Welcome to the Northeast Utilities Q3 Earnings Call. My name is John and I will be your operator for today's call. [Operator Instructions] Please note that this conference is being recorded. And I will now turn the call over to Jeff Kotkin. You may begin, Jeff.

Thank you, John. Good morning and thank you for joining us. I'm Jeff Kotkin, NU's Vice President for Investor Relations. Speaking today will be Jim Judge, NU Executive Vice President and Chief Financial Officer; and Lee Olivier, NU Executive Vice President and Chief Operating Officer. Also joining us today are Jim Muntz, President of our Transmission business; Jay Buth, our Controller, Phil Lembo, our Treasurer; and John Moreira, our Director of Corporate Financial Forecasting and Investor Relations. Before we begin, I'd like to remind you that 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 we issued yesterday. If you have not yet seen that news release, it is posted on our website at www.nu.com and has been filed as an exhibit to our Form 8-K. 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, 2012, and our Form 10-Q for the 6 months ended June 30, 2013. 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. Now, I will turn over the call over to Jim.

Thank you, Jeff. And thank you, everyone, for joining us this morning. We really do appreciate your participation in today's earnings call. I know that there is some competition for your time this morning. I apologize upfront for my voice, I picked up a bad cold. Bad news is I have a cold. The good news is I actually caught it at the 6th game of the World Series, which you may have heard turned out very well. In my remarks today, I will discuss our third quarter financial results, an update on our integration efforts, economic conditions in our region and I'll conclude my remarks with an update on regulatory and legislative matters, including ongoing developments in New Hampshire related to our generation assets, the New England transmission owners' ROE proceeding before FERC and the status of our storm cost filings in Connecticut and Massachusetts. As you probably saw, we released our Q3 2013 earnings after yesterday's market close. Excluding merger-related and integration costs, we earned $216 million or $0.69 per share this quarter, compared to $220 million or $0.70 per share for the same period last year. Merger integration costs were $0.03 per share in the third quarter of 2013, as compared to $0.04 per share last year. These costs reflect the recognition of costs to achieve our merger integration initiatives. For the current 9-month period, we earned $619 million or $1.96 per share, compared to $457 million or $1.72 per share, excluding merger-related and integration costs from both periods. Note that last year's results excluded NSTAR'S first quarter earnings. We recognize the charge of $14.3 million or $0.05 per share on an after-tax basis this quarter, related to a recommendation by a FERC administrative law judge, that if approved by FERC commissioners, would lower our base transmission…

Thank you, Jim. I'll provide you with an update on our major capital projects and our natural gas expansion initiatives and then turn the call back over to Jeff for Q&As. I will begin with transmission in our NEEWS family of projects. Our Greater Springfield Reliability project is now approximately 98% complete and will be done by the end of this year. We expect the project to be completed at a cost of approximately 6% below its $718 million estimate. Both the completion of this critical reliability project and its lower-than-budgeted cost represent good news for our customers since they will receive the benefit of increased reliability and the elimination of the essentially all congestion costs in that area of New England. Turning to the Interstate Reliability project, a joint effort with National Grid, hearings before the Massachusetts Energy Facility Siting Board were completed last quarter and post-hearing briefs are due early this month. We now have all of the state environmental permits and continue to expect decisions from the EFSB and Army Corps of Engineers in the second quarter of 2014 and for line construction to begin mid-year, with completion in late 2015. You may recall that early this year, we and National Grid received project approval from siting regulators in Connecticut and Rhode Island. We continue to estimate that our section of the project, the park located in Connecticut, will cost $218 million. There is no new information on the Greater Hartford, Central Connecticut set of projects. We expect ISO to confirm the set of needed projects in the first half of 2014, and if left unchanged, our $300 million cost estimate and our 2017 completion date for these projects. We continue to make progress on our $1.4 billion Northern Pass project. The Department of Energy has completed…

Thank you, Lee. And I'm going to turn it back to John just to remind you how to enter questions.

[Operator Instructions]

Thank you, John. Our first question this morning is from Kevin Cole of Crédit Suisse. Kevin Cole - Crédit Suisse AG, Research Division: I guess, Lee -- I guess, to your last point on the loss of Vermont Yankee, Britain point and the DR, how much of that congestion or reserve margin loss in New England can be fixed from incremental transmission versus new generation?

When we look at this, Kevin, I think it's clear that out in the fuller capacity mark, as in 2018 timeframe, there will be an impact on that marketplace. So there will start to be a shortage of capacity, which will cause capacity prices to go up. As you know, the majority of the generation that is being built in the region is from the north. And the north/south interface is constrained. So the generation out there, which is going to be wind for the most part, we'll need transmission upgrades to be able to break the bottlenecks and get the wind energy down into the marketplace, into the Boston and into the Connecticut marketplace. So you're looking at 2 issues. One, you're looking at a capacity shortfall in the 2018 timeframe. Second, you're looking at more transmission to get renewable energy to the marketplace. And I think the other thing that we have to remember is that just as they're seeing in places like Britain, in Germany, the more intermittent power that you build, the more issues you have with grid reliability and actually, the more fossil generation plants that you have to build, which do 2 things: one, that adds carbon, number 1; and number 2, it adds cost to running the system. So when you evaluate this, you have to evaluate those aspects as well. Kevin Cole - Crédit Suisse AG, Research Division: So I guess, the process is then -- so replacement generation will first to be bid in 1; and then once the capacity is bid, then the ISO will take up the transmission integration?

That is the general process. I think the only other factor that has to be evaluated is the fact that, with all of this wind energy being built in essentially, for the most part, Maine, it has to dispatch. So there's only so much load in Maine, so it has to find a place to go. So there will be a need to build transmission to get that wind to the market that will probably precede the forward capacity market. Kevin Cole - Crédit Suisse AG, Research Division: Okay. Will this be an initiative that's taken up next year?

It's -- there's no firm schedule, but it's highly likely that's the case. Kevin Cole - Crédit Suisse AG, Research Division: Okay. Then last question, is there any amount of system tightening that could result in Northern Pass becoming a reliability project?

Well, it's certainly -- it gets to the extent of what the retirements are. And the projection of retirements are anywhere from 6,000 to 8,000 megawatts, Northern Pass, being an HVDC line, essentially acts as a generator lead. So it's really sold on the fact that it's a commercial project, an economic project to get renewable energy, but will also have a positive reliability impact to the region as well and potentially could be considered as we go forward.

Our next question is from Travis Miller from Morningstar.

Question on the transmission stuff. One, just a clarification. The 10.6 obviously, October '11 and December '12, if they were to approve that 9 7 [ph] or whatever they approve next year, would that be retroactive to Jan 1 of this year?

It's unclear, Travis. FERC historically has prescribed a 15-month refund period and that's at October, through October '11 through December of '12. There has been action seeking a refund for the subsequent period, but FERC has not acted on that. So until the FERC makes a final decision on the going forward rate, the perspective rate, it's not clear what would happen during that interim period. Potentially, it could be continued to be the 11.14% that we have earned historically.

Okay. So then -- so you took the charge for 10.6, but then starting January 1, you actually have the 11 1 4 [ph] that you've been earning on, right? So then you potentially could get back -- could give back then, whatever that decision is, the decision net of the 11 1 4 [ph] then, right? Am I kind of thinking about that right?

Yes. I mean, clearly they...

Go up and then they come down.

It depends on what FERC ultimately does. As treasuries move up, the 11 1 4 [ph] may be deemed to be still within the range of reasonableness and we continue going forward. What we do know is the fact that the 10.6 was sort of providing an opportunity to estimate, a reasonable estimate of the what the refund could be for the refund period. We felt it was appropriate to take that reserve this quarter. And my expectation is that other utilities may have done the same.

Okay. Yes, I got it. And then strategically, if the Commission will come back with something like a 9 7 [ph] or something 10, something that you guys obviously aren't supportive of, how does that affect your 2015, 2016 plans? Some of the stuff, the projects that you discussed, talked about being on the horizon, how would that affect your transmission investment plan?

That remains to be seen. Clearly, the FERC would like to continue to see utilities incented to invest in the transmission infrastructure. If there was a major dislocation of the return potential in that business, you may see, not only Northeast Utilities, but other transmission owners reassess whether or not their investments are warranted going forward or whether there's better investment opportunities in the distribution business, for instance. So we hope, we expect that FERC will issue an ROE here that continues to provide a fair return, continues to incent the investment in projects that they have been able to do historically for the last several years.

Next question's from Neil Mehta from Goldman Sachs.

It sounds like TDI New England put out a release last night indicating that they're going to look to develop 1,000-megawatt project to bring some capacity from Québec into Vermont. Do you see that as a competitive threat to Hydro-Québec?

No. Neil, this is Lee Olivier. No, I actually don't. I would just say a couple of things on that. One is just going through the numbers around the capacity situation in new England, you take into consideration the 6,000 to 8,000 megawatts that will retire, the fact that we're over 52% on gas, that no other fuels, you've got aging nuclear fleet here, there's a lot of variables that says that we need more energy that is clean coming into the region. The other thing that I would say is that this project is unlike our project. It is a project that really is a merchant line. They don't have a counterparty on the other end of it. We've got a counterparty on the other end of ours. They're willing to pay for our line. And we have significant -- along with Hydro-Québec, significant developmental experience in building these lines. So the TDI line is a merchant line without a counterparty. Its connection into the AC system would require extensive AC upgrades, all of which would be added to the cost of that project. And I guess we would assess it as one more merchant project, as a half a dozen or so in new England that have just quite frankly, never got off the ground and show no signs of getting off the ground at this time.

And could you just respond to some of the golf course litigation and the various comments by governors in New Hampshire and Vermont and whether you think that will impact timing as you look at the project?

Yes. I -- just, I won't go into any level of specificity with the Owl's Nest litigation, just to say that we think their claim is without merit. The transmission line was there before. Their resort was developed specifically understanding that we would or could further develop that transmission right away. I think they're just facing an economic situation just because of the economy. It's a fine resort. I've driven every inch of it myself. It's a wonderful place. And unfortunately for the owners, they got caught up in a bad economic climate. In regards to the environment in New Hampshire, we continue to do outreach all along the rights of ways with the folks that would have bought the line, looking out where the hotspots are, starting to resolve those, so we have ongoing conversations with Butters. We continue to have conversations with key political leaders, policymakers in New Hampshire. And the general feedback is pretty much the same. You've got to demonstrate that there is benefit for New Hampshire, what's the economic benefit. You have to demonstrate that the line in and itself won't cause any environmental damage. We think we will have a strong case that says there is a massive amount of economic benefit for the state over $1 billion -- are over a $1 billion over a 40-year life. And the life of that -- of those lines and the assets on the other end of them are really 80- to 100-year assets. So this is huge benefits that would flow to the states over many years. It'll improve reliability at a lower cost, at a lower carbon. It will create jobs. So our view is this is -- siting of a transmission line is always a complicated process. Just as they were here in Connecticut when we sited then some of the most densely-compact areas in the U.S., that was done successfully. It took us sometime to get there. But by working in the communities and the key stakeholders, we got to a win-win situation and we'll do that here as well.

Next question is from Andrew Weisel from Macquarie.

If I could follow-up about the comments you just gave about in the TDI line. What you said makes a lot of sense, that's good color. The one thing I wanted to maybe drill little deeper on is the fact that their line going to be fully buried, whereas you said that, that will make your line economically unfeasible. I understand that there's room for more than 1 project, and it's not a direct competition. But do you think that the regulators in the New Hampshire state evaluation committee and the DOE might take another look at whether they want an unburied line, if there is a proposal for one that would be fully underground?

Andrew, this is Lee. I think this is just part of our signing application. We have to demonstrate. We have a proposed -- right away, a proposed technical design, we have to demonstrate to the Siting Council why that is the appropriate one. And an alternative, obviously, would be undergrounding, and we have obviously, committed to do a level of undergrounding, approximately 8 miles of undergrounding through sensitive areas. The remainder which the right of way, obviously, is on an existing right of way with some privately purchased land in the very northern part. So we are going to have to demonstrate that as a matter of fact. Now, a couple of things and with these big underground -- announced undergone projects, first of all, there is -- the cost is higher, significantly higher when you underground, underwater and overhead. There is a lot of risk. Again, these are merchant projects, so they have to find someone that is willing to accept the risk of building these projects, because again, H2 is not paying for this and will not pay for a similar financial model that we have. So they'll have to find someone to take the risk. And any time you underground, you underwater, the risk goes up fairly dramatically. The costs are hard to predict and they're always higher than what anybody projects. So I would just give you that as color around that particular project or any major underground project. We've built underground projects here in Connecticut and they always go up. It's the nature of that technology.

Okay. Next on the Central Connecticut Reliability, I believe you said you're sticking with your expectations of decisions from the ISO in the middle of next year and in service in 2017. That seems like a pretty quick turnaround, considering we don't know where these lines are going to be built. That means you would need the permitting and planning as well as construction in a 3-year period. Is that realistic?

Yes. It actually is because in our previous design, which was this kind of big 345 kV point A to point B design, that's off the shelf. Now we're not going to do that because we found other solutions that would negate that. So these are really, for the most part, solutions that are in existing substation, so they're substation upgrades. They're existing lines that are upgraded. In other words, larger conductor, larger poles to go with them, capacitor banks and so forth. So they can be done as part of a whole host of smaller projects that don't need a significant level of siting. Many of them are done inside of the fence, so we're actually very confident that we can get all of those projects. And I say all because there will be multiple small projects that make up that $300 million number that we are very confident we can get done by the end of 2017.

Okay, you sound very comfortable with that. Just 2 quick ones now to wrap-up. First on O&M, because I believe you're sticking with the 3% O&M cuts through 2015. Given what you've seen so far, is there a potential for upside to that number?

No. Andrew, this is Jim. We're comfortable with the guidance that we've given the Street that -- for the 3 years, '13, '14, '15. We think that we can mitigate the pressures of inflation and wage increases and still have an absolute 3% decline each year. And some of the initiatives that we talked about in terms of IT savings, facility savings, will certainly help us get there.

Great, then lastly just bookkeeping. The reserve charge you took for the transmission ROE, is that included in the $0.69 adjusted number that you put out?

Yes, it is.

Next question's from Kit Konolige from BGC.

Forgive me if you addressed this before, but can you give us some details on sales in the quarter and the year-to-date by customer class?

Sure. Sales for the quarter were actually down 1.6%. But in my earlier comments, I indicated that because of the July heat wave, a significant portion of our revenues is driven by demand charges, and that heat wave drove our demand revenues up quite a bit. So even though the sales units are down for the quarter, revenues were actually up compared to last year. And by sector for the quarter, residential sales are down 1.8%, but that puts us on a year-to-date basis, with sales growth of 2%. So we've had a pretty robust year from an electric sales perspective. Commercial sales are down 1.4% for the quarter. And industrial sales are down 2.2%. When you look at them, the weighted average result is a 1.6% decline for the quarter.

And Jim, what are you looking at going forward for sales growth?

The guidance that we've given historically is 0.5% to 1%. And if you look at where we are year-to-date, we're at 0.6% growth.

So your outlook for sales appears to be quite similar to what you've encountered, say, in recent years, which would be a significant departure from what some other companies are seeing.

Yes, I think our actual results this year probably benchmark pretty favorably compared to other utilities, which is, I think, an indication of the quality of the service territory. I mentioned some of the statistics in my comments in terms of our employment numbers, our housing start numbers, et cetera. So our numbers are holding up pretty well, and that's actually in spite of a very significant spend on an annual basis in the areas of energy efficiency.

Right. How much would you estimate energy efficiency is impacting sales?

Kit, I don't have that number readily available. It's actually -- you'd have to qualify it. Is it this year's spending that you're talking about or is it sort of the last 5 years in energy efficiency? So we do spend approximately $400 million on energy efficiency spending. I think Massachusetts was voted as the #1 state in terms of its commitment to energy efficiency by an industry association. So a lot of spending there. We actually do get recovery of the lost space revenues in some of our jurisdictions. And so even though the sales numbers look low, when you factor in lost space revenues, the revenue impacts look more favorable.

It doesn't appear we have any more questions. So just want to thank you, all, for joining us. If you have any questions later today or next week, please call John or me, and we look forward to seeing many of you at the EI conference.

Thank you, ladies and gentlemen. This concludes today's call. Thank you for participating. You may all disconnect at this time.