Eversource Energy (ES) Q2 2011 Earnings Report, Transcript and Summary

Welcome to the Northeast Utilities Q2 Earnings Call. My name is Sandra, 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, Sandra. Good afternoon, and thank you for joining us. I'm Jeff Kotkin, NU's Vice President for Investor Relations. Speaking today will be Chuck Shivery, NU's Chairman, President and Chief Executive Officer; Lee Olivier, NU Executive Vice President and Chief Operating Officer; and David McHale, NU Executive Vice President and Chief Financial Officer. Also joining us today are Jim Muntz, President of our Transmission Group; and Jay Buth, our Controller. 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 risks and uncertainty, which may cause the actual results to differ materially from forecast and projections. Some of these factors are set forth in the news release issued yesterday. If you have not seen that news release, it is posted on our website at www.nu.com. Additional information about the various factors that may cause actual results to differ can be found on our annual report on Form 10-K for the year ended December 31, 2010, and our 10-Q for the first quarter of 2011. 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 and 10-Q. Now I will turn over the call to Chuck.

Thank you, Jeff. And I'd like to thank all of the investors, who are listening to our call, for joining us this afternoon. Let me start by noting that NU had a good second quarter and a very strong first half of the year, both of which were consistent with our full year 2011 earnings guidance. As you can see in our news release from last night, earnings per share were up 25% in the first half of 2011 over the first half of 2010, excluding merger-related costs. In light of the results of the first half of 2011 and our prospects for the full year, last night we raised the floor and, hence, the midpoint of our guidance for full year results. For 2011, we now project earning between $2.30 per share and $2.40 per share, excluding merger expenses. As busy as the first half of the year has been, the next 6 months should see a number of very positive events. During the second half of the year, we expect to consummate our merger with NSTAR be in full construction mode on our Greater Springfield Reliability Project, bring key elements of PSNH's Clean Air Project into operation, announce a new route for the northern section of our Northern Pass project and achieve the financial performance that supports our updated earnings guidance. Our confidence in projecting near-term financial performance is enhanced by the fact that, for the first time in more than 2 years, we do not have either a distribution rate case pending or one that is about to be filed. We continue to make good progress on the major events facing the company, our merger with NSTAR. In the past 3 months, we have achieved a number of milestones. In May, Maine regulators signed off on the merger, subject to FERC approval, which we obtained in July. If you have read the FERC decision, it fully authorized our merger as being consistent with the public interest, recognizing that the transaction would have no negative impact on competition in the New England energy marketplace. The FERC decision, when combined with the FCC approval and exploration of the Hart-Scott-Rodino Justice Department review earlier in the year, means that the Nuclear Regulatory Commission sign-off is the only federal approval we still require. As you know, shareholders of both companies overwhelmingly endorsed the merger in March. On the state regulatory side, the Connecticut DPUC issued a final decision on June 1, stating that it did not have jurisdiction over the merger because it did not involve the change of control of a Connecticut utility. While that decision has been appealed to the Connecticut Superior Court, we believe the DPUC's ruling is legally sound. At the Massachusetts DPU, we have completed hearings on the merger, with final briefs in the case due to be filed on September 19. We believe that time schedule positions us to receive a final DPU decision and close the merger in the fourth quarter of this year. The DPU hearings have provided a platform to allow NU and NSTAR to demonstrate the very significant value our merger will bring to the region both in terms of cost savings and expanded environmental initiatives. We continue to be very comfortable with our projected $784 million of net benefits during the first 10 years after closing. I know many of you have asked Jeff about the early July motion by the Massachusetts Department of Energy Resources to extend the docket schedule significantly. We have opposed that motion vigorously and believe, if granted, it would be counterproductive to stakeholder's interest by delaying our ability to bring the benefits of this merger to NU and NSTAR customers, shareholders and employees. The DPU hearing officer overseeing the case has not yet ruled on the DOER's motion, and we are hopeful it will be rejected. NSTAR is not only our merger partner, it is also our partner with the Northern Pass transmission project in New Hampshire where we continue to work through the regulatory approval process. Lee will provide you with more details, but we now believe that the project's schedule will need to be extended, with construction likely to take place from 2014 through 2016 rather than 2013 through 2015. Although we believe there is a widespread view that the project will bring very significant economic and environmental benefits to both New Hampshire and other New England states, we also recognized that there were significant concerns about the initial 40-mile route we proposed for the northern section of the line in New Hampshire where we do not currently own a right of way. We continue to listen to the different stakeholders involved in this process and to work with them to identify the best possible route for this line. As Lee will discuss in more detail, we expect to identify a new route for that northern section later this year so that regulatory review can continue. Moving from New Hampshire to Connecticut. This year, the Connecticut legislature enacted Comprehensive Energy Legislation, which, among various provisions, restructured the energy functions within state government and brought them under a new Department of Energy Environmental Protection or DEEP. The new public utilities regulatory authority, led by 3 of the previous DPUC commissioners, assume responsibilities for most of the DPUC's regulatory roles including rate cases. The more policy-driven responsibilities, such as the state's integrated resource plan, were assigned to a new energy division within DEEP. We are encouraged that, from a policy standpoint, many of the initiatives we have been advocating for years appear consistent with the views of both Governor Malloy and our first DEEP Commissioner, Dan Esty. We were also pleased that the new legislation will allow us to build 10 megawatts of regulated renewable generation in Connecticut. In approving the budget for the new fiscal year, Connecticut lawmakers revoked another piece of legislation passed in 2010 that would have been harmful to our customers. That legislation had authorized the issuance of nearly $1 billion of new bonds that would have had been to be repaid through customers' electric bills. With the state's budget picture improving, the legislature revoked the authorization before the bonds could be issued, thereby effectively lowering rates for CL&P customers this summer. We have never believed that attempting to balance the state's budget in this manner was appropriate, and we congratulate the governor and the legislative leadership on this outcome. On the regulatory front, while we were pleased with the PURA's decision on our merger, we were disappointed with its decision in the Yankee Gas rate case. We appreciate the commission's support for our capital program but agree with much of the commentary from the financial community, which has observed that the authorized ROE of 8.83% is a negative outlier for the industry nationwide. We subsequently asked the PURA to reconsider 3 aspects of its final order. And yesterday, the authority agreed to reopen the case to consider one of them. David will discuss that in more detail shortly. At FERC, we were encouraged by the recent ruling on transmission planning in cost allocation. We believe it reflects support for transportation development like our NEEWS and Northern Pass initiatives and respect for regional planning process in place in New England. Most importantly, the FERC commissioner has expressed deep support for continued investment in the nation's electric transmission infrastructure. This is a view with which we clearly agree. Finally, we are quite pleased with the company's ongoing operations. Our customer service metrics continued to improve. Our reliability is sound even in the face of the record heat we experienced in the northeast 2 weeks ago, and the response of our employees to the extreme weather events, such as the June 1 tornado that struck Springfield, Massachusetts, has been very well-organized and carried out. We've received a number of positive comments from both state and municipal leaders on our response to these severe storms. Lee will provide more details on our operations and on the progress of our major projects. And now, I will turn over the call to him.

Thank you, Chuck. Our operating performance was quite good in the first half of the year and has remained strong since the start of the summer. We had 2 major weather events in June, which caused significant damage and to which our organization responded very well. On June 1, a damaging tornado tore through the city of Springfield. In the following week, 3 days of thunderstorms accompanied by high winds knocked out power to approximately 300,000 of our customers across 3 states. In both cases, the vast majority of customers had their power restored within the first 36 hours. Our prompt response to outages, along with outstanding call center performance, mitigated long protracted service restorations and drew praise from state and local elected leaders. In total, we spent about $17.8 million in restoration activities following those storms. More than $15 million of that, which has either been capitalized or applied against our major storm funds. Pretax storm-related costs actually fell by about $5 million in the second quarter of 2011, as compared with 2010. We believe our customers appreciate the improvements we have been serving them. In the most recent JD Power survey of utility customer satisfaction, all of our electric utility scores improved, and Yankee Gas remained the highest ranked mid-sized natural gas distribution company in the northeast. Our $430 million Clean Air Project, a wet scrubber being installed at our 2-unit Merrimack coal-fired station, is ahead of schedule and currently 86% complete. System tie-ins, startup and commissioning activities are expected to begin in the fourth quarter of 2011, and the scrubber itself could be operational by the end of the year. The [indiscernible] project should be completed by mid-2012. You may recall that the scrubbers required -- is required under New Hampshire's mercury reduction law, which was enacted about 5 years ago. Two weeks ago, the New Hampshire Supreme Court dismissed, in an appeal that had been filed against the project, saying the plaintiffs did not have standing to bring the case. In Massachusetts, our first solar installation, a 1.8-megawatt facility in Pittsfield, has operated well; and our second facility, a 2.2-megawatt installation, was under construction at a brownfield site in Springfield and should be completed by the end of the year. Turning to transmission. Our transmission capital expenditures totaled $164 million in the first 6 months of 2011, and we expect the pace of capital spending to accelerate in the second half of the year as we move into full construction mode on the Greater Springfield Reliability Project. The GSRP is the largest of the 3 major projects we expect to undertake as part of the NEEWS family of projects. In Massachusetts, we commenced substation work on GSRP in December of 2010 and began site work on the overhead section in the first quarter of 2011. We recently began substation work in Connecticut, and we continue to expect full construction in Massachusetts to begin later this quarter after we receive the required Army Corps of Engineers and Massachusetts environmental permits. We need those permits to work in or near wetland areas, and we've made substantial progress working through the remaining environmental permit issues over the past 3 months. We expect to receive the permits by the end of this month or in the first part of September. The workforce and materials are available to start construction in the wetland areas immediately upon the receipt of the permits. In the meantime, we have accelerated our work on areas where we already have full permitting. As a result, we now estimate that the GSRP project is approximately 36% complete, and we remain on target to complete the project by the end of 2013. To date, we have spent $231 million on GSRP. You may recall, during our May earnings call, I had mentioned that we had filed an application with FERC to recover in regional rates the financing cost of NEEWS during the construction period. That change has, in effect, reduces the AFUDC but increases cash flow from NEEWS during the construction period. This is related to the interplay between our local network rates and our regional network rates. FERC approved our application for our construction work in progress effective June 1, 2011, in regional rates, and as a result, we will be capitalizing less the financing cost for NEEWS during construction. This is good for New England customers because it will ultimately result in a lower-cost project to be supported in regional rates. As I mentioned during the first quarter earnings discussion, this change reduces our total cost of NEEWS, net of the United Illuminating investment and the larger Connecticut projects to approximately $1.35 billion. For the Greater Springfield Project, it reduces costs from $795 million to $718 million. By the interstate, it reduces the costs from $251 million to $218 million. For the Central Connecticut project, it reduces the estimated costs from $338 million to $301 million. Those AFUDC-related changes were already factored into our rate base projections that we published in our in-report earlier this year. We do not believe it should have any impact on the NEEWS-related earnings estimates Street analysts have developed. Turning to those other 2 major NEEWS projects. We at National Grid expect to file our siting applications in Connecticut, Massachusetts and Rhode Island late this year to build the Interstate Reliability Project. Last month, we began formal consultations with several municipalities in Eastern Connecticut, a requirement before we file our formal state application. The Central Connecticut Reliability Project continues to be reviewed by ISO New England as part of the overall review of transmission in Central Connecticut. We expect the review to be completed and needs identified in late 2011 with specific projects identified in late 2012. We received good news from Washington in late June when the FERC denied, in a 3:1 vote reconsideration of the financial incentives for NEEWS that were approved in late 2008. To remind you, those incentives include recovery of abandoned cost, a cash return on construction work in progress while the projects are under construction and a 12.89% return on equity. Also, I should note that on July 22, electricity usage increased significantly when the temperatures hit an all-time record of 103 degrees at Bradley Field north of Hartford. The preliminary New England peak demand load of approximately 27,700 megawatts appeared to be the second highest ever recorded in New England. Fortunately, the region's generation transmission systems performed very well. The unanticipated increase in peak demand which would have been even higher if it -- if not the fact that it occurred on a Friday afternoon, when many in the workforce begin their weekend departures, underscores the likelihood that peak demand is again rising in the region. Earlier, Chuck discussed some of the recent developments concerning the Northern Pass project. Recall that the project involves 180 miles of new transmission line in the state, including an AC section in Southern New Hampshire. Of those 180 miles, we currently have right of way for 140 miles. Our focus right now is on the 40 northernmost miles where we need new right-of-way. We continue with our outreach in New Hampshire stakeholders and communities as we identify and secure a route for those 40 miles and hope to announce such a route later this year. We are making solid progress in this effort. This process of identifying routes and providing stakeholders with time to review and comment has added about an additional 9 months to the siting process. That is why we now estimate that the construction will begin in early 2014. As you may know, the U.S. Department of Energy environmental assessment process begins once a specific route is submitted. We applied last fall with the DOE, and they have left open the public comment period on the project so that the participants in the review process can comment on the route that we identified. The DOE will announce a consultant who will be working on the environmental data already collected for the lower 140 miles of the route. We expect this process to continue throughout this year and into 2012 as we advance through the siting process. Additionally, we will begin preparing our application for the New Hampshire Site Evaluation Committee once the northern 40 miles of the route are identified. On June 28, we took another step forward on Northern Pass when we filed a special use application with the U.S. Forest Service to build approximately 10 miles of the Northern Pass project along our existing right-of-way corridor that runs through the White Mountain National Forest. PSNH developed this corridor more than 60 years ago and currently operates a 115-kV line there that serves customers north of the national forest. We are proposing to relocate the existing line and build the new 350-kV DC line in this corridor. We look forward to working with the forest service as it participates as a cooperating agency in the overall review of the project's Environmental Impact Statement. As a reminder, the project has a number of benefits for New Hampshire and the region. It is expected to add more than $25 million a year in local property tax revenue and add 1,200 construction jobs. We estimate it will reduce the region's wholesale electric cost between $200 million and $300 million annually, including at least $30 million that would accrue to New Hampshire, and reduce CO2 emissions by as much as 5 million tons a year. Despite the later projected start of the construction in 2014, we continue to estimate that the project will cost about $1.1 billion, including in-stores 25% share. At the EEI conference in November, we will update our year-by-year capital expenditures projections for the Northern Pass to reflect the 2014 to 2016 projected construction period. Turning from electric transmission to natural gas distribution. Yankee has completed about 76% of its $57.6 million Waterbury-to-Wallingford project. We continue to expect the project to enter service by November 1. And the DPUC rate decision allowed the entire project to be included in rates. In the rate decision, the DPUC also endorsed Yankee Gas's plan to significantly increase its capital spending by $25 million to $40 million annually to replace older cast iron and bare steel pipe. As Chuck noted earlier, we are not pleased with other aspects of the decision, and we will continue to focus on how we can more effectively manage the operation and maintenance resources at Yankee Gas to mitigate the impact of this decision on financial performance. Yankee Gas sales continue to be strong in the second quarter, some of it related to cooler temperatures in April and May. Firm retail sales rose 18.4% in the first half of 2011 compared with the same period in 2010. On a weather-adjusted basis, firm sales rose 6.6%. With housing starts still relatively low, a great deal of the increase sales is the result of new distributed generation coming online and fuel switching driven by high oil prices and low natural gas prices. Approximately 2/3 of this increase was a result of new distributed generation facilities coming into service. For the second quarter, weather-adjusted commercial and industrial sales rose 25.7% and 11.2%, respectively, over 2010, primarily driven by the same factors. We also continue to see convergence in residential space, as evidenced by a 7.8% weather-adjusted increase in residential sales over second quarter 2010. This can be primarily attributed to increases in master-needed multifamily buildings converting from oil to gas. Now what I'd like to do is to turn the phone call over to David.

Thank you, Lee. Our results for the first half of 2011 reflect many of the same favorable trends we've seen since the middle of 2010. They include improving distribution results as rate increases and cost control measures have allowed our returns to recover from last year's low levels, favorable transmission earnings as we continue to invest in our infrastructure and a decline in the competitive business earnings as those businesses, particularly the Wholesale Marketing business, winds down in 2013. As a reminder, those results are now folded into our NU parent and other companies' business segments. As Chuck noted earlier, we have raised the lower end of the distribution segment guidance in the NU consolidated guidance by $0.05, effectively raising the midpoint of NU's earnings guidance for the year. Our new range of $2.30 per share to $2.40, excluding merger costs, reflect the results we have experienced in the first half of 2011. The warmer temperatures and storm expense we have experienced in July and our prospects for the balance of the year, including the progress we are making on our major projects particularly the Greater Springfield Reliability Project and PSNH's Clean Air Project. In fact, the progress we are making on our transmission program this year is expected to result in us earning toward the upper end of our transmission guidance. I will discuss our updated guidance in more detail shortly. Overall, we earned $77.3 million in the second quarter of 2011 or $0.44 per share compared with $71.9 million or $0.41 per share in the second quarter of 2010. Over the first 6 months of 2011, we earned $191.4 million or $1.08 per share compared with earnings of $158.2 million or $0.90 per share in the first half of 2010. Excluding charges related to our merger with NSTAR, we earned $200.9 million or $1.13 per share in the first half of 2011, up nearly 25% over 2010. Although we believe we are well positioned for a successful year, and you can see that in our adjustments to guidance, I recognize our results for the quarter fell a little short of consensus, some of that may be due to the fact that, last year, our competitive businesses added about $0.03 for the quarter versus breakeven this quarter. We believe other items are timing-related including PSNH rate case-related revenues and the pattern of transmission earnings where we see continued positive momentum for the second half of this year. Our Transmission segment earned $42.4 million or $0.24 per share in the second quarter of 2011 compared with earnings of $41.9 million or $0.24 per share in the second quarter of 2010. Over the first 6 months of 2011, our Transmission segment earned $86.9 million or $0.49 per share compared with earnings of $82.1 million or $0.46 per share in the first half of 2010. Improved year-to-date transmission results reflect our ongoing investment in a high-voltage grid that serves the region as well as our forward-looking fully-tracking transmission tariffs. We expect transmission earnings growth to accelerate over the coming quarters as we move into full construction mode on the Greater Springfield Reliability Project Lee mentioned a moment ago. Due to Greater Springfield and many smaller projects that are now under construction, our transmission rate base totaled $2.78 billion as of June 30, 2011, compared with $2.64 billion at June 30, 2010. I know that some of you have noticed that CL&P's Transmission earnings were $2.1 million lower in the second quarter of 2011 than they were in the second quarter of 2010. This occurred even though CL&P's transmission rate base in the first half of '11 was about $2.15 billion, nearly 2% higher than it was in the first half of 2010. The reason for the decline in earnings is that we true up the many tracking features of our transmission tariff to coincide with the filing of our FERC Form 1 for the previous quarter, which is done in the second quarter each year. In 2011, that true-up resulted in a refund to our wholesale transmission customers, while in 2010, it resulted in incremental billings. That year-over-year change resulted in a decline in CL&P's second quarter Transmission earnings of $3.7 million from 2010 to 2011. We have no similar true-ups for the remainder of the year. Overall, we remained very comfortable with our 2011 Transmission earnings guidance of 105 to 110. In fact, as I mentioned earlier, we believe we'll earn toward the upper end of that range. Turning to the Distribution business. We earned $40.3 million or $0.23 per share in the second quarter of '11 and $118 million -- excuse me, $118.5 million or $0.67 per share in the first half of 2011. This compared with earnings of $27.1 million or $0.15 per share in the second quarter of '10 and $75 million or $0.43 per share in the first half of 2010. CL&P's Distribution segment earned $19.1 million in the second quarter of 2011 and $47.6 million in the first half of '11 compared with earnings of $8.4 million in the second quarter of '10 and $22.7 million in the first half of 2010. This improvement was due to a combination of strong cost controls and to the distribution rate decision we received last year, partially offset by higher pension and healthcare costs. That rate decision was approved a $63.4 million rate increase effective July 1, 2010, and an additional $38.5 million that was effective on July 1, 2011. As of June 30, 2011, CL&P's trailing 12-month distribution ROE was 9.8%. At this point in the year, we project a full regulatory ROE of about 9% for the year. PSNH's Distribution/Generation segment earned $16 million in the second quarter of 2011 and $37.5 million in the first half of '11, compared with $16.9 million in the second quarter of '10 and $28.1 million in the first half of 2010. PSNH benefited from this July 10 distribution rate increase in AFUDC earnings from the Clean Air Project, but those benefits were offset by higher pension and healthcare costs. Additionally, there were a number of relatively small onetime positive impacts in the second quarter of 2010 when PSNH concluded its rate case. Those positive impacts, which totaled about $3.85 million after tax, resulted from the fact that the final rate decision was retroactive since August 2009. While we have the benefit of higher rates in the second quarter of 2011, we lost the benefit of those 2010, onetime impacts. As a result, PSNH's second quarter 2011 Distribution earnings were down by about $1 million from 2010. PSNH Distribution regulatory ROE, including Generation earnings, was 10.3% for the 12 months ended June 30, '11. We expect that level to decline over the last 2 quarters of the year and for PSNH's Distribution regulatory ROE to be approximately 9% for the year. This is primarily due to the roll-off of the recruitment period associated with PSNH's decision from last year. From mid-2010 through mid-2011, we recovered approximately $13.7 million from customers to recoup revenues that we would otherwise would have recovered from customers from August 1, '09 to mid-2010. With those dollars now fully recovered as of June 30, '11, our distribution rates declined last month by about $2.3 million on an annualized net basis. The Western Massachusetts Electric. The Distribution segment earned $4 million in the second quarter of 2011 and $9.7 million in the first half of 2011 compared with $2.3 million in the second quarter of '10 and $5.2 million in the first half of 2010. The improvement was primarily due to the resolution of WMECO's distribution rate case earlier this year, partially offset by higher operating costs. WMECO's Distribution regulatory ROE was 6.5% for the 12 months ended June 30, '11, compared with an authorized return of 9.6%. We expect Western MEC's distribution ROE to increase to approximately 9% for the calendar year of 2011. Recall that, due to decoupling, which began 6 months ago, sales volumes have little impact on WMECO's earnings. Overall, retail electric sales fell 1.3% in the second quarter of 2011 compared with the same period in 2010. The first half retail electric sales rose 0.9% in '11 compared with 2010. Weather-adjusted retail sales were down 0.9% in the second quarter of '11 and down 0.5% for the first half of 2011 compared to the same period in 2010. This weather-adjusted sales decline, while somewhat more moderate than we have been experiencing in the past few years, is nevertheless a bit larger than the flat year-to-year weather-adjusted sale change we have projected at the start of the year. Within customer classes on a weather-adjusted basis, year-to-date residential and industrial sales were flat. The weakness we are seeing is in the commercial sector where sales were down 1.3%. It's a very different story on the natural gas side of the business, as Lee mentioned. For the year-to-date, Yankee Gas firm sales were up 18.4% and weather-adjusted firm sales were up 6.6%. Commercial industrial sales continue to benefit from increased migration of interruptible customers switching to firm rates. And just to be clear, these results and our views around sales for the balance of the year are incorporated into our updated guidance. Yankee Gas earned $1.2 million in the second quarter of '11 and $23.7 million in the first half of '11 compared with a loss of $500,000 in the second quarter of 2010 and earnings of $19 million in the first half of '10. Yankee's sales increases were partially offset by higher operating costs, including higher pension and healthcare expenses. Chuck mentioned earlier that, despite some constructive changes between the draft Yankee Gas rate decision and the final decision, the overall order was disappointing. The final decision resulted in a rate decrease of approximately $500,000, which was effective July 20, to be followed by a rate increase of about $6.7 million effective July 1, 2012. While the PURA accepted our proposed capitalization ratio of 52.2% common equity and 47.8% debt, the authorized ROE of 8.83% is below what we think is a fair and reasonable return even in this economic environment. Also, the final decision disallowed firm rate base certain equipment that is now in-service, and serving customers, and disallowed recovery of wage increases for non-union personnel. It also lowered rates by $1.5 million in rate year one and $3 million in rate year 2 to reflect expected savings from our merger with NSTAR, which still awaits approval. We've asked PURA to reconsider 3 specific issues contained in the final decision. One was the implication of merger savings; another, the inclusion of non-union wage increases in rates over the next 2 years; and the third, related to the correct regulatory treatment for deferred tax assets related to net operating losses associated with bonus depreciation. Together, these items totaled $3.6 million in rate year one and $6.1 million in rate year 2. On August 2, yesterday, the PURA issued a draft decision granting our request to reconsider the deferred tax asset related to the net operating losses but denied our request to reconsider the imputation of merger savings and the exclusion of wage increases. If our request relating to the deferred tax asset is ultimately approved, it would amount to a pretax benefit of about $750,000 in the first rate year that begins this quarter and about $1.1 million in the second rate year, which begins in July 2012. Yankee's regulatory ROE was 9.9% for the 12 months ended June 30, '11, but we expect that level to decline over the coming quarters as a result of the rate decision. Turning from our regulated businesses, NU parent and other companies, we had net expenses of $5.2 million in the second quarter of 2011 and $14 million in the first half of 2011 compared with earnings of $2.9 million in the second quarter of '10 and $1.1 million in the first half of 2010. The 2011 results include $1.2 million of net expenses in the second quarter of '11 and $9.5 million of expenses in the first half of '11 related to the pending merger with NSTAR. Excluding those items, we recorded net expenses of $4 million in the second quarter of '11 or $0.03 per share. In the first half of '11, excluding expenses, we recorded net expense of $4.5 million, also $0.03 per share. As I mentioned earlier, the lower return in earnings this year are largely due to the wind-down of our wholesale business within our remaining competitive companies. As I noted earlier, we raised the full of our earnings guidance for 2011. With the first half of the year now behind us, we are comfortable narrowing our Distribution and Generation segment earnings guidance to between $1.30 and $1.35 per share. We continue to project net expenses of about $0.05 per share in the parent and other businesses, excluding merger costs. On a trailing 12-month basis, our earnings are $2.39 per share for the period ending June 30, 2011, excluding merger and 2010 NU parent tax settlement impact. As a heads-up, if there is a decline in trailing 12 months earnings over the balance of this year, we expect it will occur primarily in the third quarter. You may recall, that in 2010, we and many other utilities in the Northeast benefited from extremely warm third quarter temperatures. And while July '11 was indeed quite warm, we have not experienced and do not expect to experience the same number of cooling-free days we recorded in 2010. Turning from earnings to debt assurances, balance sheet and cash flow. In May, we took advantage of strong demand for high-grade utility debt to sell $122 million of taxable PSNH first mortgage funds. The 10-year bonds carry a coupon of 4.05%, and the proceeds were used to redeem about $120 million or 6% tax-exempt bonds. We continue to expect PSNH to issue another $160 million of taxable bonds later this year and for WMECO to issue $100 million of senior unsecured notes. We expect to benefit from S&P's decision on May 16 to raise all NU debt deferred stock ratings by one notch. That ratings action was based solely on NU's improved stand-alone credit profile. S&P maintained its credit watch positive rating on NU and our 4 regulated subsidiaries, subject to confirmation of our pending merger with NSTAR. One key factor triggering that credit upgrade is our improving cash flow. Cash from operations after retirement of rate reduction bonds totaled approximately $652 million in the first half of 2011 compared with $405 million in the first half of 2010. Mostly as a result of that strong operating cash flow, our total debt level declined nearly $150 million in the first months of this year so our common equity levels rose by more than $100 million. Total debt represented about 54.5% of our consolidated capital structure at the beginning -- at the end of June, well below the 60% level we have discussed for a number of years. Much of that improvement reflects the benefits from bonus depreciation for income tax purposes. We continue to project full year cash flows from operations of between $900 million and $950 million this year after repayment of PSNH and WMECO rate reduction bonds. Five years ago, we were generating less than half that level of cash, and we believe that improvement underscores the continued financial strengthening of our company. Thank you very much for your time this afternoon. And let me now turn the call back to Jeff Kotkin.

And I'll turn the call back to Sandra so she can remind you of how to enter your questions. Thank you, Sandra.

[Operator Instructions]

All right. Thank you very much. Our first question today is from Greg Gordon from ISI. Greg?

Two questions. First, the pushing back the start of the expected construction date for Northern Pass. I mean, specifically the extra 12 months, what do you think that's going to, that that extra time is going to allow you to accomplish? I mean, specifically what parts of the negotiation or what issues have you slotted in for being resolved over that incremental time period?

This is Lee Olivier. It's really about 9 months. And what that 9 months will do is -- if you think about the 180 miles, we need to do a couple things. One, we've got to secure the right-of-way. We have 180 -- 140 miles secured, so we'll be working in the northern communities where we need to secure another 40 miles. So we'll be tracking with municipal officials, landowners and so forth and other key stakeholders in that area. And we have to do the environmental assessment. We have a contractor that will put together an environmental assessment that looks like 2 seasons. It looks at both kind of spring and fall. And we've already started that on the first 140 miles on the existing right-of-way. We'll be turning over that data and information fairly soon to the DOE third-party contractor that will evaluate it. And then once we finalize the last 40 miles, we will conduct whatever additional environmental studies we need to do on that last 40 miles. So the additional time allows us to do the environmental analysis over 2 seasons and also work in the communities to build consensus and to line up the rights-of-way through that last 40 miles. And as I've said in my discussion, we're making very solid progress on that.

Great. My second question is with regard to the time line in getting the final decision in Massachusetts. It's just it's not completely clear to me how the resolution of the pending proposal from the DOER will take place. I mean, is it possible that the commission will just rule, and in the context of approving the merger, just say, "Yes, we looked at that, and didn't think it was necessary." Or do they have to make a separate independent ruling on his motion at some point between now and when they make a final decision?

Greg, this is Chuck. I think your first suggestion is clearly something that could happen. They could simply wrap the DOER motion into the final ruling, and have a final ruling that just is comprehensive. They could wait and -- or could take the position that they want to rule on the DOER motion. But either one of those is possible.

Okay, so it's just not clear in terms of milestones, whether we will get a separate ruling or whether we'll just hear nothing until they make a final decision.

Yes, that's -- I think, Greg it is positive that they have -- the hearings have concluded, and they have set the schedule for the briefings. So as you know, I think David mentioned that reply briefs are due by September 19. So at least we're moving forward, I think, on that schedule. The commission than has the time, whatever time it needs to make a final decision. But as I said earlier in the script, we believe that, that is a sufficient decision -- sufficient time to make a decision and allow us to close the merger before the end of the year.

Thank you, Greg. Our next question is from Justin McCann from Standard & Poor's Equity. Justin McCann - S&P Equity Research: You have already discussed the wind [indiscernible] negotiations for the last 40 miles of the Northern Pass transmission project. But could you explain precisely what is specified by the Eminent Domain Bill in New Hampshire? And then one more question, could you then discuss the projected timeframe for the wind power projects that are in development, as well as for company decisions related to potential influx?

Okay. In regards to the Eminent Domain Bill that was in the New Hampshire legislature, as you may recall, the eminent Domain Bill was approved in the House of Representatives and was then sent to the Senate. And in the Senate, it was essentially moved to re-refer, which means it's essentially stable. And the Eminent Domain Bill, what that would have done is essentially it would have precluded the right of eminent domain for any other project other than essentially reliability based projects. So if that was the case, then it would be very difficult to develop any other renewable resources inside of New Hampshire, so we thought that was discriminatory. So it sits over in the Senate in re-referral. And at some point in 2012 when the New Hampshire legislative session is back in which is in the January timeframe, they will take it up sometime in that session, could be at the beginning, could be up the end. In regards to wind development in New Hampshire, if you could just elaborate a little bit more on that, Justin, I would appreciate it. Justin McCann - S&P Equity Research: Well, I was thinking, it's like your -- you have potential sites in Vermont parts of New Hampshire and also in Maine. And I'm just wondering what kind of timeframe you have regarding decisions regarding the development of those sites, if you decided to do so.

Yes, in regards to actual wind development right now, Northeast Utilities does not have any ongoing wind development in any of the northern 3 states. As Chuck indicated, we have renewable development in solar in Massachusetts and a to-be-determined 10 megawatts of renewable in Connecticut. The wind developers in the north are all essentially commercial competitive enterprises, and what we do there is a system, as necessary, to make interconnections through their wind development, most notably in New Hampshire. And we actually are working on some now in Western Massachusetts in the Berkshires region.

Thank you, Justin. Next question is from Paul Patterson from Glenrock. Paul?

The customer migration decision that happened in New Hampshire, how does that work out going forward? Do you recover from existing customers? What's the sort of the thought process since that order came in?

Well as stated. As it stands now, the order sort of directs us to when we file our next energy supply rate, which is the rate from July 1, 2010 -- 2012, going forward. We will pro forma into that rate all of our costs of service and, of course, all our fuel recoveries and the like, both for our own generation and for the market generation. And at that time, they also directed us to propose various rate design mechanisms that could potentially address some of these migration issues. So that's really our next step, is to begin to work with the commission and make some proposals in the fall of this year.

Okay. So is there any, is there sort of a regulatory balance that you guys are keeping as a result of this? And since you -- I mean, I assume that you -- this amount that, I guess, is being recovered at this moment, correct?

Well, all amounts at this point are being recovered through our customers. And if there's an under- or over-recovery, those monies are trued up in the subsequent ES filing. So there's no recovery issue per se.

And I would add, Paul, that PSNH serves about 99.8% of its residential customers as of June and about 50% of all the commercial customers. So there is still a large customer base that buys their power directly from PSNH.

I got you. The weather normalized. You guys did mention that perhaps it was decreasing, but normal weather -- weather normalized usage was fast declining a little bit more than what I, if I got you correct, I don't know If I completely heard it right, before, I think last quarter, you thought it was going to be sort of a flattish kind of situation. Could you just elaborate a little bit more on what that means and, I guess, what's sort of driving that?

Paul, again, it's David. We had made a statement when we set sort of direction for 2011, our guidance, that it was premised on a number of underlying assumptions that we try to bring current with the Street, and one of those is sales growth. And we have said general observation has been -- since 2005, we have seen demand disruption or negative load growth, if you will. This year, we actually had a little bit more optimism going into the year and thought that weather-adjusted sales would be flat. And we did see, right out of the blocks, some negative prints even though we had seen a little bit more favorable results, maybe in the spring. Our actual observation now and what we said in the call is weather-normalized sales were down 0.5%. So it's certainly better than the last 3 to 5 years of trend but not based on what we thought going into the year around projection. That said, the delta between flat sales and being down 0.5% is not a major earnings driver for this year. And as you know, our Massachusetts utility now has revenue decoupling, so it sort of neutralizes that issue. I think it's no surprise that we're going to stop short of calling for a double dip for sure, but no surprise that the New England economy and our economies have not reaccelerated in terms of growth, in terms of job creation, in terms of housing and the like. So you have more economic, sort of -- fundamentally more economic weakness than we might have hoped for 6 or 9 months ago. And I think, on top of that, you do see, and Lee mentioned this, you do see fuel switching, which means customers who are going to DG were losing electric load, although we have a nice hedge, and now we're picking up gas sales at Yankee Gas. So you're seeing that type of activity. And you are seeing policies that are trying to incent customers to move in that direction, whether it's large commercial customers or even smaller customers who are installing solar. And then I think, second, another fundamental trend, which I do not see sort of seizing by any means is states incenting utilities and providing more monies to fund conversation, load management and DR [ph] programs. In fact, you may know that, throughout New England, these programs have not only funded in rates by distribution companies but by proceeds from the Reg E option and proceeds by the FCM option. So there are monies flowing into demand response, and as the efficiency that are also putting downward pressure on our sales.

Just also finally, the smart meter. Was there finally a decision at the DPUC or, I guess, the DEEP as it's is called now? Any -- did that ever get decided? And what's driving it?

Paul, this is Lee Olivier. That has not yet been decided yet. There is currently not a schedule inside of the current PURA organization to make a decision on EMI Smart Grid.

Thank you, Paul. Our next question is from Ashar Khan [ph] from Visium.

So Lee, can I just, going back to what you said, should this 9-month delays, so should we just proportionately take, like, 75% of numbers? And the majority of the spending was in '13, '14, '15 and just move them, like, one year later? Is that a good benchmark, I guess, with little change to CapEx?

Ashar, yes, I think that's a good way to position the numbers, essentially shifting them over by one year because the type of work that will go on now will just be -- will just move out another year.

Thank you, Ashar. Our next question is from Jonathan Arnold from Deutsche Bank. Jonathan?

A quick question on Massachusetts and where you are in the stage, in the process with the merger. Is it still kind of possible procedurally that the settlement could emerge on these issues? And then sort of second part to that question, the DOER seems to be focused on sort of trying to address NSTAR rates beyond their current rate plan. And then is it conceivable that all these things could get wrapped up into something that might sort of precede the merger?

Jonathan, this is Chuck. I think, with respect to any settlement, and obviously we don't speculate on settlements or at this point in time. But you could if there was a settlement that was reached, it obviously would be part of the merger process, I think, that the DPU would have to deal with. With respect to the DOER issue, first of all, we don't believe that the motion is appropriate. We think the process that we've gone through, with weeks of hearings of over 1,000 interrogatories, have in fact proven the standard, which is as you know, a net benefit standard at this point in time. And that we would hope that the Massachusetts DPU would not look favorably on that motion.

Right. And let me ask on another topic. I believe you still need the NRC, and it seems to be kind of caught up in some technicalities. Any sense of how that might play out and what sort of timeframe?

Yes, we think that the NRC approval will be forthcoming and will be forthcoming on a timeframe that it will not delay the merger. The technicalities that, I think, you're referring to are the foreign ownership issues. And as you know, we own a portion of essentially the spent fuel pools of 3 power plants, hence the NRC requirement. We don't believe that foreign ownership issue is really the merger issue. And we would hope that the NRC would come forward with their decision on the merger irrespective of the foreign ownership issue.

Is there a schedule for this? Or it's just handpicked?

No, there's no schedule, but as I said a little bit earlier, we think we will have that decision from the NRC in a way that would not slow down the merger approval.

Thank you, Jonathan. Next question's from Travis Miller from MorningStar. Travis?

What were the storm costs in the second quarter? And what have they been through July so far?

Storm cost in second quarter. Well, for the second quarter's -- storm costs were lower in the second quarter by $5 million over the second quarter of 2010. And I think we’ve spent essentially $22 million year-to-date in major storms. Again, $14 million of that was capitalized. I think those are -- is that it Dave? I don't know if you have any more refined numbers.

No, I think those are fine, Lee.

Yes.

Okay, $14 million capitalized and then $8 million as expense, year-to-date? Okay.

Yes. And as I said, in terms of the actual O&M storm expenses that affect earnings were about $5 million on them.

Thank you, Travis. Next question's from Chris Ellinghaus from Williams. Chris?

David, can you quantify what the CL&P transmission true-up was in the quarter?

Yes, and just for comparative, and I've said it's probably worth repeating, I mean, just the nature of the scheduled '21 tariff. Every second quarter, we go through this true-up process, up sometimes a fairly small number, sometimes it's a little bit more meaningful. But just by way of, I guess, facts, in the second quarter of 2011, it actually lowered our earnings by $1.1 million. In the second quarter of 2010, it actually increased our earnings by $2.8 million. And just a little history, in Q2 of '09, it would have been an increase of $1.5 million. So there is sort of a pattern and a history. It can swing either way, but those are the numbers. So it's basically a $4 million swing between '11 and ‘09.

Okay, great. And those are pretax?

No those are earnings numbers.

Okay. Your O&M year-to-date, are you on track for -- or can we believe that that's sort of the run rate for the rest of the year?

Well, I admit that it's a little tough to decipher O&M run rates, looking at our income statement, given all the accounts that actually run through that. But I'll tell you that the O&M run rate this year is, it really in good standing. We've had very good sort of cost controls on the basic fundamentals of the business. Where we have had some ownings and increases they’ve generally been funded by the regulators around programs or enhanced reliability, as an example. And even if you look at some of the trouble spots, Chris, around, say, on collectibles, we have a very good trend there. And that's pretty much in check at this point, although it continues to get a lot of attention.

Okay, great. If my recollection is correct, I think, last year in the third quarter, you were suggesting that maybe you had about a $10 million pretax benefit for weather last year, is that correct?

Yes. I think, Chris, it was. If you looked at the third quarter of last year versus a normal third quarter, it was about, after tax, it was about $7 million or about $0.04 a share. So if we had had an average summer last year, third quarter earnings would have been $0.04 lower.

Okay, great. That's consistent with what I've got. Would it also be fair to say that, while we were all probably planning for weather, that at this point it looks like you won't get all the way back to normal if sort of the trend from July holds forward?

Yes, I think that's a fair statement. We're not -- we're tracking close. As I’ve said we're down 0.5% of sales and probably driven by the economy are going to have to accelerate. And if you look at where we've seen the fall-off, as I said that's in commercial, we don't see at this point a reemergence of our commercial class of customers. So I think that's a fair statement, Chris. We probably won't get back to flat, but we'll bring you current at the end of the third quarter.

Thanks, Chris. Our next question is from David Paz [ph] from Merrill Lynch. David?

Just going back to Northern Pass, just could the CapEx there be revised with an alternative route?

David, this is Lee Olivier. Based upon everything that we see right now, we still think that $1.1 billion is a good number. The final disposition on the capital is really driven by the siting process. So when you get through the siting process, and you're ready to start construction, you do kind of a true-up or reestimate of the labor and materials of the project and whatever workarounds, and that gives you kind of the final look. Right now, we think that $1.1 billion number is good, but it's subject to change. I don't think it would be any less than that.

Okay, got it. And then on the NEEWS projects, can you remind me what the allowed return on equity is during the construction phase and does that differ from the online phase?

It's 12, 8, 9, David.

It does not differ.

It doesn't differ.

Not different. Okay, got it. And I thought you had about $130 million of projected spend on Merrimack through '13, so we should effectively have that now just through the middle of 2012?

Yes, that's correct.

All right. Thank you, David. Next question's from Jim von Riesemann from UBS. Jim?

I just have a quick question on New Hampshire and legislative strategies up there. Can you just provide a little bit of color with what's going on in legislature next year and how that your strategy might be framed around Northern Pass?

Jim, this is Chuck. It's really difficult to say. I think, as Lee mentioned and as one of the folks asked a little bit earlier, the question around the Eminent Domain Bill was re-referred in the Senate so there will be essentially a reevaluation of that and then a re-discussion of that in the legislature next year. But that's really the only item going on right now around Northern, that was even going on around Northern Pass.

Is there, the follow-up question I have then, is there anything in FERC Order 1000 that you saw that would allow you to avoid some of this legislative issues, possibly?

I don't think so.

All right. Thanks, Jim. And we have no other questions. So thank you, all, very much for joining us today. If you have anything else, please give us a call, and have a great afternoon.

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