fuel security and pricing especially during the winter are key considerations in New England and discussions have been ongoing for a while there as you pointed out. And we do – for our customers as you know we're not in the generation business and we buy our customers who remain with us on last resort or basic service.
We go out into the marketplace every six months to secure their energy needs. And we do see that in the winter that that pricing of those contracts does spike, as a result of constraints in the region. So, we're trying to work through FERC, FERC has dockets open on fuel security there at the ISO. New England is evaluating fuel security and certainly it's an issue that we've tried to be in front of in the region.
In terms of reliability, our reliability is really top tier and we continue to focus on that. But certainly if you take units out of the system like Pilgrim is planning to retire in 2019 that just puts more and more pressure on the constraints in the region.
Thank you guys. Take care.
Thanks, Greg.
Thanks, Greg. Next question is from Mike Weinstein from Credit Suisse. Good morning, Mike.
Hi. Good morning guys.
Good morning.
Hey, I'm wondering if you could maybe bracket or talk a little bit about the annual capital spending that you anticipate from grid monetization in both Connecticut and Massachusetts going forward. I know that this is probably going to be a topic at the EI. But I just wanted to see if maybe you could start talking about it now in terms of how much you anticipate things increasing going forward.
Well, thanks, Mike. I guess it is different by state as you point out you're asking about. In Massachusetts, we really have approval in our current rate plan and additional grid mod provisions for $233 million of spending. And really we're well underway of implementing, the core of that being our energy storage programs. We have two installations for that that are moving along well, as well as initiating our EV infrastructure build in addition to other automation types of projects.
So right now that is the approved level in Massachusetts, $233 million. In the Massachusetts order, they set it up as just like we do more or less for our energy efficiency program where it's going to be an ongoing three-year cycle. So, as we get another year into this program, we'll be filing a plan for the next three-year cycle. So really at this stage the only thing in our plan is what's approved, the $233 million.
In Connecticut, there's a similar – there's a kind of distribution planning /grid mod docket that's been ongoing for many months and really they – it's concluded just recently at the end of October with some hearings. There will be some briefs filed by the end of November, and a decision on that is expected sometime in January of 2019.
And the decision likely will be more what types of things should be put into a filing to go in, it won't be an approval of X amount of dollars for Y number of projects. So, I think we're a little bit away on that in terms of Connecticut and New Hampshire is really in the early stages and has initiated a docket, but there hasn't been any programs approved at this stage.
So, until we get a little bit more clarity, I don't think that by EI we'll have any more clarity than today. So, certainly we think that the programs that we've been implementing in terms of storage and EV infrastructure have a long runway and provide many benefits to customers over many years. So, likely in the future in other grid mod dockets, we'll be filing for programs that address those two issues as well as others. But at this stage, there's no further dollar level associated.
Got you. And on electric transmission given the FERC current – in the latest order and comment regarding the methodology in New England for determining ROEs, are you – if higher ROEs were earned on transmission, would that – are there any specific projects or things that are being held back right now by a lack of a policy or the uncertainty over it that might come out once FERC actually does solidify how it's going to treat those assets?
Well, I think the direction is certainly seems to be converging around sort of the numbers that that we have in place here in Massachusetts now or in New England now and what FERC gave as an illustrative number in that order. So those numbers are good numbers for that business considering the risk profile and how long it takes the site and construct these projects, so certainly – it's in the appropriate zip code.
So I would say there's nothing really that's being held back or nothing that would be advanced per se given where the plus and minus of where that FERC ROE and the incentives are right now.
Okay. Thank you very much.
Thanks, Mike. Next question is from the Angie Storozynski from Macquarie. Good morning, Angie.
Good morning. So I have two questions. One if you could provide us with an update on your water growth plans, I'm talking M&A. I mean what's the current status of your bid or interest in that kind Connecticut Water? And separately on offshore wind, so we saw Ørsted's, the acquisition of Deepwater and I'm just wondering if that's in any way reflective of growth prospects for your joint venture with Ørsted or is it completely unrelated. Thank you.
Yeah, sure. Well, thanks for those questions Angie. In terms of the first one, in terms on the water growth, our outlook hasn't changed there from the – we think that the opportunities in the water business are very synergistic with our business, and we like this. The water growth story there's a lot of infrastructure that needs to be put into the ground. We do think that most of the growth will be through the smaller roll ups of distressed or local water companies in the region. And then we also mentioned that with that there could be some opportunistic larger M&A.
And as you point out, you asked about the Connecticut Water where we're not really involved in that at this stage. We had a bid that was trumped by the other party and we said that we were not going to put in a number that we didn't think created value for our shareholders. So we're not involved in that activity at this stage. And I think they're moving through their shareholder approval process at this stage, and also their regulatory process in both Connecticut and Maine. So, so far we're on the sideline there.
And for offshore wind, we really have a very good relationship with Ørsted, we're fully aligned on Bay State Wind. And we don't see that there's any limit in terms of our opportunities there from what we had expected when we first got involved with the partnership with them.
Just one follow-up, so on Connecticut Water so you are not even participating in the regulatory approval process. I forgot, I thought that you were an intervener or you were planning to be an intervener in that case in Connecticut?
Yes we are an intervener in the regulatory process, that's correct. But in terms of the bidding process for the company, we're not involved. But as an interested party in the area where they operate, we are interveners in the case.
Very good. Thank you.
Thank you, Angie. Next question is from Julien Dumoulin-Smith from Bank of America. Good morning, Julien.
Hey. Good morning team. So just to clarify a little bit on the last question, can you elaborate a little bit more about the opportunities reported from the Deepwater acquisition and how you see it? Just to be clear about this, which project sites are you all thinking about bidding for the upcoming – or as a JV thinking about bidding for these upcoming auctions?
Does it in any way impede it, or conversely, if the added scale when you think about projects and potentially leveraging some of the infrastructure out of Deepwater vis-à-vis transmission or otherwise actually improve the JV's advantage for bidding into some of these upcoming RFPs? I just want to be a little clearer about that?
Sure. I think you asked a number of things there. So just to clarify it, Ørsted and Deepwater were the, are the combination there it's not an Eversource activity, it's Ørsted and Deepwater. And as I said, we're fully aligned on the Bay State Wind partnership, our existing agreements with them anticipate this kind of scenario and we feel very good about the going forward opportunities that exist for the Bay State Wind partnership.
We do have more RFPs scheduled in Massachusetts. As you know that some of those contracts in New England are working their way through the contracting phase or in some cases like in Massachusetts in the regulatory approval process, but there's opportunities coming about in New York. There's RFPs being developed for New York and there's an RFP expected in Massachusetts of about 800 megawatts probably in the first quarter of this year. In Connecticut, there's an open zero carbon RFP that exists. So there's many opportunities that exist that the Bay State Wind partnership is actively involved with and we feel good about what our prospects are moving forward.
Got it. Excellent. And then just a follow up here, obviously some of your peers in the state have encountered some fairly tragic events. How does that modify if at all any of your gas modernization efforts? I know there's a specific modernization filing in the state as well. I mean, just want to make sure we fully understand the read-throughs from the events with [indiscernible} (00:30:19) to you all and any potential upcoming filings that you might be making on the back as well.
Sure. Well, just last night it was announced that there's going to be an independent evaluation statewide of the gas distribution network and the Public Utilities Commission is overseeing that, that's expected to last 90, 120 days. So there may be some items that come out of that review that impact capital plans, et cetera. We've had at our gas property in Mass and in Connecticut, a fairly active and aggressive program to remove and update our leak-prone infrastructure. And really that program since it has been in effect just a few years, we've doubled the spending on that, where we used to spend in the $30 million and $40 million we're spending $90 million on that to replace leak-prone infrastructure and move it out quicker than it would otherwise be.
So between that and other activities that we've done in terms of combining operations and our focus on quality, our quality assurance and that type of thing and operator qualifications, we've done a lot and planning to do a lot in the space going forward.
Got it. All right. Excellent. Thank you all.
Thank you, Julien. Our next question is from Michael Lapides from Goldman. Good morning, Michael.
Good morning, guys. Thank you for taking my question. Just curious when you think about the opportunities to manage O&M further and you've done post the combination with Northeast Utilities a sizable job of kind of controlling costs, where do you think the biggest opportunity sets are from here? I mean, it feels and looks like a lot of the low hanging fruit has already been gotten over the last few years, where is the next incremental step change if there's one?
Well, Michael, thank you. We pride ourselves on really being a leader in terms of being able to manage our business in a cost effective manner. So ultimately, as you know, that benefits our customers. And since the merger, we've taken $500 million of cost out of business really, and at the same time improving our reliability and customer service levels to dramatically better than they were pre-merger.
So you can lower cost and improve service at the same time and we continue to look for opportunities to do that, and a lot of that is driven by automation and consistency of operations between properties across states, standardized equipment, et cetera. So it is – as you point out, the runway gets harder, the low-hanging fruit, as you say, is – there's less of that around. But that doesn't mean that we're not focused on it. And we're still – we guided to 1% or so reduction this year, we're on track to do that.
And really, I'd say, the next wave – when we merge, you can only do so much in the – at one time in terms of changing out systems and standardizing them. And initially some of the systems are more of what you think of as the corporate systems and now we're moving more into our field operations in terms of automation and providing more tools to better serve customers and lower cost. And those are being rolled out now and next year. So I think those will be the drivers going forward in terms of our ability to keep that process – that O&M focus going.
Got it. Okay. One other question for you. We've seen in the Northeast many of the other water utilities kind of aggregate or consolidate some of the municipal water and wastewater systems. How are you thinking about that opportunity set? More importantly, how do you quantify like how big of a potential addressable market that really is for you over the coming years, and if it's something that's easy to bolt into Aquarion or not?
Well Aquarion has over many years rolled in municipal systems and I think we could do more there. I think just given its prior ownership model that inhibited that activity to some extent, so it's not going to drive customer growth by 10% but it's a steady 1%, 2% a year that you can add to customers by rolling up some of these systems.
And really you have a good opportunity in the current environment. What – the current environment is – budgets are tight and environmental regulations are getting more strict. So you've got municipalities saying gee, do I really want to put more pipe in the ground and invest there, do I want a new school or a fire truck, and just with these environmental regulations do I want to be in this business. So, I think, you've got the opportunity and I think you have the environmental framework that would allow some of these to move forward.
And we have actually a few pending right now at PURA in Connecticut for approval, smaller systems we still see that there's an opportunity to continue that path.
Got it. Thank you, guys. Much appreciated.
Thank you, Michael.
Thanks, Michael. The next question is from Paul Patterson from Glenrock. Good morning, Paul.
Good morning. How are you doing?
Good, Paul. How are you?
All right. So I wanted to just follow up on the transmission ROE FERC thing, and I apologize but could you just – you did describe that there was some volatility potentially, I think, with respect to how that proposal might work and – if I heard you correctly. And I was wondering, what were the more recent complaint – what are your calculations for the more recent complaint periods? What would they be if the proposal were enacted as proposed? Do you follow me?
I do, I do follow you, but I just want to clarify that what I spoke about was volatility, actually that's – because of the – introducing an average of multiple methods and by making it a little bit more setting the bar higher in terms of introducing new complaints, that that should mitigate some of the volatility.
Okay. I got you. Okay. I heard you wrong I guess when I was – okay, that makes sense. Okay. Thanks for the clarification.
Yeah it could have been my Boston accent. I'm not sure, Paul. So on that front I think we're in good shape. And we looked at the case and we're reserving, we have looked at our – all of the complaints and really the 10.57% and the cap on the incentives is really – we think kind of handles everything to that level. So if there's a change, we haven't gone through all the details of the calculations because the first calculation then sets the second cancellation, et cetera. But we don't see that there's going to be any big swings.
We've disclosed a 10-basis point, forever we disclosed a 10-basis point change in the ROE could have a $3-million impact. But as I said, the current proposal that's out there, there's briefs that are going to be filed by the parties. All the parties are going to do that in January. Then there's reply briefs, so I think that some of those numbers might continue to evolve but I think we're in a good position right now.
Okay. So just to understand this if – the way it currently looks to you, you'd kind of be in the same ballpark, this 10.41% base ROE for the subsequent complaint periods roughly speaking, I mean there might be some variation but it's kind of in that neighborhood. Am I understanding it right?
Yeah. I think the way we're looking at it now from our preliminary take and again where we continue to work with all of the transmission owners, because this isn't just an Eversource item, this is a regional item that we see that it's about where it is. Right, you're correct.
Okay. And then there was some discussion about incentives when they made this or at least there was some comments, statements. Do you foresee any change in the incentives that FERC has been historically granting in combination with this order or are subsequent to it, or do you have any sense about that at all?
Yeah. I think that they're going to be looking at that. I think that was one of the silent items before, but that is something that I think will be addressed in these briefs and reply briefs that are coming up, but more to come there.
Okay. And then I noticed that Northern Pass is still sort of a topic in New Hampshire. I think it was in the gubernatorial debate just recently. And I just was wondering if there's any – so, I mean I know obviously what happened there, but it's still sort of out there and there has been some issues associated sort of similar to Northern Pass with the (00:40:47) proposal. I'm just wondering if there's sort of any flavor you could give about where Northern Pass or the potential for another Northern Pass kind of thing, or Northern Pass 2.0, whatever you want to call it. How should we think about that going forward?
Well, you may or may not be aware that the New Hampshire Supreme Court has accepted our appeal on the Site Evaluation Committee rulings. So, they did direct the regulators to certify the record and get that back to them next month. So there will be a process where that is evaluated at the New Hampshire Supreme Court in terms of our current Northern Pass proposal. So that still is something that's working its way through in New Hampshire.
It's tough enough for me to forecast the timing of existing projects as opposed to speculating on what might be down the road. But there's certainly aggressive environmental targets that the region has. We've seen an uptick. And even in Massachusetts in the latest session that ended a few months ago, they authorized more offshore wind. And I just think that the tide is going to continue to be looking for projects that deliver clean energy into the region. So what that is right now I can't point to a specific project, but I think if you look – if you see what's out there in the discussion, it's certainly moving to more of that than less.
I guess what I'm wondering is, so – and I apologize for not being more clear. So let's just assume that the Supreme Court that you – that the siting evaluation committee – I guess, the next step would be to see what the siting evaluation – to see how the Supreme Court ruling sort of works its way through that process.
That's correct.
Okay. And then after that I guess we just have to see what what's going on with that.
Yes. That's correct.
Okay. Great. Thanks so much.
Okay. Thanks, Paul.
Thank, Paul. Next question is from Praful Mehta from Citi. Good morning, Praful.
Good morning. Hi, guys.
Hi.
So maybe we touch on offshore wind first, the price of $65, that cleared, and just generally how do you see pricing for offshore wind? There clearly seems to be some disconnect in the market, I wanted to see if you think those prices are too low, or more broadly how do you see the opportunity set for offshore wind relative to the kind of prices that we've been seeing?
Well in terms of the pricing, Praful, we did not win the bid, so the pricing that got accepted was below what we thought was an appropriate bid for the risk profile and the return levels. So, in terms of whether it's appropriate or adequate I think that's best to ask of the winning bidder for that standpoint.
I think that – we had said that in the – from my previous comment you can see there's more and more activity going on out there in terms of offshore wind, more development. And I think as you get more in the ground or in the ocean with these projects, that you have a better supply chain. So I think that if you look at any of these kinds of activities, prices seem to move down, technology gets better, et cetera.
So I'm not sure you know that, that's probably not the question you're asking but the specifics of a price or whatever I think is really up to the party that won at that price to really give some information as to why they think that's appropriate because obviously our pricing wasn't at that level.
Got you. So I guess another way of saying it is, if prices were to stay at these levels do you expect winning bids in the future or do you – I guess, is there still a disconnect?
Sure, I mean, when you say in the future as I said costs change. Prices come down, improvements get made in the supply chain, regulatory uncertainty becomes clearer, so a lot of factors that enter into what's in a bid. You have the price of components. So a lot of factors are there, but you have to keep in mind, you also have tax credits that may not exist in the future. So what impact that has on the pricing and determination that people make too. So if you look at the price sort of absent any tax credits maybe that push – that signals for higher pricing and the tax credits have helped to lower it. So, when you say in the future, it's hard to really determine if – you have to give me what the tax situation is and some other things that you have to factor into the bid.
Yeah, no, agreed and that's super helpful color. So I appreciate that. And then just on Northern Pass quickly. I know I heard all the comments before, so just wanted to clarify, stepping back does that mean that there is still an opportunity given this legal process? Or is that going on more as a check? I guess just put it in context of like does this still – do you still see a realistic possibility of Northern Pass coming back?
Yes. In a short answer, yes.
All right. Okay, perfect. Good to hear. Well, appreciate that. Thank you, guys.
All right. Thanks, Praful. The next question is from Andrew Weisel from Scotia Howard Weil. Good morning, Andrew.
Hey good morning everyone. First just a quick one on the Access Northeast impairment, is that an accounting item or are you no longer going to pursue the project or something similar?
Well, it is an accounting item. It's an accounting determination driven by the facts and circumstances and what the accounting guidance is. So, just to elaborate on that though, certainly the legislation in Massachusetts would have to be in place under the current system to enable a contract to be signed. There was no such legislation that came out of the recent legislative session that ended during the third quarter.
And as somebody alluded to early, we did have an unfortunate incident in Massachusetts that I think may provide difficulty in terms of getting legislation in the future. So, looking at all those facts and the impact that might have on future cash flows, that is a determination that we made to – that the project was impaired.
Okay. Understood. Then, lastly on the balance sheet, I'm not trying to get ahead of the February CapEx update, but how are you thinking about share repurchases? You always thought of that is sort of a backup plan or a support – a safety net to sort of speak, some of these mega projects you've been pursuing seem unlikely to require capital at least in the near-term. So, how much of a cash stockpile do you want to hold on to?
Well, as we said and I will continue to say our business is developing infrastructure and certainly our capital plan – we've added to the capital plan, so that shows that we're investing more of our opportunities set into regulated infrastructure projects, and that would be my expectation that our investments will be – we have a large opportunity set for investments and that's what our focus would be and not really in the share repurchase mode. But we've done share repurchases in the past, people ask about it but it's not really at the top of the list.
All right. Thank you.
Great.
Thank you, Andrew. That was the last question that we had in the queue. So I want to thank you for joining us today. If you have follow-ups please give us a call later today. Good luck with the rest of the call. Take care.
Thank you. Ladies and gentlemen, this concludes today's conference. Thank you for participating. You may now disconnect.