Welcome to the Northeast Utilities earnings call. My name is Vivian, and I will be your 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. Mr. Kotkin, you may begin.

Thank you, Vivian. 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, our Executive Vice President and Chief Financial Officer; and Lee Olivier, our Executive Vice President and Chief Operating Officer. Also joining us today are Jim Muntz, President of our Transmission business; Phil Lembo, our Treasurer; Jay Buth, our Controller; and John Moreira, our Director of Corporate Financial Forecasting and Investor Relations. Before I turn over the call to Jim, 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 risks 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. 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, 2013, and on form 10-Q for the 3 months ended March 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. Now I will turn over the call to Jim.

Thanks, Jeff, and thank you to everyone for joining us this morning. Today, I will cover second quarter and midyear financial results, including the impact of the 2 orders issued by the Federal Energy Regulatory Commission on June 19. I'll also cover sales trends, the state of our regional economy and a number of state regulatory and legislative developments that we've seen since our last earnings call. Before I discuss those topics, though, I would like to comment on the first half of 2014. We've had strong financial and operating performance to date. Revenues, particularly natural gas, are ahead of budget, and operating costs are being well managed. And I'll remind you that we have projected a 4% reduction in operations and maintenance costs this year. As Lee will discuss, electric service reliability is running well ahead of last year, and remember 2013 was NU's best performance ever in terms of reliability. On the state regulatory side, we received a favorable decision on the CL&P storm docket, have cleared some important hurdles in completing our news transmission projects and made a solid start to the Connecticut Light & Power distribution rate case. We are well positioned for a strong second half of 2014 and believe we will earn between $2.60 and $2.70 per share for the full year, including the $0.10 charge related to the FERC ROE orders but excluding post-merger integration costs. I'll now turn to those FERC orders, which were issued in June 19. One of those orders tentatively determined that the base ROE earned by New England transmission owners should be lowered from 11.14% to 10.57%. The second order set for a settlement process, a second ROE complaint that was filed with FERC in late December 2012. We are pleased that in the decision, FERC agreed that…

Thank you, Jim. I will provide you with an update on our major capital projects and our natural gas expansion initiatives, and then turn the call back to Jeff for Q&As. You will recall that during our Analyst Day 6 months ago, I noted that we had a base capital forecast for our transmission and natural gas delivery business that could grow meaningfully as we identified additional [indiscernible] to include in our forecasts. Now, 6 months later, I'm going to update you on some of those projects. And I should add that we are not done yet as New England's energy delivery infrastructure continues to change rapidly as the region decarbonizes its fuel mix and depends more on natural gas and renewables to power the economy. I will start our detailed update on transmission and our NU's family of projects. We commenced construction of our $218 million section of the Interstate Reliability Project in March. And as of June 30, the project was approximately 40% complete. We are building the approximately 40-mile Connecticut section of the project, and the National Grid is building Rhode Island and Massachusetts sections. National Grid received its final permit in May, and we expect all sections of the project will be completed by the end of 2014. Turning now to the Greater Hartford Central Connecticut Reliability Project. In mid-July, ISO New England Planning and Advisory Committee met to discuss the series of solutions necessary to remedy overload and low-voltage conditions that exist today or will emerge in the near future across Central and Western Connecticut. You may recall that initially, we had expected that a single new prequalified kV transmission line from Hartford -- from the Hartford area to Waterbury area would resolve transmission issues in the region. Over time, that has evolved into a…

Thank you very much, Lee. And I'm going to turn it back to Vivian just to remind you how to pose a question.

[Operator Instructions]

First question this morning is from Julien Dumoulin-Smith.

So first, if you can expand a little bit. You talked about potential opportunities on the gas side. Obviously, NESCOE's got its own process going on here. Can you elaborate a little bit as to where you see these -- where you see that going? Could this ultimately result in ownership in midstream as well?

Yes, this is Jim, Julian. Yes, it could. As you may be aware, that -- NU, UIL and National Grid filed a proposal to NESCOE indicating that to the extent that the generators won't step up and commit to pipeline capacity for their electric generating units and the pipeline companies themselves tend not to be their business model to build on spec, we think that the utilities could play an ownership role, partnering in a project that would solve the issue. And costs could be paid for by the customers that benefit from it, which would be the electric customers throughout the region. So that will involve ownership potentially.

Got you. How big of an ownership do you think? I mean, could you kind of elaborate in terms of your thought process and timeline on getting that -- a decent proposal here?

I really can't comment at this time. Obviously, pipelines are capital intensive to build and would depend upon the route and the design. But we would expect to see a significant investment if we were to go forward with the project along those lines.

Excellent. And then at the time of the Analyst Day, you talked about potentially accelerating certain capital investments depending on what happened with NPT and other factors. Can you elaborate a little bit on the potential for the acceleration? I suppose some of that was tied to the Boston-related investments.

Yes, this is Lee Olivier, Julien. And if you think about it, we've added another $50 million to the Greater Hartford Central Connecticut Project over the period of 2015 to 2017. And we added $100 million, most of it in the Greater Boston area, and some of it is with the Greater Boston project. We also have the new substation we're building in Somerville, Massachusetts, new physical security that is required through the NERC and FERC requirements. And other upgrades in substations and replacement of aging infrastructure. So that adds $100 million. So this is $150 million. And we talked about the gas business. We had numbers in there from '15 through '17 of $250 million, and there's potentially up to approximately $150 million, $160 million more investment during that period as well. So net, over $300 million.

Excellent. And just a last question, kind of bigger picture here. I mean, what's your reaction ultimately to the latest quarter -- the last FERC order on transmission? I mean, does this change tactically your view in terms of investment in one bucket versus another? Or in terms of coming back to FERC, I mean, how are you thinking about positioning the subject going forward?

Well, the 10.57% ROE was actually in line with, I think, The Street's expectations. And if you look at what we reserved for that first complaint in the third quarter of last year, it was right in line with the outcome. So that was not a surprise. What was a surprise was what we see as a change in precedent if FERC is going to allow a second complaint to be heard and, more importantly, the impact that we interpret the order to be on incentives. There was no record on incentives established in the case, yet the consequences of the new mechanism that FERC is proposing is to dampen incentives. We entered into projects for complex, innovative technology. We're incented to do so. And the consequences of this order is to actually cut into those incentives that were awarded. So we have some real issues with the way that the 2 orders came out. However, we still see the transmission business as attractive business to be in. I don't think the 10.57% is particularly punitive. So it's clearly a big part of our business strategy going forward, but we would like to see resolution of these concerns that we have.

Thank you, Julien. Our next questions comes from Dan Eggers from Crédit Suisse. Daniel L. Eggers - Crédit Suisse AG, Research Division: Can I -- just on the gas volume and kind of the strength this year relative to the customer additions, if you were to break down that 4% of load growth, how much of that is being driven by the conversion part of the business and how much is being driven by just greater usage?

I think a big part -- actually, there's probably -- obviously, the economy is improving, particularly in, obviously, the Greater Boston Area and in Stamford now where there's about $4 billion of construction going on there. So between the new customers and the series of high-rise, mid-space buildings that were coming up that need gas and the customers that we have connected over the course of the last 4 to 5 years, I think the majority was driven by either customers that have come online over the past few years and new customers that are coming online right now.

Dan, maybe another observation is we're adding about 10,000 customers a year to a 500,000 customer base. So just the customer kind of alone is a 2% increase. So not every customer, obviously, takes the same sort of load, but I think it's a combination of both increased usage per customer as well as increased volume of customers that we're adding. Daniel L. Eggers - Crédit Suisse AG, Research Division: Okay. And then I guess on the NESCOE pipe, I guess your RFP is supposed to be kind of addressed by year end. Is that still a realistic timeline from your perspective? And what will we expect to hear in the investment community once your RFP is completed?

Yes, the -- again, it's Lee Olivier, the NESCOE will provide a schedule next month. So September, essentially, they will provide a schedule that will take us all the ways through to the selection of the successful bids and the awarding of the bids, the filing of the FERC applications, both in gas and electric. So we will expect to get a schedule on that in the September timeframe. Daniel L. Eggers - Crédit Suisse AG, Research Division: Okay. And I guess so I understand this, how are you guys going to structure this from a rate perspective? Have you figured out how to see it put into rates for the utilities to cover their cost? And are you going to run into any issues with FERC as far as rate design given the fact that you're probably going to pass through a gas cost through an electric bill?

Yes. Well, the ISO New England will file the tariff, and the EDC customers will collect the tariff. And obviously, they'll go through a state process as well. But it will be -- ISO New England will file for a tariff. And I think the electric transmission aspect of that would be very straightforward. There's precedent to do that. Probably not a lot of precedent on the gas side. That could be a little more difficult. However, there is a strong consensus with all of the leaders in New England, the governors, the -- most of the congressional delegation who understand the need and understand the risk that the region is facing. So with strong congressional delegation support for this with FERC, we believe this will be successful. Daniel L. Eggers - Crédit Suisse AG, Research Division: And I appreciate the NESCOE opportunity. When you guys spend more time kind of reflecting and strategizing for this coming winter from a reliability perspective and given the gains in gas customer usage, have you guys come up with any other solutions to help further enhance reliability this winter? And if demand response rules change on this FERC decision, is that going to incrementally complicate electric deliveries?

I think on the gas side, clearly we have all the gas lined up for our customers on the gas side. So for all the LDC customers, they will have firm gas supply and that will not be an issue. FERC will -- not FERC, but ISO New England is in the process of doing another kind of fuel supply plan this year. Last year, they did -- they purchased X amount of oil for the generators, kind of gas-fired generators, that could burn oil as a backup. We were one of those participants with our New England plan. ISO has a similar scheme that's slightly different but is similar to last year. So we believe that there'll be sufficient oil. We've also included LNG in the mix for generators, so LNG that could be purchased and gasified for generators. So right now, that is the plan. I wouldn't speculate on what would happen around the DSN decision right now, but we're going to end up going through the winter with about 1,400 megawatts or less non-gas-fired power plants, both nuclear and coal. There are the plants that ran continuously over the winter, so -- last winter. So it's going to be very, very challenging to get through this winter. So you're looking at a situation where you'd have the loss of one large unit, one 1,200-megawatt nuclear unit, where there could be serious threats and challenge to the reliability of the region. So it's an impetus to get moving on the NESCOE initiative for both electric transmission and gas-fired plants.

Thanks, Dan. Our next question is from Travis Miller from MorningStar.

On the transmission charges, if I understand, it sounds like you guys have taken the charges for everything retroactive or backward looking. At what point do you leave in that $0.05 ongoing earnings or any additional charges as we move forward? Just give me a sense for that forward look.

Yes, well, the consequences of the new mechanism at FERC and the new base ROE would be that we would lose, on average, $0.05 to $0.06 a year that would come in ratably throughout the year. We'd be basically be earning less every quarter.

All right. Does that start? I guess what's the effective date, more or less, of that?

The effective date would be the -- when this order that was issued is final, and that's expected to be in the fall.

This fall?

Yes.

Thanks, Travis. Our next question is from Paul Patterson from Glenrock.

Just to sort of follow up on the Needham [ph] clarification rehearing case. Are you guys implementing rates based on the -- on simply the base ROE? Or are you also taking into account what the upper end of the range would cut off the incremental ROE, if you follow me?

We -- the reserve that we've established reflects the lower base and it also reflects the upper end of the range as it impacts the incentives that were earned through the 2 complaint periods. So we basically booked it all.

Okay. So -- and just incrementally speaking, if you were to get the rehearing on the incremental part go your way, what might that mean financially?

The -- well, $0.05 of the $0.10 writeoff that we just took would be unwound. And I would say of the $0.05 to $0.06 going forward, about 1/3 of it relates to the impaired incentive impacts that we're talking about.

Okay. And then just for the quarter, I'm sorry if I missed this, what was the weather-adjusted sales growth number for the quarter system-wise on electric?

Electric, the second quarter sales were down 2.9%. But weather-adjusted, it would have been down 1.7%.

Okay. And then just finally, on the NESCOE stuff, with each -- with the legislation that was in Massachusetts with respect to hydro and stuff, it -- I don't know what happened to it, but it looked like it was running into some difficulty in committee. I think it might have not passed. I'm just wondering, with these opportunities, which I understand the logic and everything for them, and the support that the leadership has, do you think there's any legislation that would have to be implemented at the state level to have either gas or electric projects associated with these infrastructure needs to take place? Or is there anything -- I mean, I guess what I'm just sort of wondering is, I mean, leadership might think something conceptually, but when you actually sort of have to get something done, sometimes it doesn't always work out exactly. I'm just sort of wondering sort of strategically how you look at that and how you've sort of addressed that since you guys would ultimately argue with it.

Yes, Paul, this is Lee Olivier. The bill did die yesterday in the Massachusetts legislature. And it's -- and the legislative season is over, so there'll be nothing this year. And that bill was essentially all Orion [ph] giving the state authorization to go out and purchase energy. So they would allow them to go out and purchase large-scale energy from hydro and wind and so forth. The bill is not needed as part of the NESCOE process, so this is a Massachusetts-only initiative. And a big part of that was all around meeting their carbon reduction goals. So they've got a goal of reducing carbon essentially the equivalent of 9 terawatt-hours by 2020. So this would allow them to go out and purchase nonprofitable carbon fuel sources and meet that, meet that goal. So from the standpoint of NESCOE, with -- NESCOE is about -- is building infrastructure. Once the infrastructure is built, whether it's electric transmission or gas and places for sub-transmission, the EDCs, with the approval of the state regulators, will have that opportunity to go out and do purchases of energy over either long term, short term, that would obviously have to go through the Public Utility Commission approval process. But that ability is still there. It would just roll up through the EDC, which would go for approval with the PU. So we don't see any other legislation that is needed for a NESCOE initiative to go forward as is.

Our next question is from Greg Gordon from ISI.

When you look at the earnings growth aspiration, what is the baseline expectation for electricity kilowatt per sales, weather normal? And can you talk about that in terms of, like, customer growth versus sales growth? You talked about how the economy in the region definitely looks like it's taking off. I come to Boston all the time. I see all the new customers you guys are getting. How do you think about customer growth relative to sales growth? And size the expectation for kilowatt-hour sales growth going forward.

Well I think the guidance that we've given The Street, the long-term guidance, is 0% to 0.5%. So we're not anticipating modest -- significant rather, sales growth in total. You are right that we're seeing customers get out and there's a lot of construction activity going on. Obviously, what we have in addition to that is we spend about $0.5 billion a year on energy efficiency and it has an impact. So the usage per customer is obviously going down and offsetting the fact that our customer numbers are growing. Now the good news is on the energy efficiency front, we have a pretty compensatory ratemaking mechanism that allows us either a decoupling recovery or lost base revenues recovery and will also provide an incentive if we do a good job in terms of executing the programs, and we get cost recovery currently. So we can have revenue growth in spite of the fact that the kilowatt-hour sales are somewhat flat.

Thanks, Greg. Next question is from Andrew Weisel from Macquarie.

First question. Maybe I misheard here, but the Greater Hartford central project, you upped the CapEx. Did the ISO identify their preferred solutions? Or is this more making progress without a final answer?

Yes, Andrew, this is Lee Olivier. No, ISO has identified the preferred solution. So we and ISO agreed on what the preferred solutions are, and we have priced those out. And essentially, it's another $50 million on to the initial estimate of $300 million.

Okay. Next, the Connecticut rate case. I believe you said hearings are in August. How soon could a potential settlement be reached? Would it be after the hearings?

The -- we're -- I think we have a long history of rate settlements, and we've had rate settlements that went up to the 11th hour right before an order was issued. But hearings have been completed, briefs have been filed. And we've also had instances where settlements were reached before the case was even filed. So it's a pretty broad range. It will depend on the perspective and the willingness on both parties. We're obviously in the due diligence phase right now, answering a lot of data requests that are, I would think, appropriate for the consumer advocates to get comfortable that the numbers are all supportable. So we would hope to reach settlement in this case. But when that happens, it's hard to predict.

Would you be willing to give like a 1 to 10 scale probability of a settlement?

I can't do that because it takes 2, obviously, to agree. But we do have a pretty good track record, including some settlements in Connecticut over the last couple of years. And some of them have been low profile, but I think the fundamentals of the case, again it's totally driven by the investment that we've made in Connecticut. We've done a great job managing costs. The rate request would have been much higher had we not done that. So -- and I think the basis suggests that we should get a good outcome here. But obviously, in settlement space, the other parties need to agree that. I'm not going to probability-weight it.

Okay, fair enough. Then one last one on the NESCOE RFPs. If we take Northern Pass out of the equation because that kind of has its own trajectory, would you be interested in proposing another Northern Pass-like project? I think you mentioned some other opportunities. Roughly speaking, are those very large scale? Or will they be more smaller projects?

Yes, Andrew, this is Lee Olivier. We're looking at a number of projects. Some of them are smaller, could be anywhere from several hundred megawatts to 1,000 megawatts. So there's a good number of projects that we have reviewed, and we're in the process of narrowing those down to approximately half a dozen projects that we think could add significant value to the region that we'd connect transmission into where there are renewable resources, whether they're wind or hydro. So when the RFP process comes to fruition, we will be ready with several options beyond Northern Pass in which we can offer into that process.

Thank you, Andrew. Next question is from Nick Ulas [ph] from Gabelli.

I guess just on the transmission side, could you talk a little bit more about how the Order 1000 process will work in New England? And then I guess you mentioned some partners. And your thoughts on pursuing transmission projects outside of the region and what types of opportunities you see there?

Yes, in terms of the FERC Order 1000. FERC has not actually issued the order and how that will work. And so we don't have an outcome here from ISO New England. So ISO New England and FERC did concur on what those rules will be. We've looked at with -- a potential FERC order as we kind of think what the impacts are on current stream of investments, and we think the effects would be minimal at best. So from that standpoint, we need to wait for FERC to issue the order and for ISO to concur with it and put together the actual policies and procedures to go with it. So I would say that's probably going to be something that's going to happen probably by the end of the year, I guess probably fourth quarter. And so your -- yes. And NESCOE is really not using kind of the Order 1000 process. So it's their own process which they can use in concert with ISO New England filing the FERC tariff. And that's -- the ISO New England rules have always had a provision in there that the region could, for the public good, go out and do separate RFPs. I'm sorry, your last part of your question, Nick, is?

I guess it's -- you talked about, I mean, some interested partners coming to you on the transmission projects maybe outside of the region, what do you see there.

Yes, we've actually had a number of potential partners calling. We've actually looked at a lot of projects, quite frankly, around the country. Some in the West Coast, others nearby. We're in discussions with some folks. It's one of these things that you may look at 20 different projects and there may only be 1 or 2 that you really think fit the profile which you would want to invest in, which is there has to be a clear need for the project, it has to have FERC treatment in terms of being able to ensure that you can fully recover your cost, very similar provisions that we have here in New England. We would love to have a partner that we feel very comfortable with, that is trustworthy. So we've looked at quite a few. Some we have chosen not to pursue, and others we're in the process of looking at now, which is the reason why we hired Dr. Shea to be our VP of Transmission Development. She's got the skill set, the business skill set that we obviously needed for that, along with Jim Muntz who is our President of our transmission business. So as we look at those and we find some that we think are really viable, we will share those with you all.

Thanks, Nick [ph]. Next question is from Michael Lapides from Goldman.

Lee, I apologize. I had a hard time hearing you a little bit. Can you summarize on the transmission side? How in total is your CapEx forecast different than what you disclosed in Analyst Day?

Okay, so big picture, Michael, it's $150 million higher. So $50 million more for the Greater Hartford Central Connecticut Project in years '15 through '17. And then we have about $100 million of other transmission. And again, that's everything from new the substation we're building in Somerville, Massachusetts; to our Greater Boston project, which is a $550 million project, going up by another $20 million; new physical security requirements that are mandated by NERC for -- so another $15 million; and a whole bunch of other smaller projects that are in the $6 million to $7 million range. So that adds up to be $100 million. So there's $150 million of more transmission that we've -- than we talked to you about in the February timeframe.

And just to clarify, Michael, the $50 million in the Greater Hartford project is within the forecast horizon, but the additional $100 million that Lee referenced is in 2018. I think Lee had provided an estimate of what we anticipated out in '18 and right now have identified a $100 million more spend.

Right.

Yes, okay. So a little bit more back-end loaded on that $100 million?

Right.

Right.

Okay, fine. Any changes to your Northern Pass capital spend forecast, timeline especially?

No, not at this time. We're -- there's no real changes at this time. I mean, most of the investment right now has been the DOE IS [ph] process and supporting that and doing early engineering and other environmental work around the sites. So really no CapEx forecast changes at this time.

And finally, on Northern Pass, what happens now on the PPA process given the Massachusetts legislation has kind of fallen by the wayside?

Yes. So on the PPA, there -- when the project is built, HQ will have the sole rights to the line and anyone can do essentially a bilateral deal that chooses to with HQ. They can negotiate a power purchase agreement with HQ over some duration. So that opportunity is still there, and that, in all likelihood, would run through the EDCs with the -- obviously, with the EDCs approving a PPA, that very well still could be done.

Thanks, Michael. Next question is from Rajeev Lalwani from Morgan Stanley.

Two questions. So first, can you provide us the pluses and minuses from your old and new guidance for 2014? I'm just curious what the offsets are for the transmission. And my apologies if you've provided that earlier. And then the second question is around reformation and I guess particularly on the telecom side. Any updated thinking there as far as interest in pursuing that?

Sure. On the pluses and minuses, fundamentally we're absorbing a $0.10 hit that we got in the second quarter here on the FERC order. And in spite of that, the guidance has remained fairly robust. The previous guidance was $2.60 to $2.75. The new guidance is $2.60 to $2.70. So, obviously, it reflects what we've achieved year-to-date in the first 2 quarters, but, more importantly, what our expectations are as we update what we think the potential is for the last 2 quarters. On the REIT side, I know there's a lot of financial reengineering activity in the industry, whether it's MLPs or YieldCos or REITs. Some have tax advantages. Others don't. It's not clear to us. Given the nature of our business, we're a pure regulated transmission and distribution business, I think it's difficult to imagine how we could carve out our assets for such a structure and that the regulators would be willing to accommodate that. Nevertheless, we are following the activities we're interested in and understanding the opportunities that could be there in the future for future projects, and we'll continue to monitor that.

All right. Thanks, Rajeev. That's the last question, so we want to thank you all for joining us today and have a great weekend. And call John or me if you have any more questions today. Take care.

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