Jeffrey R. Kotkin - Executive Officer James J. Judge - Chief Financial Officer and Senior Vice President Leon J. Olivier - Chief Operating Officer and Executive Vice President James J. Judge - Chief Financial Officer and Executive Vice President

Kevin Cole - Crédit Suisse AG, Research Division Travis Miller - Morningstar Inc., Research Division Neil Mehta - Goldman Sachs Group Inc., Research Division Andrew M. Weisel - Macquarie Research Kit Konolige - BGC Partners, Inc., Research Division

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. Jeffrey R. Kotkin: 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. James J. Judge: 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 ROE by 54 basis points for the 15-month period from October 1, 2011 to year end 2012. Because of this charge, transmission earnings were down $12.5 million or $0.04 per share in the third quarter of 2013 compared to the same quarter a year ago. Turning to sales, while Decembers of 2012 and '13 were both hotter-than-average, 2013 was somewhat milder than 2012. July was the hottest month ever in Connecticut, but cooling degree days for both August and September fell short of last year's levels, leading to an average cooling degree day decline for the quarter in our 3-stage service area of about 7% compared to last year. From a revenue standpoint though, the loss in kilowatt hour sales was more than offset by higher demand charges caused by an early July heat wave and a modest distribution rate increase at PSNH. As a result, higher electric distribution revenue added about $0.01 per share to earnings even though kilowatt hour sales were down 1.6% for the third quarter of 2012. I mentioned during our second quarter earnings call that some of our maintenance work has been slowed -- had been slowed early in the year by weather, particularly by the snowfall in the first quarter. As expected, we caught up on much of that work in the third quarter, particularly tree trimming in our non-tracked O&M roles. The higher non-tracked third quarter O&M reduced earnings by $0.02 per share in the third quarter of 2013, compared to the same period last year. Offsetting the higher O&M in the quarter, was impacted the lower effective tax rate. That showed up primarily at NU parent where it resulted in a $0.03 favorable impact compared with the third quarter of 2012. All other items, including lower interest expense, provided us with another $0.01 per share of benefits. Given where we are from an earnings perspective on the year-to-date basis, we remain very comfortable with our 2013 earnings guidance of $2.45 to $2.60 per share, and continue to believe that our longer-term earnings per share growth rate remains at 6% to 9% off a base of $2.28 per share of recurring earnings that we reported in 2012. Now to update you on various developments this quarter. In September, we extended our existing $1.9 billion backup credit facilities an additional year through September 2018. On our merger integration initiatives, we recently completed an assessment of the legacy NU and legacy NSTAR IT departments, and it showed that each company maintained very different technology approaches and platforms. To provide high quality service to customers at an efficient cost, our new IT organizational model is preferred. This model will include a uniform approach using a combination of internal and external resources to support continuing development of technology solutions. Moving forward, our in-house IT team will focus on strategic change-the-business work, while day-to-day run-the-business activities will be moved to service providers who specialize in this work. This will allow us to leverage a larger pool of experts who can implement new technologies, expedite integration and eliminate duplicative processes, all targeted at improving business processes and enhancing customer service. As NU shifts to this new model, a number of internal IT employees will decline over time to about 50% of the current level. Severance costs associated with that change drove the integration charge for this quarter. Another integration assessment that we recently completed involves our facilities. The review showed our facility configuration could be optimized, further improving our ability to more efficiently plan work and deploy resources across the broad geographic region. To improve operational efficiency and provide more effective service across our region, we will begin reconfiguring certain facilities as well as consolidating a number of locations. This will enable us to respond more effectively to customer needs and also reduce costs associated with underutilized locations. So progress continues to be made on the integration front, which will help support the 3% per year cost-reduction targets through 2015 that we have discussed with you previously. The changes in both IT and facilities continue to focus on 2 of our most important goals that will benefit customers over the long term, reduced costs and improve our service. Now to comment that economic conditions in our region. We continue to see signs of improvement, particularly in the labor and housing markets. Regarding the labor market, total employment in each state we serve has increased by about 1% as compared to 2012. In our region, we are seeing continued improvement in construction-related labor activity, which increased this year in all 3 states, ranging from 2.9% in Massachusetts to 4.5% in New Hampshire to 8.6% in Connecticut, each of which is significantly better than the national rate of 1.5%, as of August. This is encouraging news for our service area because it represents new customers and additional sales in the future. Another indicator of future sales can be seen in statistics tied to the housing market. More specifically, in the area of new housing permits for single and multifamily homes. We are seeing solid gains in the number of housing permits issued this year compared to the same period last year in each of the 3 states that we serve. In fact, the 36% increase in housing permits in Massachusetts exceeded the national average of 23% and represents another source of new customers. Also, sales of existing single-family homes in Massachusetts were up 16% from September of last year, the highest level since the peak in 2005. On a regulatory front, as I noted last quarter, the New Hampshire PUC staff issued a report recommending that the commission open up a proceeding to examine several possible solutions to PSNH's default service rates and explore various alternatives for its generation assets. On September 18, the commission issued a request for proposals to engage an expert to determine the value of the generation assets. It is expected that the consultant will be announced later this month and a valuation report is expected to be issued within 6 months of the consultant's date of hire. We continue to believe that all generation investments are prudently incurred and should be fully recovered. Now I'd like to provide an update on the base ROE proceeding I mentioned earlier. On August 6, the administrative law judge assigned to the ROE proceeding issued a recommendation that the current base ROE is not just and reasonable under current FERC methodology. However, the judge determined that separate base ROE rates should be set for the refund period and the prospective period and recommended a base ROE of 10.6% for the historical period and 9.7% on a prospective basis. The charge that we took in the quarter was related to a potential refund for the historical period. Based on past precedent, we expect the prospective base ROE will be adjusted to reflect the movement in 10-year Treasury bond yields from the 6 months used for the trial last spring, as compared against the 6 months before the date of a final decision from FERC, which is not expected until mid- to late-2014. The last regulatory item that I'll cover is the status of our storm cost proceedings. Primarily as a result of the 4 major storms that New England experienced between August 2011 and February 2013, we have about $650 million of deferred storm cost that we need to recover from our customers. In Connecticut, we filed for recovery of $454 million of storm cost in March of this year and hearings were completed in early September. You may recall that last year, Connecticut Light & Power agreed to forgo recovery of $40 million in storm costs as part of our merger settlement agreement. Thus far, the proceedings have progressed well and we remain confident that we recover the remaining $414 million of these costs over a 6-year period, beginning December 1, 2014. Briefs of this matter are due today with reply briefs due next Friday. In Massachusetts, NSTAR filed -- NSTAR Electric filed earlier this year to recover approximately $35 million of storm cost from 2011, and we expect a decision next month. As per our merger settlement agreement, the recovery of the 2011 storm costs will commence over a 5-year period beginning January 1, 2014. NSTAR Electric has not yet filed for recovery of 2012 or 2013 storm costs, totaling $91 million. Public Service Company of New Hampshire on the other hand is already recovering its major storm costs and will complete that recovery in mid-2015, assuming no new major storms occur. Western Mass Electric is currently reviewing its 2011 and 2012 storm costs with regulators. Regarding Connecticut's comprehensive energy strategy, we filed our gas expansion plan with the state's regulators back in June, and the Department of Energy and Environmental Protection deemed the plan to be generally in compliance with the legislation. The public utility regulatory authority conducted hearings on our plan. And a final decision on the plan from the agency is expected later this month. A draft decision is currently scheduled for next week, Lee will update you on some of the recent gas conversion activity in a moment. Before concluding my formal remarks, I should note that our management team plans to attend the upcoming EEI Financial Conference in Orlando from November 10 through the 13 and we look forward to seeing many of you there. Unlike some past years, we will not be hosting a formal breakfast at EEI. Instead, we are currently planning on hosting an Analyst Day luncheon in Boston during the first week of February. At that time, we plan to provide 2014 earnings guidance and details on future capital spending plans and key initiatives, as well as our outlook over the longer term. Specific details will be provided to you as we get closer to the event. Now, I'll turn the call over to Lee. Leon J. Olivier: 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 their public scoping meeting process. The comment [ph] period remains open until November 5. Concurrently, the project has held 16 open houses in towns along the route. These open houses were designed to allow us to interact with a wide range of stakeholders along the route. We believe they have achieved their goal of fostering communication and increased understanding of the project. We expect a draft environmental impact statement from DOE next summer which would trigger both a comment [ph] period on the draft EIS and our filing with the New Hampshire site evaluation committee. We continue to target a summer 2015 to construction, resulting in a mid-2017 completion. You may have seen our news release announcing creation of a $7.5 million jobs development program we will sponsor in northern New Hampshire if the line is constructed. This would be one of the many benefits of Northern Pass for the state, which would also include the state's share of the region's estimated $200 million to $300 million reduction in wholesale energy costs, the creation of 1,200 jobs during construction and almost $30 million a year in additional property taxes paid to communities along the route. Additionally, New Hampshire would benefit from the annual reduction of up to 5 million tons of CO2 emissions in the region, as the Clean Renewable Energy from Hydro-Québec displaces fossil-based generation that would otherwise be running. As we have said previously, our transmission program involves much more than Northern Pass and NEEWS. We have essentially completed our new 345 kV link to Cape Cod, with a small amount of remaining work to be completed this fall and next spring. This portion represents the lion's share of the $150 million we were spending to strengthen the lower Cape transmission system. In mid-August, the LMP commenced work on a $70 million project in the Waterbury area to improve reliability by replacing 21 miles of older steel lattice towers with new monopoles. That work should be completed in 2014. In September, the Connecticut Siting Council approved a $47 million project to install new 115 kV underground cables in and around downtown Stamford to help support the billions of dollars of new development that is taking place in the city. All of the projects that I have mentioned are in our $4 billion 2013 through '17 transmission capital expenditure forecast. We expect to spend about $640 million this year on transmission CapEx, in line with our earlier projection. Through September 30, we have spent $426 million in our Transmission business. Since our previous earnings call 3 months ago, we have had a number of developments regarding power supply in New England. We know that by the end of 2014, the Vermont Yankee Nuclear Power Plant will shut down. Also, the new owner of the breaking point station in Southeast Massachusetts announced plans to retire the breaking units in 2017. Separately, we have seen more than 500 megawatts of demand response be withdrawn from the next capacity auction. Altogether, these announcements affect approximately 2,700 megawatts or 10% of the summer peak load in the region. In addition to these shutdowns, we have seen winning bids announced for hundreds of megawatts of new wind facilities in Northern New England. Many of you have already asked us about the implications of these developments on our transmission CapEx plans over the next coming years beyond what is already in our $4 billion 5-year plan. We think that it is likely there will be significant additional transmission investment needed to maintain reliability and improve access to these clean, intermittent power sources, but it is too early to estimate how much that additional investment will be and exactly when it will occur. Turning to our distribution business. I'm pleased to say that for the first time since 2010, we have made it through October unscathed, no late-season tropical storms and no freak October snowstorms. In fact, we've had strong reliability performance across our electric distribution companies this year, and CL&P is on track to have its most reliable year ever. We invested $490 million in our Electric Distribution business through the first 9 months of the year and continue to expect to invest approximately $670 million for the full year. On the natural gas distribution side, we invested approximately $126 million for the first 9 months of the year and expect to invest nearly $180 million for the full year. We continue to see heavy demand for new natural gas services and expect to invest $55 million of the nearly $180 million to help new customers connect to our system. We added 7,805 new heating customers between NSTAR Gas and Yankee Gas through September 30, and are now likely to surpass our initial estimate of 9,100 new heating customers this year. This continues to be driven by the wide differential between the cost of heating oil and the cost of natural gas. With significant supplies of natural gas only 2 states away, we see this situation likely to continue for some time. In June, Governor Malloy signed legislation to encourage the state's businesses and homeowners to convert their furnaces to natural gas. The bill required natural gas utilities to file a plan to implement the legislative objectives in June, which we and United Illuminating did jointly. The pure [ph] is due to issue a draft decision on the plan next week, and a final decision just before Thanksgiving. Yankee's plans calls for the annual investment to connect new customers to rise approximately threefold to $90 million in the late years of the plan, which is a 10-year plan. Under our plan, that investment would be tracked and recovered through rates with a full return. While the growth is not on the scale of our $4 billion transmission investment plan, it would expand Yankee Gas' customer base from approximately 215,000 customers today to nearly 300,000 during the 10-year period. Finally, I would note that in September, Massachusetts regulators approved Western Mass Electric's application to increase its solar investment from 6 to 8 megawatts. Last week, we announced that we would build 4 megawatts in East Springfield, Massachusetts. This will bring the total solar investment in our plan to approximately $35 million, including 4 megawatts we've built earlier in Pittsfield and Springfield. Like the other projects, the East Springfield project is a brownfield location, so it's a win-win for Western Mass Electric, the host community and our customers. The earnings from these projects are modest, but steady, since we will recover a full return on our investment through a tracking mechanism. Now, I would like to turn the call over to Jeff for Q&A. Jeffrey R. Kotkin: Thank you, Lee. And I'm going to turn it back to John just to remind you how to enter questions.

[Operator Instructions] Jeffrey R. Kotkin: 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? Leon J. Olivier: 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? Leon J. Olivier: 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? Leon J. Olivier: 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? Jeffrey R. Kotkin: 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. Jeffrey R. Kotkin: Our next question is from Travis Miller from Morningstar. Travis Miller - Morningstar Inc., Research Division: 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? James J. Judge: 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. Travis Miller - Morningstar Inc., Research Division: 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? James J. Judge: Yes. I mean, clearly they... Travis Miller - Morningstar Inc., Research Division: Go up and then they come down. James J. Judge: 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. Travis Miller - Morningstar Inc., Research Division: 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? James J. Judge: 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. Jeffrey R. Kotkin: Next question's from Neil Mehta from Goldman Sachs. Neil Mehta - Goldman Sachs Group Inc., Research Division: 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? Leon J. Olivier: 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. Neil Mehta - Goldman Sachs Group Inc., Research Division: 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? Leon J. Olivier: 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. Jeffrey R. Kotkin: Next question is from Andrew Weisel from Macquarie. Andrew M. Weisel - Macquarie Research: 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? Leon J. Olivier: 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. Andrew M. Weisel - Macquarie Research: 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? Leon J. Olivier: 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. Andrew M. Weisel - Macquarie Research: 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? James J. Judge: 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. Andrew M. Weisel - Macquarie Research: 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? James J. Judge: Yes, it is. Jeffrey R. Kotkin: Next question's from Kit Konolige from BGC. Kit Konolige - BGC Partners, Inc., Research Division: 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? James J. Judge: 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. Kit Konolige - BGC Partners, Inc., Research Division: And Jim, what are you looking at going forward for sales growth? James J. Judge: 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. Kit Konolige - BGC Partners, Inc., Research Division: 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. James J. Judge: 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. Kit Konolige - BGC Partners, Inc., Research Division: Right. How much would you estimate energy efficiency is impacting sales? James J. Judge: 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. Jeffrey R. Kotkin: 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.