Welcome to the Eversource Energy Third Quarter Earnings 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 would now like to turn the call over to Mr. Jeffrey Kotkin. Sir, you may begin.

Thank you, Hilda. Good morning and thank you for joining us today. I'm Jeff Kotkin, Eversource Energy's Vice President for Investor Relations. 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, 2015 and our Form 10-Q for the period ended June 30, 2016. 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 on our website under Presentations & Webcasts and in our most recent 10-K. Turning to slide 2. Speaking today will be Phil Lembo, our Executive Vice President, CFO and Treasurer; and Lee Olivier, our Executive Vice President for Enterprise Energy Strategy & Business Development. Also joining us today are Werner Schweiger, our Executive Vice President and COO; Jay Buth, our Vice President and Controller; and John Moreira, our Vice President of Financial Planning and Analysis. Now, I will turn to slide 3 and turn over the call to Phil.

Thank you, Jeff, and thank you all for joining us this morning. Today, I'll cover our third quarter and year-to-date financial results, provide an update on certain transmission projects and discuss recent legislative and regulatory developments in the three states. So let's start with the quarter on slide 4. We earned $265.3 million or $0.83 per share in the third quarter of 2016, compared with earnings of $235.9 million or $0.74 per share in the third quarter of 2015. Our Transmission segment earned $0.28 per share in the third quarter of 2016, compared with $0.24 per share in the third quarter last year. The primary driver of the earnings growth is a higher transmission rate base, which is due to our continued needed investment in the reliability of the New England power grid. I'll summarize some of our key reliability-driven transmission projects in a minute. On the Electric Distribution and Generation side, we earned $0.53 per share in the third quarter of 2016, which is the same number as the third quarter of 2015. High distribution revenues were largely offset by higher depreciation, property taxes and interest costs. On the Natural Gas side, we lost $0.02 per share in the third quarter of 2016, compared to a loss of $0.01 per share in the third quarter of last year. Higher interest and taxes more than offset the benefits of a rate increase at NSTAR Gas and the increased revenues from our natural gas infrastructure tracking mechanisms. Turning from the third quarter to the year-to-date results, we earned $713.1 million or $2.24 per share in the first nine months of 2016, compared with earnings of $696.7 million or $2.19 per share in the first nine months of 2015. In our earnings press release, we reiterated both our 5% to 7% long-term…

Okay. Thanks, Phil. I'll provide you with a brief update on our major investment initiatives and then turn the call back to Jeff for Q&As. Let's start with Northern Pass in slide 10. There's been a number of developments involving Northern Pass since our late July earnings call. On October 14, the New Hampshire Public Utility Commission issued an order authorizing Northern Pass to do business as a New Hampshire utility. In reaching its decision, the commission approved a settlement agreement between Northern Pass and the PUC staff that determined that Northern Pass had the technical, managerial and financial expertise to operate as a public utility. The PUC further concluded that "granting Northern Pass authority to commence business as a public utility is for the public good". We're pleased to have received this important foundational ruling. In September and October, the New Hampshire Site Evaluation Committee or SEC held more than 20 days of hearings or technical sessions on the project, which featured 10 panels of witnesses on topics that included system stability, reliability, project construction and historical resources. The sessions allowed interveners to question our witnesses on all aspects of the project based on testimony that was submitted as part of the SEC application last fall. We are very pleased with how well these sessions went overall. They were an excellent opportunity for us to demonstrate the thoughtful planning, design and engineering that we have already devoted to this project, and to underscore the significant economic and environmental benefits Northern Pass will provide to the region. The next key milestone is the submission of intervener testimony in mid-November. Reports from the state agencies that are reviewing the project are due to the Site Evaluation Committee by March 1, and we anticipate the final committee hearings starting in April of…

Thank you, Lee. And I'm going to turn the call back to Hilda just to remind you how to enter questions. Hilda?

Thank you.

All right. Our first question this morning is from Mike Weinstein from Credit Suisse. Good morning, Mike. Michael Weinstein - Credit Suisse Securities (USA) LLC (Broker): Hey. Good morning, guys. Thanks, Lee. Hey. For Access Northeast, would changes to serve LDCs allow the project to proceed without the need for any additional legislation?

Mike, this is Lee. It would really depend on the scope, in other words, the scale of those contracts that could be obtained. You have the Kinder project signed up nearly 500,000 dekatherms, 0.5 Bcf, with contracts that had been approved by their respective regulators in, essentially, Massachusetts and New Hampshire. So, once you start getting up around 500,000 dekatherms, that makes the project more viable. But we have not made a complete determination on that yet because we still think there is a need for the EDC participation in the other states. So we think there could be a hybrid solution of both LDCs and EDC contracts. Michael Weinstein - Credit Suisse Securities (USA) LLC (Broker): I guess what I'm thinking is that if it's not reliant on EDC contracts then, if you can get enough LDCs to participate, you wouldn't need any, I guess, special consideration from the Commission where electric customers are supporting the project.

Yeah. That would be true, but it would likely be a smaller project than the 900,000 dekatherms that we originally outlined. Michael Weinstein - Credit Suisse Securities (USA) LLC (Broker): And on Clean Energy Connect, I think you mentioned that it now supports hydropower as well. I thought that Energy Connect was mostly from supporting wind power in New York State?

Yes. Clean Energy Connect was the combination of existing Brookfield run-of-the-river hydro facilities; in other words, hydro facilities that are old or mostly depreciated and building of new wind by two other entities, which was Iberdrola and EDP. So you would marry up essentially 600 megawatts of wind, 700 megawatts of hydro, you would have ended up with about a 85% capacity factor over the line with having that run-of-the- river hydro balance it. Michael Weinstein - Credit Suisse Securities (USA) LLC (Broker): Okay. I see. And just back on Access Northeast for a second, if the project begins construction 2019, you're looking at getting it online no earlier than spring of 2020 or late 2020?

It'd be late 2020. Michael Weinstein - Credit Suisse Securities (USA) LLC (Broker): Late. Okay.

In the fall, yeah. Michael Weinstein - Credit Suisse Securities (USA) LLC (Broker): Thank you.

All right. Thanks, Mike. Next question this morning is from Travis Miller from Morningstar. Good morning, Travis.

Good morning. Thank you. I was wondering, you talked about the winter and the gas demand and stuff. As we go into the season, you talked a lot about the constraints that still are there. What has improved since the last, say, two winters when there were the constraints – or not so much last winter, but two, three winters ago?

The fundamental improvement for now for this winter would be that the Spectra Energy AIM Project, which delivers about 345,000 dekatherms. The first phase of that came on, on November 1, delivering about 245,000 dekatherms, and then the remainder of that is expected to come on either later this month or in December, which would give you about a total of 345,000 dekatherms. And probably the way to look at that is, if you add AIM in and then you retire Breaking Point, next year they kind of wash each other out.

Okay. Okay. Got it. And then, on the offshore wind stuff, what recognition among regulators is there that this would most likely lead to higher customer prices? Is that something that's being discussed and being considered at a high level, or is this just the run to get renewables into the mix?

I would just say on that, following what's taken place in Europe, and I think the U.S. will have a major advantage, because Europe, pretty much where most of this development started, was much higher on the cost curve. And they're coming down on the back side of the cost curve. So you've seen cost as high as $0.24, $0.25 a kilowatt hour. Our recent tenders done in Europe and Holland for less than $0.10 per kilowatt hour. So we believe with the economy of scale and the development in places such as in Asia or China, which is starting to take place now in Taiwan, we will see a fairly dramatic decrease. I think the other thing that you have to remember too is that the load centers in New England are on the shoreline. And if you have offshore wind, it's closer to the load. And so therefore, your transmission costs decline significantly. And offshore wind comes on essentially 10 turbines at a time. It doesn't come on like a traditional generator where you spend five years building 1,000 megawatts and one push to the button it all comes on. It's every 8 (31:53) megawatts that comes on. So it rolls in over time. It has a better cost recovery curve as well.

Yeah. I think also, Travis, there's a recognition that there's a mix of solutions that are needed to meet aggressive carbon reduction targets as well. So you've got a mix of needs in terms of bringing more gas. Wind and solar play a part too. So there's many fronts that need additional supply to come into the region.

Okay. Great. I really appreciate the thoughts.

All right.

Thanks, Travis. Next question is from Paul Patterson from Glenrock. Morning, Paul.

Good morning. I wanted to follow-up on Mike Weinstein's question. If I heard the answer, it sounded to me that there would be a smaller project in the absence of the passage of Massachusetts legislation for Access Northeast. Is that correct?

Yeah. Paul, this is Lee. I think it's too early to determine that because we're still in the process of understanding the LDC load. I can tell you there is strong interest from the governors of the two bigger states that we've talked to recently on having an EDC solution as well. And you've got Maine and Rhode Island that are still in the hunt. We recently met with the Connecticut governing agency and their view is that, need some new solutions, but we fully support gas, bring us back some solutions to consider. So you've got three states that clearly want an EDC solution. And so it's kind of marrying up that with a large enough LDC solution to make for a project that will have a meaningful difference in the region in terms of reliability and price stability and lowering the differential between the region, as an example, MISO and PJM, which is about a 50% differential higher in the winter time. So we're still advocating for a project upscale that can make that difference.

Okay. So, I mean, I guess I misheard the – I thought it sounded like you might be less than 900 (sic) [900,000] (34:27) dekatherms, if it wasn't for the EDC participation in Massachusetts.

Yeah. Well, the question was that, if it was only LDC, would it be the same size of Access Northeast of 900,000 dekatherms. The answer to that, it was only LDC? No. It would not be.

Okay. And that's only LDC in Massachusetts or is that – I mean, the way it's – let me ask you the question this way. The feeling I got is that, because of the Massachusetts Supreme Court ruling, the other states seem to have – at least some of them seem to have some issues about going ahead with something without Massachusetts fully on board. Is that a correct way of summarizing it or do you see it...

I think there needs to be a take of gas and obviously the related revenue requirements with it for Massachusetts. But if you go back and look at the previous contracts that were signed by LDCs in the old Kinder project, majority of those are in Massachusetts. And, of course, gas customers are electric customers as well. So it could be picked up by gas customers. But in essence, the state makes the contribution because gas customers are electric customers.

I got you. And then Phil made a statement about the renewable RFP where the hydro bids or whatever were not selected, and it sounded like there might have been a technical reason for that. Did I understand that correctly? In other words, it wasn't conforming to – it was an issue of whether or not the bids you guys had proposed did not conform to some specific technical element of it. Is that the reason why it was rejected? Or was there some other issue?

One aspect, Paul, this is Phil, is sort of subsequent to the RFP going out, Massachusetts passed specific legislation enabling hydro in terms of contracting. So, certainly on the Massachusetts side, the legislation that came in subsequent to the RFP being issued provided us specific authorization. So the timing was, the RFP started, but then the legislation happened. So, now, we have specific legislation, as I indicated, to cover a solicitation for hydro in Massachusetts.

Yeah. And I would add that, if you look at the statutory authority of the three states, they could have bought up to 5 terawatt hours of energy. And they bought 0.9 terawatt hours. So they bought 17% of what they were authorized to buy. The majority of that energy is in solar. And obviously, on a cold winter day at 4 o'clock, you're not going to get that energy and two-thirds of it is really solar. So they bought small facilities. Nothing like...

Why is that? Why didn't they buy more?

Well, it's just – you've got three states and they have different needs. As an example, Connecticut, on their carbon goal is doing very good. In other words, they've got a goal by 2020 of 39 million tons a year. They're at 40 million tons now. So they said, hey, look, we'd just rather buy best one in renewables right now. And as Phil said, Massachusetts in that solicitation didn't really have authorization to buy hydro. But now that they will, in April they'd be able to buy a large tranche of hydro, almost 10 terawatt hours. So it's a little bit of the construct and the timing, but that's kind of how it ended up.

Okay. I appreciate it. Thank you very much.

Yeah.

Thanks, Paul. Our next question is from Caroline Bone from Deutsche Bank. Good morning, Caroline.

Hey. Good morning, guys. I was just wondering could you just talk about the options you have to offset the impact to earnings from a 9-months to 12-months delay in Access Northeast?

Yeah. I think that – this is Phil, Caroline. If you look at our growth rate through 2019, there's not a significant amount of Access Northeast in there. So, if you assume that it's still in that time period, you're fairly close just in terms of the spending that, even with the delay, that it would not have a significant impact there. So we've looked, as we did mention with the NPT, if there's other transmission projects, and as you've seen, we found additional reliability projects. We have additional trans investment in our gas infrastructure, the Massachusetts solar program. So there is a number of initiatives that could fill that. But it's not a significant number.

Okay. Fair enough. And then with regards to the transmission you guys might get involved with to connect offshore wind in Massachusetts, I know this is kind of far down the road here, but can you discuss how cost recovery would likely work?

How cost recovery would likely work? That whole framework is still being worked out, being discussed and flexed. There's really no specifics. There's couple of notions, one that the state could do kind of a broad RFP for a transmission highway that would interconnect the six parcels of water back into the mainland and folks would bid on that. There could be one or multiple winners on that for design kind of EPC construction. And the other one is basically that each developer, which is pretty consistent with what takes place currently in Europe, each developer bids their project and they bid whatever, 400 megawatts, 600 megawatts, 800 megawatts, whatever the bid is in terms of megawatts, they build their own offshore substations and they build the cables that run into the mainland and interconnect into the existing transmission system. Which really means all that would be onshore would be a substation and an interconnection to the 345 kV grid. So it's not really been determined exactly how that will work, but that is a topic of discussion that is taking place inside of the Commonwealth.

Okay. And then, just one final one on a different topic. I know we have kind of the NSTAR Electric rate case finally on the horizon. Can you just remind us how much rate base is currently at NSTAR Electric distribution specifically?

Yeah. Yeah. 2.7, 2.8; in that range.

Okay. Great. That's it. Thanks, guys.

All right.

Thank you.

Thank you, Caroline. Next question is from Shar Pourreza from Guggenheim. Good morning, Shar.

Hey, guys. Sorry, I had to hop in late and I apologize if this was addressed. Lee, let me ask you. So, in Access Northeast, it sounds like a solution could be EDCs for states like Vermont, Rhode Island, Connecticut, and LDC demand in Massachusetts. Would the Clean Energy – I'm sorry, the Kinder project that was canceled, the Northeast Direct, it sounds like out of 1 Bcf per day for Access Northeast, you could generally account for Massachusetts just by the customers that were signed up for the Kinder pipe.

Yeah. There is a potential to get very close to that. So Massachusetts created a 42% hole in the project when they couldn't sign contracts. That's about 400,000 dekatherms or so. And there's a fairly large LDC demand in Massachusetts as well. So it could come pretty close to that.

How is the dialogue going with the offtakers of the canceled pipe?

We have our folks at Spectra that really conduct that dialogue for us because that's kind of what they do around the nation. So I could only characterize it as an ongoing process.

Okay. Great. And then on New Hampshire, obviously, with the recent ruling, it's 10% of the pipe. Can you theoretically just bypass New Hampshire and socialize the cost through the rest of the New England region, just given the fact that it's such a small piece of that pipe?

Yeah. I mean, I think that when the regional states, all the states in the region and led by the governors quite frankly, put this construct together, it was with the understanding that each state would take its load share of the gas. So our view on that is we still think there's an opportunity for having New Hampshire take their respective load, which is not big as granted as you said. But we're still committed to work with the other governors and work with the State of New Hampshire to find a pathway through where they pay for their share of the gas.

Right. Right. And then let me just ask you a little bit more sort of just top-level question on the growth. I mean, obviously, investors are going to shift to 2020 and beyond, especially now given the delay of Access Northeast, which hopefully wasn't a surprise to people. But the question is, knowing how you've been able to backfill your growth, knowing sort of the reliability spending, you've done a pretty good job about negating the delay of Northern Pass, do you sort of envision I mean 5% to 7% potentially being put in jeopardy if Access Northeast is further delayed ? Or do you have enough in that pipeline, no pun intended, but do you have enough in that pipeline in reliability or whatever spend that you have that you don't envision 5% to 7% being impacted?

So I know you said you may have jumped on late. I think, in the actual prepared remarks, I did reiterate our comfort and our guidance of the 5% to 7% earnings growth range. And so we're very comfortable there. Also, as you know, in February, we'll be doing an update of our outlook and adding another year and giving more visibility on the capital and have sort of outlined, as you mentioned, the hole and how to fill that in terms of transmission, gas, the solar project in Massachusetts. So we feel good about that rate and we'll have more information in terms of adding another year on when we get to the February time period.

Excellent. Thanks, guys.

You're welcome.

Thanks, Shahriar. Next question is from Mike Gaugler from Janney. Good morning, Mike.

Hey. Good morning, everyone. Nice quarter.

Thank you.

Given the delay in Access Northeast and other new capacity pipeline cancelations, just wondering how you're thinking about new reliability projects, as the existing capacity has to be spread more thinly. Or wondering has that optionality essentially been exhausted with the projects that are already announced and underway?

Yeah. Mike, this is Lee. I think the reliability projects that have been built and are under construction and under review are all traced to either situations where there is current overloads or current violations of NERC criteria. And so, therefore, they're being built out to correct that. Most of the future reliability – or future transmission rather that will be needed in the region will not be reliability-based. It will be needed to connect renewables from a source, whether that's offshore, in Canada or now the New England such as Maine, to get that renewable energy into the load. So it's nature. It will be less around what we've done over the last 10 years and more around interconnecting renewables to get it to the load.

Okay.

And, Michael, this is Phil too. Just in terms of the specific items, I know you're talking about additional or future items, but there are still several ongoing reliability projects that we have that we're having significant spend on through the next several years in terms of Greater Hartford or Greater Boston and projects in New Hampshire, which may need some additional transmission in New Hampshire more than they've had in recent years. So there's good amount in the pipeline. And as Lee said, the nature of some of that going forward could change. But the pipeline is robust at this stage.

All right. That's all I had, gentlemen. Thank you.

All right. Well, thanks, Mike. That's the last question that we have this morning. So thank you very much for joining us today. We look forward to seeing many of you at the EEI Conference next week. Take care.

Thank you. Ladies and gentlemen, this concludes today's conference. Thank you for your participation. You may now disconnect.