Eversource Energy (ES) Q1 2013 Earnings Report, Transcript and Summary

Welcome to the Northeast Utilities Q1 earnings call. My name is Yvette, and I'll be your operator for today's call. [Operator Instructions] Please note that this conference is being recorded. I will now turn your call over to Jeffrey Kotkin. Mr. Kotkin, you may begin.

Thank you very much. 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 subject to risk and uncertainty, which may cause the actual results to differ materially from forecasts and projections. Some of these factors are set forth in the news release issued yesterday. 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. 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.

Thank you, Jeff and thank you, everyone for joining us this morning. I know that you have a number of calls this week, as companies report their results in advance of the many conferences taking place over the next few weeks. I appreciate that you're spending some time with us this morning. Before I begin, I'd like to thank all of you in the investment community for the many calls and e-mails that we did receive expressing your concern for the safety and well-being of our employees in the wake of the terrible Boston Marathon tragedy on Patriot's Day. It is much appreciated, as all of us in the Boston community attempt to move on from this horrific event, which occurred within the steps of our corporate office in Boston. So thank you, all. My remarks today, I will discuss our first quarter results, recent financing activity, economic conditions in our region and I'll conclude with an update on various regulatory and energy policy issues, including recent storm filings and the FERC ROE proceeding. I'm sure that most of you saw our earnings release issued late yesterday. We earned $228.1 million, $0.72 per share this quarter. While this is ahead of Wall Street's expectation for the quarter, it is very consistent with our $2.40 to $2.60 per share earnings guidance for the year. So we feel comfortable saying that we are on plan. I should remind you that this is the last quarter when we will be comparing pre-merger NU to post-merger NU. So future earnings reports will be more an apples-to-apples basis. Aside from the addition of NSTAR to this year's results, one of the bigger drivers for the quarter was weather. We had record warmth in the first quarter of 2012, pretty typical temperatures in the first quarter of 2013. We had a typical cold New England winter this year. Heating degree days were up nearly 21% in the Hartford area this year, compared to 2012. As a result, we experienced a 3% increase in electric sales for the quarter and a 22% increase in natural gas sales. Legacy NU, higher electric and gas sales added $0.09 per share to earnings per share based on the pre-merger share count. Another significant factor that benefited earnings was the continued investment in our transmission business. Transmission earnings totaled $79.9 million in the first quarter 2013, compared with $46.3 million in the first quarter 2012. The increase was due in part to adding in nearly $18 million of NSTAR transmission earnings to the NU consolidated transmission results in the first quarter this year. Approximately $16.5 million of the increase or about $0.09 per share resulted from transmission earnings growth in the legacy NU system. It reflects continued investment in our transmission infrastructure over the past year and a lower effective tax rate that resulted from the resolution of state tax audits. That resolution added approximately $6 million to our transmission earnings in the first quarter of this year. Overall, on a consolidated basis, the tax resolution added approximately $13.5 million or $0.04 per share to our first quarter 2013 earnings. Much of the increase in transmission infrastructure occurred at Western Mass Electric as we near completion of the Greater Springfield reliability project. We will discuss Greater Springfield and other news projects shortly. Turning to distribution. We realized a decline in operations and maintenance cost, which added $0.08 per share to the quarter's results. A number of factors contributed to this decline. First, during the mild snowless first quarter last year, we were able to accomplish a good deal of maintenance that normally would have been done later in the year. That raised O&M in the first quarter of 2012. Due to the snow and storms of the first quarter of this year, less routine maintenance was undertaken, much more time was spent on storm outage recovery. So much of the reduced O&M is really a timing issue. We do not expect to see such year-over-year reductions in distribution maintenance costs as we move through the year. Second, we are implementing efficiencies across the merged company and we expect the savings to be permanent. Those efficiencies are helping us achieve the 3% per year reduction in core O&M that we first discussed with you last October, and which we expect will continue through 2015. We are on track to achieve those reductions while at the same time, continuing to improve reliability and customer service. We continue to feel very comfortable with our 2013 earnings guidance of $2.40 to $2.60 per share, as well as our longer-term earnings per share growth rate of 6.9% -- excuse me 6.29%, off the $2.28 per share of operating earnings that we recorded in 2012. There were a few other earnings drivers I should mention that helped us in the first quarter this year. Yankee Gas and Public Service in New Hampshire each benefited from a $7 million annualized distribution rate increase that took effect last summer. Together, they added about $0.01 per share to earnings in the quarter. Turning to the parent and unregulated companies, we earned $7.2 million in the first quarter 2013. That excludes $1.8 million of after-tax merger expenses. In the first quarter 2012, the pre-merger parent non-regulated companies had net expenses of $2.6 million and that excludes $1.1 million of merger expenses. This year's improvement reflects lower interest expense, earnings from NSTAR Communications and a lower effective tax rate that resulted from the resolution of the tax audits that I mentioned earlier. Lower interest expense was driven by a couple of factors. One is the low rate we are paying on Northeast Utilities' commercial paper program, which replaced bank borrowings last summer. Effective rate of the commercial paper program, as of the end of March 2013, is about 35 basis points, compared to a cost for short-term debt of about 2% for the same period last year. Another factor was the maturity in April 2012 of $263 million of NU parent, 7.25% notes to refinance last spring that NU issued $300 million of variable rate notes that mature in September of this year. In addition to that maturity this year, NU has another $250 million of 5.65% notes that will mature on June 1. These 2 large NU parent maturities due within 3.5 months of each other, we are evaluating refinancing strategies for the $550 million of maturing debt. Another financing event that will have a positive impact going forward, and occurred just yesterday is PSNH's redemption at par of $109 million of pollution control revenue bonds that were due to mature in 2021. The rate on those bonds is 5.45% and we expect to refinance this debt in the near term. Let me comment on economic conditions in our region. I would characterize the local economy as generally better than the U.S. and it is exhibiting some signs of improvement, particularly in the labor market when compared to the U.S. The unemployment rate for Massachusetts dropped in the first quarter, declining to 6.5% from 6.7% at year end. The unemployment rate for Connecticut also decreased in the first quarter to 8% from 8.1% at year end. While the unemployment rate in New Hampshire did increase slightly in Q1 to 5.8% from 5.7% at year end, it is still well below the national rate, which is now at 7.7%. Also, the housing market in parts of our service area is showing signs of strength when compared to the U.S. Now I'd like to provide you with a brief update on Connecticut's Comprehensive energy strategy, followed by a regulatory update that covers the filings we made in March associated with prior storm costs, as well as recent developments around the FERC ROE case. First, the developments around Connecticut's energy strategy. On February 19, Connecticut issued a final version of its plan. In its simplest terms, the goal is cleaner, cheaper, more reliable energy for Connecticut customers. The strategy includes a series of policy proposals made to expand energy choices, improve environmental conditions, create clean energy jobs and enhance the quality of life for customers in the state. It includes a 7-year initiative for expanding natural gas use, with the goal of providing nearly 300,000 utility customers with access to natural gas and building an estimated 900 miles of new natural gas mains. In addition to natural gas expansion, the strategy also calls for a significant expansion of energy efficiency investment in Connecticut and a review of Connecticut's renewable energy portfolio standards, with the potential for including Canadian hydroelectric generation as a qualifying resource under certain circumstances. It also includes investment in alternative fuel transportation. Many of the recommendations in the strategy require actions by PURA, as well as the Connecticut legislature. Various legislative proposals concerning redefining and expanding renewables, expanding energy efficiency programs and encouraging installation of natural gas heat have been reported favorably out of the legislature's energy and technology committee and are likely to be considered by the full legislature before the session ends on June 5. We look forward to the opportunities that this energy initiative will provide Connecticut and Northeast Utilities over the long term. Now to some recent regulatory updates, storm restoration was, again, a focus of our attention in the first quarter of this year. Following on the heels of storm Sandy in October last year was a major blizzard in February known as Nemo, which caused extensive damage to NSTAR Electric's Southeastern Mass. service area. That's 4 devastating storms in a 16-month period, the likes of which we haven't experienced in over 20 years. Nemo's restoration resulted in about $100 million of deferred storm costs. Combined with the approximately $570 million of deferred storm costs from 2011 and 2012, mostly at Connecticut Light and Power, we now have about $670 million of costs we need to recover. On March 1, NSTAR Electric filed a request with the Mass. DPU for recovery of approximately $35 million of cost related to tropical storm Irene and the October 2011 snowstorm over a 5-year period, beginning January 1, 2014, in accordance with our Massachusetts merger settlement agreement. We also expect NSTAR Electric to file for 2012 and 2013 major storm costs later this year. On March 28, Connecticut Light & Power filed a request with Connecticut's Public Utilities Regulatory Authority for recovery of restoration costs associated with major storms, which occurred in 2011 and 2012. Effectively, the request seeks recovery of $414 million of deferred costs over a 6-year period beginning December 1, 2014. The amount reflects a reduction of $40 million we agreed to forgo as part of the Connecticut merger settlement agreement. A schedule has not yet been set for the Connecticut Light & Power docket. Turning from storm recovery to FERC proceedings, the complaint by various parties against the base ROE earned by New England transmission owners led to the hearing phase this coming Monday. On April 17, the transmission owners and other parties of the proceeding filed updated transmission ROE analysis with the FERC, updating information previously filed to reflect current market conditions. Subsequently on April 26, the transmission owners further updated the analysis to reflect a revision to 1 company's earnings growth rate, which moves the ROE 50 basis points higher and underscores the sensitivity of the analysis to minor changes. This updated analysis results in a midpoint of 10.3% using the New England transmission owners' projected methodology approach and 9.7% using the historical methodology. The analysis indicated that our current base ROE of 11.14% continues to be within the zone of reasonableness and therefore, should not be changed. Based upon our updated testimony, the range is in 2 scenarios, one is 6.1% to 13.2% and the other is 7.3% to 13.2%. So the 11.14% is well within those ranges. Other parties recommended reducing the base ROE by approximately 200 basis points. To remind you, each 10 basis point reduction will be the equivalent of $2.1 million of annual earnings at our current investment level. We continue to believe that FERC's decision in this complaint will be viewed widely as an important statement on efforts to promote transmission development across the United States. We and others in the industry believe that a significant reduction in the ROE for New England's transmission owners would have a chilling effect on transmission investment throughout the country and would run counter to FERC's very successful policy since 2005 of encouraging transmission investment as a means to make the grid more reliable and secure. There is more to come on this issue. An initial decision from an administrative law judge is scheduled for September 10. We expect the decision from FERC commissioners mid-to-late 2014, which could be followed by requests for reconsideration and an appeal process. That concludes my formal remarks. So I'll turn the call over to Lee.

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 over to Jeff for Q&A. The Greater Springfield Reliability Project, which represents more than half of our expenditures on the news family of projects reached a significant milestone in early March when we energized the new 3.5kV section between Connecticut and Massachusetts. GSRP is now about 95% complete with some additional substation and 115kV line work still to go over the balance of this year. Overall, this project remains on schedule and has been a huge success providing grid operators with a critical new link between Western Massachusetts and Connecticut and helping us to continue to reduce congestion cost or pass-through to customers. We now expect it to be completed as much as 5% below its $718 million budget. We are very pleased with the management of this complicated project and it illustrates our continued decade-long core capability of managing large transmission projects and completing them on or below budget and on or ahead of schedule. Second large piece of news is the 3 state Interstate Reliability Project or IRP. The Connecticut Siting Council approved the Connecticut section of IRP in January. Meanwhile, our partner in IRP, National Grid, has received the unanimous endorsement for the project from Rhode Island utility regulators who have forwarded that endorsement to state siting regulators. Siting hearings have begun in Massachusetts. We still need Rhode Island and Massachusetts siting approvals, as well as environmental permits in Connecticut and Rhode Island and the go ahead from the Army Corps of Engineers. We expect to commence substation construction in late 2013 or early 2014 and line work in mid-2014. Our segment is still expected to cost $218 million. On the third major piece of news, CL&P's Greater Hartford central Connecticut project, we continue to work collaboratively with ISO New England on documenting the results of the need analysis to resolve numerous transmission constraints in central Connecticut. We believe ISO New England identified a number of projects throughout the greater Hartford and central Connecticut regions that must be built. ISO is expected to identify the preferred transmission solutions in late 2013 or early 2014, which are likely to include many 115kV line upgrades. These projects collectively are expected to cost around $300 million and are likely to require a much less siting and permitting than the single 345kV central Connecticut reliability project we have previously discussed with you. Elsewhere in the transmission system, work on NSTAR Electric's $106 million project to add a 345kV link to Cape Cod commenced in September 2012 and will be completed this summer. It is currently approximately 60% complete. I think many of you have been focused on our work on the Northern Pass project. As you may know, the project announced at the end of 2012 that it had identified a new route in a portion of New Hampshire's North Country. Since that time, our project team has worked very hard to finalize the details of this new proposal and to continue our outreach efforts with local citizens, stakeholders and communities. We had hoped to share the details of our new routing proposal by now, we have decided to continue our work on building support for the new route to ensure it is the best possible proposal for New Hampshire. There are various options we are evaluating as part of the commitment to ensure that our new route addresses the concerns raised regarding the project's potential to impact scenic views. We believe it is in the best interest of landowners, communities and all stakeholders for us to continue to take the time now to consider these various options and refinements. Of course, once these options and refinements are finalized, we will initiate formal filings in the next step of the public review process. As a result of this ongoing work, we expect the project to be complete by mid-2017. The need for Northern Pass or the Northern Pass project is clearer now than ever before. Volatility in the New England energy market this past winter underscored our region's need for new sources of clean, low-cost power to diversify our power supply and secure our energy future. Northern Pass will bring that diversity to New Hampshire and New England in the form of 1200 megawatts of clean energy from the Hydro-Québec system, almost all exclusively hydroelectric power. The benefits will be significant. And they include: helping to address the New England's acute need to diversify its electric energy supply, which is currently more than 50% dependent on natural gas. ISO New England has identified this as a top risk factor and recently warned that New England came dangerously close to an emergency condition this past winter because of the challenges created by our over-reliance on natural gas generation; bring up significant natural gas supplies now used for generation that instead could be used by the region to reduce its dependence on imported oil space heating, reducing carbon dioxide emissions by up to 5 million tons annually; and also, that would be the equivalent of taking approximately 900,000 cars off the road; lowering electric costs for New England consumers by an estimated $200 million to $300 million annually by displacing more costly fossil fuels; and providing unique and significant economic benefits to the state of New Hampshire, including the creation of 1,200 jobs during construction, approximately $26 million of annual new property taxes for local communities and the state. We continue to estimate that the project will cost $1.2 billion, including the $45 million we expect to spend on Northern Pass this year. We continue to project $636 million of transmission capital spending in 2013. For the first 3 months of this year, we invested $141 million in our transmission facilities. On the distribution side, we expect to invest approximately $670 million on our electric infrastructure and $170 million on our natural gas distribution facilities this year. In the first quarter of 2013, we invested $126.5 million in our electric distribution system and $25.5 million in our natural gas delivery system. We continue to see increased demand from residential and nonresidential customers to convert their space heating systems from oil to natural gas. As I said in our year end call, nearly 8,000 new [indiscernible] space heating customers between NSTAR gas and Yankee Gas last year. We currently project approximately 9,100 new space heating customers in 2013. In the first quarter, we added 2,800 heating customers, 1,500, of which were conversions of existing residences and 1,300 were a combination of new residential construction and commercial customers. During our previous earnings call, we discussed Connecticut Governor Malloy's energy strategy. One of the cornerstones of that strategy is to develop a new approach to increase the penetration of natural gas in Connecticut. Yankee Gas is now well advanced in preparing a proposal that will fill the state regulators -- will file with state regulators and the state energy office in the next couple of months. Areas may include changes to the hurdle rate model for making new investments to connect customers by extending the payback period and other possible changes such as a capital expenditure tracker for new mains. If approved, such changes would accelerate the conversions in 2014 and beyond. Turning to generation with the high gas prices driving high wholesale electricity prices in the first quarter of 2013. PSNH generating units operated well and with much higher capacity factors than in the first quarter of 2012. PSNH generating units generated more than 1.1 million megawatt hours in the first quarter of 2013 as compared with 750,000 megawatt hours in the first quarter of 2012. That's a nearly 50% increase. We estimate PSNH's generation saved customers about $42.5 million in the quarter as compared with buying the same amount of power in the wholesale market. Now I'd like to turn the call back over to Jeff for Q&A.

Thank you, Lee. And I will turn the call back to Yvette to just remind you how to enter questions.

[Operator Instructions]

Our first question this morning is from Travis Miller from Morningstar.

I wonder if you could go a little bit more into that 4% core gas growth. You mentioned it here at the end of the call, but was there anything in the quarter unusual? Was there any kind of specific program you guys ran or any kind of major industrial customer who came in? Anything one-off or is that kind of a growth rate that we can expect throughout the year?

Well, when you look at the customers that we're adding over our total cash customer base, we're getting 2% a year basically in customer growth. And what you've seen here in this first quarter is the usage per customer has gone up as well. So I'm not going to commit to say that the underlying gas growth number would be 4% long term, but we certainly anticipated higher growth on the Gas business than on the electric side and that's consistent with the guidance, the long-term guidance that we provided the street.

What do you think is driving that higher customer usage number, apart from the weather? Just the core gas usage is a little different than what we're seeing across the country.

I think the economy is picking up and, as I say, we've seen a number of conversions as well, the combination of those 2 has gas as the preferred fuel of choice.

Next question is from Greg Gordon from ISI.

I wanted to know, it's been an awfully long time since-- that we've been waiting for the finalization of the route on Northern Pass. And I know you guys articulated on the call that the reason for the delay is you just want to firm up local support. But are there any other extant issues whether it's underlying changes in economics or costs or things going on up in Canada or down in Connecticut with regard to sort of political sensitivities to changing economic dynamics. They are also factors here or is this just finalizing all the small details around getting firm support for the route that's causing the delay?

I would say it's really the latter, Greg. This is an important project to the state of New Hampshire, to the New England region, and to the company. I think Lee laid out well the merits of the project in terms of environmental benefits and savings to customers and jobs and property taxes in New Hampshire. We really are just trying to build as much support for the project as we can, addressing any concerns or issues that people have, so it's a matter of increased outreach to the community.

Yes, and I would just add to that, Greg, that if you look at the economics of the project looking at where New England is in terms of the volatility of the energy markets in the winter. When we have--we have certainly a more than adequate supply for the gas companies for the distribution part of the business but there's a severe shortage of pipeline capacity for generation. And what that does is really obviously pushes prices high. That's the kind of a market where HQ can capture that volatility and it actually becomes more profitable for them as a result of this situation, which really has no immediate fix on the horizon. So we think the economics of the project continue to improve.

Okay. Well, there is a significant gas pipeline expansion coming in from the Algonquin in 2015 to 2016. So I think I see your point that this winter and probably next winter are extremely constrained. But I don't think the gas situation in New England in the longer-term is actually that constrained.

It actually is constrained because we have run all the analysis and the pipeline is constrained even with the proposed pipelines coming in, that will certainly solve the issues for the EDCs and solve the issues around supporting our continued growth, but it will not solve the issue for generation and that's also the position of ISO New England as well.

Next question is from Julien Dumoulin-Smith from UBS.

Kind of following up on the last question here. Obviously if the RPS bill moved out of the Senate yesterday, to what extent does a 5% cap on hydro limit the ability for the Northern Pass project to qualify into the RPS as a hydro resource, or transporting hydro resources?

We think the passage of the bill by the Senate yesterday is good news for the state and its electric customers. It furthers the Governor's goals of cheaper, cleaner, more reliable. If I understand it correctly, large Canadian hydro would qualify for renewable status only if the state fails to achieve its goal of 20% renewable by 2020. However, Canadian hydro could still help the state meet its carbon reduction goals, whether that hydro comes from Quebec or the maritime provinces. So even though it's limited to a 5% RFP, it's more than that existed prior to this legislation, legislative proposal. So and I think it's consistent with the governor's goals and that he's welcoming all large-scale hydro. He's not having the government pick winners here. We think the RFP is likely to occur later this year if the legislation is passed.

Just to be clear, the 5% that would allow for a partial contracting of Northern Pass or something if you were to win that RFP?

That's correct.

Excellent. And then kind of going back a little bit. In terms of timeline on the routing, I mean, not to rehash that last question too much here, but at what point do you think you'll be ready to kind of definitively say we have a routing ready to go? I mean, is it another 3 months or another -- by year end kind of at this point?

Julien, right now, just based upon where we are, I would think, by the middle of this year so we're talking around the July time frame we should be ready to announce the route.

And then kind of going back to the oil to gas element here. Just how much of an opportunity is there on the table, particularly given some of the other options pursued at the legislative level to expand or accelerate that conversion rate? I mean, what is the upside here potentially in terms of putting capital to work?

Well, if you think about the expansion plan over a 10-year period, we could add, between the 2 companies, the majority of which would be at Yankee Gas, we could add about 160,000 customers. So you could add about 100,000 customers at Yankee Gas and approximately another 60,000 customers at NSTAR gas. So you're talking about taking the company right now, the total gas company is about 490,000 customers and you're talking about over 600,000, 650,000 customers over a 10-year period.

Next question is from Paul Patterson from Glenrock.

Just back to Northern Pass for a second here. Should we think that basically, I mean there, that there's been some delays in terms of getting this routing thing completely resolved. Would you guys still be, I mean, just generally speaking, you guys are still very confident, though am I right in that, that this is going to actually come to fruition? You were mentioning the economics and everything improving. On a scale of 1 to 10, how should we think about the outlook of this project as to where you saw it a quarter ago?

This is Lee Olivier. I'm not going to opine on your scale. I'm not going to opine on your scale, but I can tell you we're very, very confident that this will be built. I mean, for all the reasons I cited in the call, this project looks better and better. And if you go run out renewables, the portfolios for all of these states, which we have over the course of the next 10 years, it is very, very clear. You can't meet renewables without creating expenses that would just crush the economy of New England. This line from the standpoint of reliability actually because I talked about what happened this winter in terms of reliability. That was very, very close in terms of doing load shed this winter. So if you look at where we are in the region with the shortage of gas, if you look at the renewable portfolio and all of these states also have carbon reduction portfolios, this line will be built. It's different from anything we've done before because we've always had the right of eminent domain. It's been a pure reliability project and this one you don't. So you got a lot of stakeholders and our view of this is to get it right with the stakeholders now and that will save a lot of problems that you would have as you start the actual siting process. So it takes a little bit more time, but this line will be built.

Next question is from Michael Lapides from Goldman Sachs.

I know you can't really opine on the FERC case and honestly I'm not one who would call myself a great predictor of anything that the FERC is likely to do. But when you just think long-term and strategically where you want to allocate capital over a 5 to 10-year period, if there is a significant reduction in the authorized ROE for you and other transmission providers, would that significantly alter your views on, hey, transmission is a good place to allocate capital over long periods of time?

Yes, I think my comments earlier, Michael, commented on that, that to the extent there's a dramatic reduction here I do think it would not only show investment interest at Northeast Utilities, but across the country. And when you have distribution investments that certainly have less risk in terms of siting and development and what have you and the returns in the distribution business are north of 10%, it's hard to imagine that the transmission business much more complex, much more lead time required, more risk, development risks, it should get sort of a premium over what the investment profile is for distribution. So I do think it would have a significant impact on where utilities would opt to invest their capital in the future.

Got it. And one question, unrelated topic, just O&M management and cost reduction post-merger, how do you think you're tracking so far relative to expectations outlined at the Analyst Day in October?

I'd say that we're spot on. I mean, the guidance that we've given the Street is that we think we'll be able to achieve 3% reduction in O&M a year for '13, '14 and '15, that translates to about a $50 million a year reduction in O&M. When you look at what we achieved in the first quarter here, it was close to $25 million. So it would imply that we're ahead of the pace. But the reality is that there was some timing issues. Spending on maintenance that we didn't get to do this quarter that we did a lot of a year ago. So when you adjust for the timing I would say that we're pretty much right on track with where we want to be with that 3% reduction that we're committed to.

Meaning that your reduction year-over-year at this quarter was a little bit bigger, but you could expect maybe less of a reduction in future quarters during '13?

Exactly, Mike.

Next question is from Maurice May from Wellington Shields. Maurice E. May - Wellington Shields & Co., LLC, Research Division: Getting back to the potential for new gas customers I think you said that you have potential for 100,000 at Yankee and 60,000 at NSTAR Gas so that would be 160,000. How can we translate that potential new customer growth into rate base growth? In other words, do you have a rule of thumb of rate base growth for customer addition, anything like that?

Maurice this is Lee. We don't have a rule of thumb for that, but if you just look at Yankee Gas as an example, for new customer connections now, we spent about $27 million a year for new customer connections. And if you think about that over the 10-year horizon, that works its way up to about $80 million to $90 million a year of CapEx. So it's a fairly significant expansion in CapEx. And that's just Yankee. We have started a similar process of educating legislators and policymakers in Massachusetts and should there be a Connecticut-type of legislation, obviously, that growth in NSTAR gas could be higher as well. Maurice E. May - Wellington Shields & Co., LLC, Research Division: Okay. So at Yankee, for example, you're spending $27 million this year for the addition of how many customers?

We'll do about 4,600 customers at Yankee this year.

Next question is from Jonathan Reeder from Wells Fargo.

On your Analyst Day slides you had mentioned about the additional CapEx upside over the next several years from potential transmission projects, are there any specific items such as, like, power plant shutdowns that we're waiting to see how they play out or is this just more continuing to evaluate the recently combined system and make proposals into the ISO, when do you think you might have a better idea on these potential opportunities?

Jonathan, this is Lee Olivier. I think from the standpoint of our forecast that we provided on the last call, which is essentially the $3.9 billion. We actually know where all of that $3.9 billion will go. We know every project. Where it is, many of these, the majority of them have approvals through the ISO New England regional system plan. So we literally know where every bit of that $3.9 billion is going right now. To the extent that there is additional plant shutdowns, power plant shutdowns, that could create some additional opportunity.

But at this juncture I guess you haven't identified anything yet outside of that original $3.9 billion in the region?

No, no, nothing at all. Well, obviously, our model has continued to look at the system. We continue to find areas that need transmission fixes and as we do, we'll update you in the fall.

Our next question is from Andrew Weisel from Macquarie.

I saw the comment in the press release that weather adjusted and leap day adjusted electric sales were up 1%, can you give a little more detail on the split between states and between customer classes?

I don't have that detail, Andrew, in front of me. What I would say is that we've seen more robust growth on the residential sector on both the electric and gas side than commercial. I don't have the numbers to quote by state or even combined, but a pretty good quarter 1% growth on the electric side and 4% base growth on the gas side.

And then one just quick one on Northern Pass. I mean, certainly appreciate that it's a small, but vocal minority that are very opposed to it in New Hampshire and it sounds like you guys are really going as far out of your way as you can to try to accommodate that group. Is there a certain point at which you just say, agree to disagree, we're going to move forward? It's been a moving target and now you're saying July, is there a certain goal you're trying to reach in terms of these customer outreach programs or where do you just say, we can't make everybody happy it's for the greater good?

This is Lee Olivier, Andrew. I guess we'll say we're not there yet. We're not at a point where we're going to plow through this thing because we really do think it's appropriate. PSNH had a long history of success working with the communities and regulators. They are very, very good at this and right now, we are committed to work constructively with both of the state and the local communities and other key stakeholders. So I would say at this point in time, it's premature to say that we would plow on. We think we're very, very close on this and our partner in this, Hydro-Québec, has a long history as well of working very well in the communities and they're every bit as concerned as we are about making sure that the outcome here is right in the state and in the communities. And then as you said, you're never going to get everyone to concur with you, to agree with you. There'll always be some that will oppose, but once we feel we have brought enough consensus, we'll move forward.

Can you elaborate on what some of the sticking points are? I mean, is it where do the lines go? Is it buried versus above ground or is it height of the towers?

It's all of the above. It's literally all of the above. It's all of those issues. For instance, there's land in which we have purchased, we own or we have bought easements on and some of those areas they're fairly scenic and so where do you lay the line out? Do you lay it out in front of the tree line off a ridge? Or do you lay it out around the back that costs you some more money to go around the back of the hill. But those are all the kinds of conversations we're having. As we've said, most of these transmission towers that are about 135 feet. We've found ways to get most of the transmission towers down to 85 feet and that's after a long, long consultation with the National Forest Service. So it's that type of interaction with key stakeholders that takes the time.

Well, we don't have any more questions currently, so we want to thank you for joining us today. If you have any questions later in the day, you can give either John or me a call. Have a great day. Good luck on the other earnings calls.

Thank you.