康涅狄格電力 (ES) 2018 Q3 法說會逐字稿

Welcome to the Eversource Energy Third Quarter 2018 Earnings Conference Call.

My name is Hilda and I will be your operator for today.

(Operator Instructions) Please note that this conference is being recorded.

I will now turn the call over to Mr. Jeffrey R. Kotkin, from Eversource Energy.

Sir, you may begin.

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 provision from the 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 3 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, I'm very pleased with the results for the quarter and for the first 9 months of the year.

They'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.

Turning to Slide #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 2 nonrecurring items.

One involves 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 '18, compared to $0.50 per share in third quarter last year.

The primary driver behind the improvement was higher distribution margins.

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 lost-base revenue mechanism resulted in higher year-over-year revenues in peak use quarters such as the third quarter and lower revenues in shoulder 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 & Power.

Our electric transmission segment earned $0.34 per share in the third quarter of '18, compared to $0.31 in the third quarter of '17.

Improved results were due primarily to an increased level of 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 '17.

The change was primarily due to higher operations and maintenance expense in the gas business.

Our water distribution segment, which is new this year as a result of our 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 '18, or less than $0.01 a share, compared with earnings of $0.03 per share in the third quarter of '17.

Parent and other results reflect 2 significant nonrecurring 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's electric utilities cannot sign such contracts without a change in law.

And at this time, despite projected regional energy savings of $1 billion per 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 $0.06 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 and 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 3-year rate proposal.

The settlement is now before regulators for review and we expect the final decision in the fourth quarter.

The rate plan would be effective on November 15, 2018, and includes three moderate increases in distribution rates over a 3-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 in March, 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 5-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 benefit of our customers, rather than spending substantial time and resources on rate issues.

We've also had what I would consider positive news at FERC.

In mid-October, FERC commissioners voted 3 to 0 to implement the new methodology for reviewing and setting 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, 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 decisions, 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 to the ROE complaints to file briefs and their own calculations for a new ROE for the region using the 4 methodologies for each of the 4 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 4 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 4 complaints yet but the illustrative calculation that FERC describes in its order would result in a modestly lower base ROE of 10.41% and a higher cap of 13.08%.

We're still a ways away from a final decision but such levels, if ultimately approved by FERC would not result in significant changes to our overall transmission ROE's.

While we await FERC's actions, setting our actual ROE, we applaud the commission's intention to reduce the volatility of its ROE methodology.

Using the 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.

As you know, there were situations where a change in long-term growth rate estimates for a single company by just 1 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 ROE's before it sets an ROE complaint for hearing.

We anticipate the 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 through the commission for a decision.

It follows the 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 3 years in anticipation of laying out our revised long-term capital investment plan during our February earnings call.

And one that will also include estimates for the year 2022.

While we are not yet ready to provide revisions to years '19, '20 and '21, 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 just to remind you how to enter your questions.

(Operator Instructions)

Thank you very much.

Our first question this morning is from Greg Gordon from Evercore.

I apologize I dialed in a little bit late because the Vistra call went a little long.

They're a little bit higher beta than you so you have to listen to all the Q & A. Can you just orient us a little bit on 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, Greg.

Good morning.

Thanks for taking this call -- this conference call.

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 the 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.

So you feel like you're tracking to the middle of the guidance range today but you just indicated that you are 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 like -- in sort of from '19 to '21 to maybe '22, or could that potentially be additive to earnings potential during the current forecast period?

Well, it could be both, Greg.

As I said, 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 programs -- 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 are headed.

One last question and 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 2019, '20 -- sorry, the winter of 2018, '19, to be and how might that impact reliability and how do you plan for that?

Well certainly, fuel security, pricing, especially during the winter, are key considerations in New England and discussions have been ongoing for a while there, as you point out.

And we do -- for our customers as you know, we are not in the generation business and we buy -- our customers who remain with us on last resort or basic service.

We go out in the marketplace every 6 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 are trying to work through FERC.

FERC has dockets open on fuel security there.

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.

Next question is from Mike Weinstein from Crédit Suisse.

I'm wondering if you could maybe bracket or talk a little bit about the annual capital spending that you anticipate from grid modernization in both Connecticut and Massachusetts going forward.

I know that this is going to be a topic at EEI but I just wanted to see if maybe you could start talking about it now in terms of how you anticipate things increasing going forward?

I guess it is different by state, as you point out, you're asking about that.

In Massachusetts, we really have approval in our current rate plan and additional grid mod provisions for $233 million of spending.

And really, we are well underway of implementing the core of that being our energy storage programs.

We have 2 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 is going to be an ongoing 3-year cycle.

So as we get another year into this program, we'll be filing a plan for the next 3 year cycle.

So really at this stage, the only thing in our plan is what's approved, the $233 million.

In Connecticut, it's similar, there's a kind of distribution planning/grid mod docket that's been ongoing for many months and really it 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 '19.

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 EEI 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 future and other grid mod dockets, we'll be filing for programs that address those 2 issues as well as others.

But at this stage there is no further dollar level associated.

Got you.

And then on your electric transmission, given the FERC current -- latest order and comment regarding the methodology for determining ROEs, are you -- if higher ROEs were earned on transmission -- 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 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 to 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 incentives are right now.

Next question is from Angie Storozynski from Macquarie Research.

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 Connecticut Water?

And separately on Off-Shore Wind, so we saw Ørsted's acquisition of Deepwater and just wondering if that's in any way reflective of growth prospects for your joint venture with Ørsted or is it completely unrelated?

In terms of the first one on the water growth, our outlook hasn't changed there and we think that the opportunities in the water business are very synergistic with our business that we like the water growth story, there's a lot of infrastructure that needs to be put into the ground.

We think that most of the growth will be through these 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.

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 are not involved in that activity at this stage.

I think they're moving through their shareholder approval process at this stage.

And also the regulatory process in both Connecticut and Maine.

So we are on the sideline there and for off-shore wind, really, we really have a good relationship with Ørsted.

We are 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 in the partnership with them.

Just one follow-up so on Connecticut Water.

So you're not even participating in the regulatory approval process?

I forget, I thought that you were an intervenor or even planning to be in 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 intervenors in the case.

Next question is from Julien Dumoulin-Smith of BofA Merrill Lynch.

Just to clarify a little bit on the last question.

Can you elaborate a little bit more about the opportunities afforded from the Deepwater acquisition, and how you see it?

And just to be clear about this, which project sites are you all thinking about bidding for the upcoming -- or as a JV think about bidding for these upcoming auctions?

Does it in any way impede it or conversely is the added scale when you think about projects and potentially leveraging some of the infrastructure out of Deepwater vis-a-vis transmission or otherwise actually improve the JV's vantage for bidding into some of these upcoming RFPs?

Just wanted to be clear about that.

You asked a number of things so just to clarify it's Orsted and Deepwater where the combination here is not an Eversource activity into Ørsted and Deepwater.

And as I said, we are 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 is 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.

Just to follow up.

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?

Just want to make sure that we fully understand the read-throughs from the events with my source here to you all and any potential upcoming filings that you might be making on the back of it as well?

Sure.

Well, just last night it was announced that there was going to be an independent evaluation state-wide of the distribution, 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 Massachusetts and in Connecticut, a fairly active and aggressive program to remove and update our leak-prone infrastructure.

And really that program, since it's been in effect just a few years, we've doubled the spending on that, where we used to spend in the $30 million or $40 million range, we're spending $90 million on that to replace leak-prone infrastructure and move it out quicker than it was -- then 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 in operative qualifications, we've done a lot and plan to do a lot in that space going forward.

Next question is from Michael Lapides of Goldman Sachs.

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?

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 costs out of the business, really and at the same time improving our reliability and customer service levels to dramatically better than they were premerger.

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, there's less of that around.

But that doesn't mean that we're not focused on -- and we still guided to present a certain reduction this year.

We are on track to do that.

And really I'd say the next wave of -- when we merge you can only do so much 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 at lower cost.

And those are being rolled out now and next year but I think those will be the drivers going forward in terms of our ability to keep that process, keep that O&M focus going.

Another 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 and I think just given this 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.

The current environment is budgets are tight, and environmental regulations are getting more strict.

So you've got municipalities saying, "Do I really want to put more pipe in the ground and invest there.

Or 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 there's an opportunity to continue that path.

Next question is from Paul Patterson of Glenrock Associates.

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, if I heard you correctly, and I was wondering what were the most recent complaints, what are your calculations for the more recent complaint periods?

What will they be if the proposal were enacted as proposed?

Do you follow me?

I do follow you, but I just want to clarify that what I spoke about was less volatility actually that -- that because of 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.

I heard you wrong I guess when I was -- okay, that makes sense.

Thanks for the clarification.

It could've been my Boston accent I'm not sure if -- that.

So, on that front I think we're in good shape.

And we look on at the case and we're reserving, we have looked at 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 is a change, we haven't gone through all the details of the calculations because the first calculation then sets the second calculation, et cetera, but we don't see that, that there's going to be any big swings.

We've disclosed a 10- basis points forever, we've disclosed a 10- basis points 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're 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, the way it currently looks to you, you will 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?

Yes.

The way we're looking at it right now with our preliminary take and again, we continue to work with all the transmission owners because this isn't just an Eversource item, this is a regional item.

We see that it's about where it is, right.

You're correct.

And then there was a discussion about incentives when they made this, or at least there were some comments, statements.

Do you foresee any change in the incentives that FERC has been historically granting in combination with this order or subsequent to it?

Or do you have any sense about that at all?

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 notice the 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 -- 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 Avangrid Central Maine proposal.

I'm just wondering if there's any sort of any flavor you can 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 ruling.

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.

Now it's tough enough for me to forecast the timing of the existing projects as opposed to speculating on what might be down the road.

But there's certainly, you know aggressive environmental targets that the region has.

We've seen an uptick even in Massachusetts in the latest session that ended a few months ago.

They've authorized more off-shore 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 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 -- and I apologize for not being more clear.

So let's just assume that the Supreme Court, that you -- that the Site Evaluation Committee -- I guess the next step would be to see what the Site Evaluation -- to see how the Supreme Court ruling sort of works its way through that process?

That's correct.

Okay.

And then after that we just have to see what's going on with that?

Yes, that's correct.

Next question is from Praful Mehta from Citi.

So maybe we'll touch on off-shore wind first.

The price of [65] that cleared, and just generally how do you think pricing for offshore wind-.

There clearly seems to be some disconnect in the market, wanted to see if you think those prices are too low.

Or more broadly how do you see the opportunity set for Off-Shore Wind relative to the kind of prices that we've been seeing?

In terms of the pricing, 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 from my previous comment, there is just more and more activity going on out there in terms of offshore wind and 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 -- and I'm sure you know that, that's probably not the question you're asking but the specifics of a price or whatever, is I think really up to the party that wanted that price to really give some information as to why they think that's appropriate because obviously our pricing wasn't at that level.

So I guess another way of saying it is, if the prices were to stay at these levels, do you expect winning bids in the future?

Or do you -- I guess there's still a disconnect?

Sure.

I mean when you say in the future, as I said, costs change.

Prices come down, improvements get made in supply chain, regulatory certainty becomes clearer.

So a lot of factors enter into what's in a bid.

You have the price of components.

So a lot of factors are there but you also have tax credits that may not exist in the future.

So what impact that has on the pricing and the determination that people make -- so if you look at the price sort of absent any tax credits, maybe that pushed -- 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 it, you have to give me what the tax situation is and some other things that you have to factor into the bid.

And just for Northern Pass quickly.

I know I heard all the comments before but just want to clarify, stepping back does that it means there is an opportunity given this legal process?

Or is that going on more as a check?

I guess to just put it in context, this is still -- you still see a realistic possibility of Northern Pass coming back?

Yes is the short answer, yes.

Next question is from Andrew Weisel of Scotia Howard Weil.

First sort of quick one on the active 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.

Just to elaborate on that, though, certainly, the legislation in Massachusetts would have to be in place under the current system to enable contracts to be signed.

There was no such legislation that came out of the recent legislative session that ended during the third quarter and that somebody alluded to earlier.

We did have an unfortunate incident in Massachusetts that we think may provide difficulty in terms of getting legislation in the future.

So looking at all of those facts and the impact it might have on future cash flows, that is a determination that we made that the project was impaired.

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 as sort of a backup plan or support safety net so to speak.

Some of these megaprojects 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 onto?

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 opportunity-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 on, really not the share repurchase mode.

We've done share repurchases in the past, people ask about it but it's not really on the top of the list.

That was the last question that we had in the queue.

So we want to thank you for joining us today.

If you have any follow-ups, please give us a call later today.

Good luck with the rest of the calls.

Take care.

Ladies and gentlemen this concludes today's conference.

Thank you for participating.

You may now disconnect.