Welcome to the Eversource Energy Earnings Conference Call. My name is Christine, and I will be the operator for today's call. [Operator Instructions] Please note that this conference is being recorded. I will now turn the call over to Mr. Jeffrey Kotkin. You may begin.

Thank you, Christine. Good morning, and thank you for joining us. I'm Jeff Kotkin, Eversource Energy's Vice President for Investor Relations. 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, 2014. Additionally, our explanation of how and why we use certain non-GAAP measures is contained within our news release and in our most recent 10-K. Speaking today will be Jim Judge, our Executive Vice President and CFO; and Lee Olivier, our Executive Vice President for Enterprise, Energy Strategy and Business Development. Also joining us today are Phil Lembo, our Vice President and Treasurer; Jay Buth, our Vice President and Controller; and John Moreira, our new Vice President of Financial Planning and Analysis. Now I will turn over the call to Jim.

Thank you, Jeff, and thank you, all, for joining us this morning. Today, I will cover our first quarter financial results, which were strong and in line with our guidance range for the full year. Our strong operating performance results for the quarter I'll cover as well; an update on several regulatory dockets, which are either pending or recently concluded; and I'll close with an update on certain transmission projects. Before I begin, I want to thank our shareholders who, at our annual meeting yesterday, overwhelmingly approved our legal name change from Northeast Utilities to Eversource Energy. We began trading under the ticker symbol ES on February 19, but our legal name change required the approval of holders of 2/3 of our shares, which we did receive yesterday. Eversource Energy is not only the legal name of our parent company, it is also the brand we're using with customers in each of the 3 states where we provide service. It will not be the legal name of our 6 regulated utility companies, so their debt and preferred stock will continue to be issued and trade under the names Connecticut Light & Power, NSTAR Electric and our other 4 subsidiaries. Now turning to our financial results. Excluding merger-related charges, we earned $257.3 million or $0.81 per share in the first quarter of 2015 compared with earnings of $241.8 million or $0.76 per share in the first quarter of 2014. Overall, these results represent a strong start to the year and reinforce our confidence in our full year earnings projection of $2.75 to $2.90 per share as well as our long-term earnings growth rate of 6% to 8%. Key items affecting earnings include the various impacts of the severe winter we had in New England this year as well as a number…

Thank you, Jim. I will provide you with a brief update on our major capital initiatives and then turn the call back over to Jeff for Q&A. Let's start with what we saw in the New England power markets this winter. Even though spot market wholesale energy prices were lower this past winter than they were in the first quarter of 2014, retail energy prices increased 40% to 50%. This increase was driven by the volatility of last winter and markers pushing wintertime supply risk onto residential and business consumers. Even with lower wholesale electricity prices this past winter, we don't expect that risk premium to go away. First, you have to look at the reasons behind this winter's decline, which start with lower worldwide oil prices; lower oil prices reduce the cost of buying fuel for the region's oil-fired generation; lower worldwide oil prices also caused liquefied natural gas to become cheaper and more plentiful in New England. But all of the structural problems remain in New England. Despite the higher LNG imports, reliance on our older coal and oil units increased over the course of this winter. During peak days in February, these older coal and oil units supplied more than 40% of New England's power needs. During the evening peak on February 15, oil alone accounted for 30% of New England's generation mix, while natural gas only accounted for 17%. Last summer, by contrast, natural gas had accounted for more than 50% of New England's generation mix. This factor caused New England wholesale electricity prices to average $126.70 per megawatt hour in February, the third highest cost on record behind only January and February of last year. And some of the oil and coal units on which we depended upon this winter will soon be retired. Approximately…

Thank you, Lee. And I'm going to return the call to Christine just to remind you how to answer questions. Christine?

[Operator Instructions]

Thank you, Christine. Our first question this morning is from Julien Dumoulin-Smith from UBS.

So perhaps a first quick question, and taking off on the last comment you all made there, if I can ask. Can you elaborate a little bit about other potential projects? I know you said specifically you would provide some more information later. But is the prospect of this being an alternative to Northern Pass? Or how do you think about that as a parallel or alternative to Northern Pass as you see this RFP process moving forward?

Julien, this is Lee Olivier. I don't see them being an alternative for Northern Pass, chiefly because the fact that Northern Pass is essentially hydropower, it's firm, it's fixed, it's large, it has a very high-capacity factor, HVAC lines usually operate in the high 90%. I don't see it as -- these other sources as an alternative to it because those other sources would be a combination of wind and, in some cases, wind with a mixture of run-of-the-river hydro. So they wouldn't have capacity factor. They wouldn't have kind of the certainty that you would have with Northern Pass. However, by their nature, the wind certainly is Class 1 renewables, highly desirable, and there is an opportunity to tap into wind resources in Northern New England and in New York as well, and potentially, over time, in the Maritime Provinces. So there's a lot of potential, but all of that -- or most of that wind would require additional transmission to interconnect into. But I don't see it as a substitute for Northern Pass.

Excellent. And so to that extent do you have any sense on, at least under the RFP terms, what the timeline would be and ultimately any sense of magnitude of potential spend on that front? I know, obviously, it's very early days, but perhaps I can continue to harp on that.

Yes. It's -- right now, we would expect to have the draft out by the end of the second quarter of the RFP. And we could expect bids due sometime probably, I'm guessing, around the late August, September time frame, and contracts awarded by the end of this year, early next year and approval sometime in 2016. And in terms of the total cost that the states are willing to spend on either power purchase agreements for clean or Class 1 energy or infrastructure, that's really not been determined yet. And I think what will happen there is that the states will put the RFP out. They will get bids in. They will evaluate the bids, and they'll evaluate them from a number of standpoints, obviously, cost, sitability, the amount of Class 1 energy that they can bring, the amount of firm fixed energy, the times of the day that would be there [ph], and then they'll make a decision on how much money they want to spend at that period of time.

But do you ultimately see your involvement in bringing some of that Class 1 wind down into your respective service territories? Is that kind of a ballpark?

We do. We do. We see that, in fact, as a big part of our future. And even once you achieve the common goals of approximately 20% renewable portfolio in the region, as everyone knows that number goes down to -- the carbon reductions go down to 80% reduction, and the renewables continue to go up over a period of time. So we see more Class 1 renewables, wind, and other interconnections to either Northern New England or Canada.

And sorry, the first question was kind of a focus on the last comment you made. Bigger picture question here. In terms of the open season, can you comment on the progress and the interest across a variety of parties you're talking to? Just as [indiscernible].

Yes, this is Access Northeast, Julien.

Yes, exactly.

Yes, yes. I would say the interest has been very, very high. And as you know with -- between Eversource and National Grid, there is approximately 70% of the EDC customers in the region that have agreed to go forward with the project. And then there is a number of other EDCs that we are having conversations with now. EDCs, in some cases LDCs. We are having conversation with some generators with expressions of interest around the line to interconnect into the line. So I would say that the open season has gone very, very well for us.

Next question is from Dan Eggers from Crédit Suisse.

Lee, just on Julien's line of questioning on this -- on the New England transmission and clean energy projects. Are they targeting a certain number of megawatts or anything about firm capacity, trying to set a boundary as to where they -- for the threshold? Or is it an option where they're going to take all bids that could qualify and then decide some balance of size and cost as they deem prudent?

I really think it's more of the latter. I mean, each of these states has quantities for Class 1 renewable. And Connecticut can go up to about approximately 200, 250 megawatts of hydro. That's built into their statute. But I think more what they're likely to do is they want to get the bids in, and they go through a comprehensive analysis of really the value of the bids. In other words, can these projects get built? Is there a counter party on the other end of the transmission line? What are the capacity factors? What is the total contribution to RPS portfolio? The total contribution to carbon reduction? Are these resources available during the most challenging periods of the year, which, in the case of New England, is the fall, winter months? And they're going to evaluate those -- against those and other criteria that's very similar, and then they're going to look at where do they want to put their money.

Okay, got it. And then I guess just on the kind of the FERC decision to allow generators to procure your subsidized fuel purchases in advance kind of in this interim period. Is there a limit in the region where you guys run into an environmental compliance or performance standards at the state or federal level as oil takes presumably more share?

Yes. There is limits on all of these old units that burn oil. They are limited to either so many tons or so many days of operation. Each state is a little bit different. Now obviously, if it ran up against whether you keep the lights on or off, I'm sure each of the operators, including ourselves, would seek relief on that. But there are limits to how much carbon that you can put. But it's different by state.

So is carbon the limitation? Or is it kind of like a NOx, SOx particulate issue?

Well, it's more NOx, SOx, but as you know, it directly leads to carbon as well. And the direction of the region is to move to clean energy sources. And as you've heard by my comments, during peak days in February, 40% of all of the energy we were producing was either from coal or oil. So clearly, the policymakers want to move in the opposite direction.

Okay. And then I guess I'm trying to balance out for the quarter how much weather helped versus normal you guys had. Obviously, continued decoupling of CL&P has reduced that amount of exposure. But is the total balance just going to be the $0.02 you guys saw in the gas utility side and then some savings in the O&M? Or where should we calibrate a proper weather-normalized number?

I think the incident is probably about $0.03. We did have sort of a significant increase in gas sales for the quarter, and 20% higher heating degree days really drove that. So approximately $0.03 versus normal.

Okay. So even adjusting for the O&M and kind of the rebalancing of more O&M this quarter because you couldn't do capital, the $0.03 is the good starting point?

It is.

Next question is from Greg Gordon from Evercore.

Most of my questions have been answered. Can you just go through the -- though, what you think the base case is for the timing of [indiscernible] getting fully through the Massachusetts -- sorry, the New Hampshire process, when you'll have sort of the capital return to you from the sale of that asset when you get the securitization bonds and then what the use of proceeds would most likely be and over what time frame?

Sure. Greg, this is Jim. We will be filing the settlement, comprehensive settlement. We have an agreement in principle with those state parties that I mentioned. We'll be filing it in May, hopefully, by mid-May. We expect most of 2015 to be spent at the PUC up there reviewing the settlement. We do have a broad-based coalition in support of it. So we are optimistic the settlement will be approved. Also this year, the securitization legislation is progressing, and we expect that to be approved by the House and then signed by the Governor in the summer. So that puts us into 2016. I think 2016 will be the period where we will actually execute the divestiture and anticipate the awarding of the winning bids in late '16. We will then securitize whatever is not recovered in that transaction. And the use of those proceeds will be applied to future transmission projects to the extent that they appear, and we could use the cash to support that. Or it would be a return of capital, and we would also consider a potential, not only buy-down of debt but share buybacks as well if there wasn't a better use of those proceeds.

Great. So the earnings power of those assets really runs through, for all intents and purposes, the end of fiscal year '16? Should we think about that...

It does. In fact, there's an increase because January of 2016, the full scrubber will be in rates, whereas right now, only about 2/3 of the scrubber is in rates.

Great. And then you get that capital returned to you sort of on or around year-end '16, first quarter '17, and then redeploy that capital accordingly?

That's correct.

Our next question is from Travis Miller from Morningstar.

I was wondering now that oil prices we've had down low for quite a while, even to the extent that a lot of people are forecasting low forever, what has that done to your switching estimates in terms of customers switching from fuel oil to natural gas? Are those -- have your revised any of those? Are you seeing any kind of change there in terms of willingness and economics to switch?

Well, there's no question that sort of the reduction in oil prices sort of reduces the benefit of the conversions. But what I can tell you is that the target that we had in 2013 was about 9,000 customers, and we got 10,000. I think we had a target last year of 10,000 that we got about 10,600. So we've been exceeding targets. And we're pleasantly surprised to see that our target for the first quarter of this year that we had budgeted about 1,800 conversions, and we actually finished the quarter at 2,050. No question, the economics were impacted. Previously, it was a 4-year payback for a resident to recover the cost of the furnace conversion. And now maybe it's increased by a year or 2 in terms of the payback. But thus far, we've been pleasantly surprised at the volume of conversions we've been able to achieve.

Good. That's great. And then the political support continues to be behind the conversion as well?

That's correct. Not only political support, but there's new cost recovery mechanisms in place. In Connecticut and in Massachusetts, they're considering doing the same thing.

Next question is from Andrew Weisel from Macquarie.

First question on Access Northeast. After the conference of governors last week, do you have a sense of how quickly politicians and regulators might actually tweak the rules, specifically in Connecticut and Massachusetts? And then the second part of that question, is how likely is it that all 6 states will participate? And does that even matter if Connecticut and Massachusetts are able to approve the project?

Yes. Andrew, this Lee. Your first question, was it the timing issue of how quickly will they move?

Yes.

Yes, I think they will move very quickly. As you know, there's dockets open in New Hampshire and Massachusetts. And Connecticut is pushing this bill through. So they're doing this, clearly, with the intent of trying to head off the problems that we see in the horizon with generation with Brayton Point, as an example, and Bridgeport Harbor returns. So there's a strong sense that we need to get a pipeline upgrade in service by the winter of 2018, '19. So I would see that there would be a very timely movement forward on this thing. I would say that we -- the project by the middle of this year will have in front of the EDCs, and I would believe the EDCs will have Access Northeast in front of regulators by the middle of this year. And assuming legislation passes in Connecticut, we don't need other legislation in the region, and the PUCs would be set up to make a decision by the end of this year on the project. In regards to all of the states, clearly, Maine is already out with a solicitation for 200,000 dekatherms. I attended the Northeast Conference of Governors last week, and Governor LePage cohosted the meeting, along with Governor Malloy. And he and his Energy Secretary, Patrick Woodcock, are very aggressive around getting this to action. And that's their statements. No more talk, we need action. And I would say it's equally with the Secretaries of Energy in Massachusetts and in Connecticut. And certainly, with the fact that New Hampshire has opened up its own docket investigating the wholesale supply issues in terms of pricing in New Hampshire, said that they are going to move very quickly. And Rhode Island is already there. So it's likely -- it could be all 6 states, but it's more likely a 5 out of the 6 that will move forward in support of upgrades of gas infrastructure.

Great, very helpful. Then on Northern Pass, it looks like you filed an entry into the ISO's electric transmission upgrades queue for a 1,090-megawatt line. Can you talk about what that is, why you added it? And is that an alternative or a tweak to Northern Pass?

Yes. It's really -- what it does, it provides us an option. Clearly, in the DOE EIS study, they're studying a number of ranges around the project, modifications to the projects, the different routes on the project and potentially some additional undergrounding in the project. And basically, this option to go with the 1,090 would suggest using a different technology. And it's just an option. Our preferred route, our stated route is this 1,200-megawatt, 187-mile route as we've laid it out to the DOE. But we want to make sure that we have alternatives that could be approved through the ISO I39 [ph] process that would support the DOE outcome, whatever that may be.

Makes sense. Then lastly, appreciate the clarity on the next rate cases for a bunch of your subsidiaries. Just to clarify, after the NSTAR Gas case is done, when would be the next rate case that you'll file?

Obviously, Andrew, we'll decide that going forward. We're not obligated to file any rate cases after this NSTAR Gas one until 2017. I think in 2017, Connecticut Light & Power is expected to file another case and NSTAR Electric would likely as well. But until then, we're in control of our own destiny in terms of filing a case if we feel it's necessary and appropriate.

Next question is from Shar Pourreza from Guggenheim.

Most of my questions were answered. But just one, on the PSNH generation sale, can you just remind us sort of what you're under-earning on those assets and whether we could see that capital deployed at a relatively quicker pace upon the sale? So some accretive opportunities?

Sure. Shar, we've been earning approximately 8.5%. And the primary reason for that is that some of the scrubber costs have not been allowed into rates. The stipulated return on equity for generation is 9.81%. So we expect to be -- see earning more beginning in January of '16 when the full scrubber is included in rates. And as I said, the proceeds of the transaction, late '16, late '17, in terms of the sale and the securitization of the balance, we will look at what our best investment opportunities are at the time. And we do come up with projects periodically that -- transmission projects or what have you that could use that funding. Or as I said, we would certainly entertain as an alternative paying down capital, both in the form of debt capital as well as share buybacks. So we will assess the best use of those proceeds 1.5 years from now.

Got it. And then just on Access Northeast. Given Eversource and National Grid's, obviously, takeaway capacity as well as EDC and LDC interest, is there an opportunity given the stage that we're at now to look to upside that sort of a little bit over a B a day?

Yes. This is Lee Olivier. There is an opportunity. One of the -- I think, the aspects of our project is that it's, if you will, kind of like a just-in-time project. It's scalable. So we're talking about a Bcf today, and that's a combination of pipeline and LNG storage, which will be crucial for the region. But both our pipeline, the Spectra pipeline, the Algonquin, can be upgraded over time. So it can be scalable over time, along with LNG storage up to over 2 Bcf. But the beauty of this project is you build for what you need versus building a large pipeline that for 8 months out of the year has a very low utilization. We'll have a very high utilization on this initiative.

Our next question is from Paul Patterson from Glenrock.

Just as sort of follow-up on Andrew's questions on this -- I just want to make sure I understand. With the Massachusetts DPU -- this is with the Access Northeast, with the Massachusetts DPU and the Connecticut legislature, what is the time frame they have to act, I guess, in these cases, or legislation in the case of Connecticut vis-à-vis the FERC process, if you follow me? I mean, is there any sort of controlling factor here that we should be thinking about?

Yes. I think, realistically, we need a decision in the fourth quarter this year from, we'll say, the PUCs on the selection of Access Northeast if, indeed, we want to have the pipeline portion of the project in service by the winter of 2018, '19. And the pipeline piece is, it's about 0.5 Bcf. So we need decisions approximately by the end of this year. We will do a FERC prefiling of the project either late in the third quarter, early in the fourth quarter, and then file the full filing in 2016, the middle of 2016. So the timing is that we'll work on getting the precedent agreements signed by the end of June. We will get those before the PUCs in the third quarter, and we need the decision in the fourth quarter because we really want to file our prefiling with FERC, like I say, late in the third, early in the fourth quarter.

Okay. Great. And how much of this would you say is -- of the open season is likely to go, just roughly speaking, to EDCs versus traditional -- more traditional sort of gas customers?

I would think the majority of this will go to EDCs with the potential of -- obviously, we will have some LDC load as well. And then there are some generators that we're in conversations with that we'd like to take gas from it. They don't know if they want to do a long-term contract or do they just want to build a lateral into it. So they build a lateral in. It's like a generator and a connection. They pay for that lateral. But then they have x amount of output, some of which could be very large that they would have available to their plants over the long term, but they would just buy off -- they would buy off the market through that lateral off of Access Northeast. That's probably more likely in that scenario.

Okay, great. And then with Northern Pass, the -- I just wanted to sort of understand, I mean, you guys mentioned the testing and everything that might be happening. When do you think Northern Pass capacity would be available? Do you think it could be available for the Forward Capacity Auction #10? Just wanting to make sure that I sort of -- when Northern Pass might actually be able to be actually entering into the capacity market in New England or...

Yes, I think it's probably more in the 2020 time frame.

Okay, great. And then just finally, you mentioned LePage, and I have to -- he mentioned recently, and I know it's not your service territory, but has there been any -- he's recently mentioned about utilities actually owning [indiscernible]. And I was wondering if that's something that you're hearing among other states as well potentially? Or is that just him?

I have not heard that is a theme among any of the other states that we do business in.

Next question is from Michael Lapides from Goldman Sachs.

Jim, real quick question. Just the $12.4 million after-tax charge related to the FERC ROE decision, what line item does that impact? And you've left that, and you've done this previously in historicals in ongoing earnings. When should we start backing that out, like will that be a nonrecurring event beginning this quarter next year? Or will it start earlier than that sometime in the next couple of quarters?

It's in the revenue line, Michael. And it probably has about a $0.01 drag on earnings going forward on an annual basis. We had several items, as I talked about, in this quarter. The FERC ROE final decision. We had the bad debt remand in Massachusetts as well as the comprehensive settlement of 11 dockets in Massachusetts that were open. The net of all of those was basically a push. In other words, we had planned on all 3 taking place. Some came in higher than we expected. Some came in lower than we expected. But these are sort of -- this is our core bread and butter, right. We're probably among the most purist T&D regulated utilities. So when we get a rate order like this any more than when we got the FERC order last year, we took it to recurring earnings. That's the case here. We don't think anything here should be sort of cut out as a onetime nonrecurring item. It's traditional rate making, which is the business that we're in.

Got it. But when I think about, let's say, the rest of this year, if you've already had a couple of quarters of taking some of the FERC ROE charges, that ramps down during the course of this year. I'm just trying to true things up to what a normalized would be after 2015.

Yes. The 10.57% is what we're assuming going forward is the rate. We still do have 2 dockets open to complaints, as you know. But we do anticipate that, that's going to be -- expected to be within the range of reasonableness, and that will be the rate set going forward. This limitation or clarification that the FERC has made on the ROE cap is about $0.01 hit from what we had anticipated previously.

Got it. And then last question. The discussion about potential legislation in Massachusetts, similar to the one in Connecticut for conversions, can you just need legislation for that? Can that be accomplished via regulation without having to get the state assembly involved? And if so, what's the timeline or kind of the process you think that takes?

We already have the legislation in Massachusetts. It would be up to the PUC, the Department of Public Utilities in Massachusetts, to pursue a similar program to what we are doing in Connecticut.

Got it. They have the legislation, they just need to enact enabling regulation put it into place?

They do.

Next question is from Stephen Byrd from Morgan Stanley.

Just had one question, just on Access Northeast. There's a competitor project as well. When you look out at total demand and think about the prospects, do you see a potential really for there being enough demand for both projects to move forward? How do you think about kind of aggregate demand and how these projects would fit into that picture?

Yes. I guess the way I look at that -- this is Lee Olivier, is that you've got a problem for like 4 months out of the year, and that problem will grow as these older oil and coal-fired power plants shut down over time. So that the winter problem will continue to grow. And so you will continue to need more supply in that 4-month period of time. So essentially, the November through end of March period of time. The remainder of the year, there would potentially -- the 2 major pipelines will be a glut of gas. You're probably not going to have very good utilization in these assets. And so our view is you need assets that are scaled and designed around what the problem is, which is why we think this is a very good solution for New England. And even with our line, clearly, the demand would be very, very high in the winter period of time. But there would be lots of gas at very low prices, very low differential prices from the Marcellus area in New England during the peak periods of the summer and also, of course, the shoulder periods of spring and fall. So we think it's -- we just can't think of a rationale to build 2 very, very large projects at this point in time.

Understood. So if I'm following that, it's really the issue of major overcapacity during the nonpeak demand periods that would cause utilization to kind of be an issue if you had both move forward?

Yes. And do you want to pay for that? Do you want to pay for a lot of capacity that sits idle or partially idle for 8 months out of the year?

The next question is from Caroline Bone from Deutsche Bank.

I'd like to just follow up on an earlier question, that I think it was Paul had asked, on Access Northeast. Lee, I think you said that you'd only expect to have 0.5 B of capacity in service by 2018. Is that what you guys had originally contemplated? And would that 0.5 B of capacity cost $3 billion?

No, what we contemplated in this project is having 1 Bcf, approximately 1 Bcf, between 2018, 2019, with 2018 pipelines coming in service and the 2019 LNG coming in service. And what we would do is we would look at bridging contracts in between those with existing LNG facilities. But if you look at the $3 billion contract, not all of that was geared towards -- to the EDCs. There's approximately $600 million to $700 million of that, that was geared towards interconnecting LDCs as well.

So that spending will take place just now in the pipeline at the same kind of time in parallel to the construction or the expansion of the pipeline?

It will actually happen in -- all in a similar time line.

Okay, great. And then just one follow-up on Northern Pass. Can you just help us better understand what the delay might mean for your capital plans, if anything really significant?

There isn't really any major shift. The spending will be largely incurred through 2018 absent the fact that the testing is going to have to delay until we get to the winter period. But we have -- we provided CapEx guidance for our transmission projects, including Northern Pass. And when we look at the shifts, there were some other shifts going the other way. In particular, we have refined our estimates to the Greater Hartford project and the Greater Boston project as well, which actually advanced some spending from what we thought previously. So the CapEx that we provided start of the year is still sort of valid from our perspective.

Our next question is from Steve Fleishman from Wolfe.

I may just more bluntly ask the same question. Just in terms of your targeted 6% to 8% growth rate, the move in Northern Pass, the potential shift of stuff, that growth rate is still good? No, this doesn't affect that at all?

Doesn't affect it at all. We're still comfortable with the long-range growth rate of 6% to 8% through 2018.

Is there a year-to-year issue that comes up from that? Or is it -- are you thinking more back-ended than before?

That's the -- As I say, we've had some shifting in terms of Northern Pass cash flows, but there have been shifts forward of other projects as we refined our estimates. So we continue to be very comfortable. We're more confident than ever, I would say, on the 2 projects, Northern Pass and Access Northeast, based upon the groundswell of support that we're getting, not only from governors but energy policymakers throughout the region. When you have customers now seeing in Massachusetts energy service rates of $0.15 a kilowatt hour, there's a lot of public reaction. And I think people realize that even if we move quickly here, these projects are not going to be solved next winter or the winter after that or the winter after that. But if we move quick enough, we can get resolution of these problems in the '18, '19 winter. So I think there's more momentum for these projects than we've ever had. And who knows, there may be additional projects down the line that would further [indiscernible] 6% to 8% growth rate going forward.

Next question is from Greg Gordon from Evercore again. Okay. All right. Well, it looks like we don't have any more folks in the queue. If there's any follow-up questions, please give us a call. Thank you very much for joining us this morning.

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