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Eversource Energy (NYSE: ES ) Q2 2015 Earnings Conference Call July 31, 2015 09:00 ET Executives Jeff Kotkin – Vice President, Investor Relations Jim Judge – Executive Vice President and Chief Financial Officer Lee Olivier – Executive Vice President, Enterprise Energy Strategy & Business Development Jim Muntz – President, Transmission Phil Lembo – Vice President and Treasurer Jay Buth – Vice President and Controller John Moreira – Vice President, Financial Planning and Analysis Analysts Dan Eggers – Credit Suisse Julien Dumoulin-Smith – UBS Steven Berg – Morgan Stanley Travis Miller – Morningstar Shar Pourreza – Guggenheim Michael Lapides – Goldman Sachs Andrew Weisel – Macquarie Caroline Bone – Deutsche Bank Operator Welcome to the Eversource Energy Second Quarter Earnings Call. My name is Christina and I will be the operator for today’s call. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session. Please note that this conference is being recorded. I will now turn the call over to Mr. Jeff Kotkin. You may begin. Jeff Kotkin Thank you, Christina. Good morning and thank you for joining us. I am Jeff Kotkin, Eversource Energy’s Vice President of Investor Relations. Some of the statements made during this investor call maybe forward-looking as defined within the meaning of the Safe Harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on management’s current expectations and are subject to risk and uncertainty, which may cause the actual results to differ materially from forecasts and projections. Some of these factors are set forth in the news release issued yesterday. 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, 2014 and our quarterly report on Form 10-Q for the three months ended March 31, 2015. Additionally, our explanation of how and why we use certain non-GAAP measures is contained within our news release and the slides we posted last night on our website under Presentations and Webcasts and in our most recent 10-K and 10-Q. Speaking today will be Jim Judge, our Executive Vice President and CFO and Lee Olivier, our Executive Vice President for Enterprise Energy Strategy & Business Development. Also joining us today are Jim Muntz, President of our Transmission business; Phil Lembo, our Vice President and Treasurer; Jay Buth, our Vice President and Controller; and John Moreira, our Vice President of Financial Planning and Analysis. Now, I will turn over the call to Jim. Jim Judge Thank you, Jeff and thank you all for joining us this morning. Today, I will cover a strong second quarter financial results, which were in line with our guidance range for the full year. Our strong operating performance and update on several legislative and regulatory items and I will close with an update on certain transmission projects. Let’s start with Slide 4 and our financial results. Excluding merger-related costs, we earned $209.6 million, or $0.66 per share in the second quarter of 2015 compared with earnings of $131.9 million, or $0.42 per share in the second quarter of 2014. Over the first six months of 2015, we earned $466.9 million, or $1.47 per share, excluding those charges compared with earnings of $373.7 million, or $1.18 per share in the first half of 2014. These results strongly support our full year earnings projection of $2.75 to $2.90 per share as well as our targeted long-term annual earnings growth rate of 6% to 8%. Turning to Slide 5, a significant driver in the second quarter year-over-year earnings growth was the absence of a $0.10 charge we recorded in the second quarter of 2014, resulting from the initial decision from FERC on the allowed transmission ROEs for New England transmission owners. There was no similar charge this quarter plus we continue to realize the benefits of our continued investment in New England transmission reliability enhancements, which added $0.01 to earnings. As a result, our transmission earnings totaled $0.25 per share in the second quarter of 2015 compared with $0.14 per share in the second quarter of 2014. On the electric distribution side, higher retail revenues primarily due to last December’s Connecticut Light & Power distribution rate decision and a follow-on order from earlier this month involving accumulated deferred income taxes added $0.10 per share to earnings. I will discuss the July decision more fully in a moment. We continue to evidence good cost discipline as we have lower O&M – lower non-tracked O&M expense this quarter that reflects a decline in labor and labor-related costs and added $0.06 to earnings. I should point out that part of the large O&M decline this quarter, in fact, $22 million of the $56 million you will see in the income statement are costs that we don’t have any more as we sold our electrical contracting company early in the quarter. So, $70 million of annualized O&M will go away. There is really no real earnings per share impact as obviously the revenues will go away as well. Back to the reconciliation for the quarter. As expected, earnings were negatively affected by $0.06 due to higher property taxes, depreciation and amortization expense associated with storm cost recovery. Other factors impacting the quarter which include improved generation earnings and lower income taxes added another $0.03 per share. In terms of operations, our electric and natural gas delivery systems have performed well over the first half of the year. Our electric restoration metric, which represents the average number of months between interruptions, continues to track favorably as our reliability metrics are now consistently in the top quartile of our industry. Turning to our state legislatures, we had an active and successful spring. In Connecticut, Governor Malloy signed Public Act 15-107, which among other initiatives will allow electric distribution companies to sign long-term supply contracts with interstate natural gas pipelines. We will discuss the significance of that act shortly. Turning to Slide 6, in New Hampshire, the Senate and House overwhelmingly endorsed modifications to the state’s securitization statutes which are key to public service of the New Hampshire’s divestiture of its generating assets and recovery of those costs. The divestiture process has now moved to the New Hampshire Public Utilities Commission, where we filed a comprehensive restructuring and rate stabilization settlement agreement on June 10. That agreement was signed by a wide range of parties, including the Governor’s Office of Energy and Planning, two key state senators, senior New Hampshire PUC staff, the Office of Consumer Advocate, the IBEW local representing PSNH’s unionized workers and the Conservation Law Foundation among others. In addition to divestiture of PSNH’s 1,200 megawatts of generation, other terms of the agreement called for PSNH to defer a distribution rate case until at least mid 2017, the continuation of PSNH’s reliability enhancement program and the related cost tracker, foregoing $25 million of deferred equity return on the scrubber, and funding by Eversource shareholders of $5 million of clean energy initiatives. Parties to the settlement agreement have asked the New Hampshire PUC to rule on the agreement by December 31, 2015, which should allow the planned sale process to occur in 2016. As part of the agreement, the Commission’s review of Merrimack Station’s scrubber investment will end. We firmly believe that the agreement we filed will benefit all New Hampshire’s stakeholders over the long-term, which is why it is so widely supported. Turning from New Hampshire to Connecticut in Slide #7, on July 2, PURA approved a settlement we have reached with the authorities prosecutorial unit concerning the treatment of accumulated deferred income taxes in setting rate base in last December’s general rate case decision. The settlement restored approximately $165 million of distribution rate base and will add about $18 million of distribution revenues annually that’s retroactive to December 1, 2014. We recorded $11 million in the second quarter for the period of December 1, 2014 to June 30, 2015. In Massachusetts, we received two positive orders from state regulators relative to our plans to step up investment in our natural gas delivery system. The GPU approved a mechanism to recover investments related to the significant upgrade of our 3 billion cubic foot liquefied natural gas storage facility in Hopkinton, Massachusetts over the next several years. We expect to invest up to $200 million in that 40-year full facility, which is critical to helping NSTAR gas meet its winter supply obligations. Additionally, the DPU approved the first step in NSTAR Gas’ accelerated replacement of its cast iron and its untreated steel pipe over the next 20 years or 25 years. Those expenditures which were expected to rise to more than $60 million a year by the end of this decade will also be recovered through a distribution rate tracking mechanism. Later this year, we also expect to file a natural gas expansion plan to NSTAR Gas to comply with the state legislation that was approved last year. NSTAR Gas is our only distribution company where we have a rate case pending, hearings in that case were a base distribution rate increase request is approximately $23 million. Hearings were held in June and the decision is expected in the fourth quarter. New rates will take effect January 1, 2016. I would like to touch on energy rates for a moment. On July 1, the default energy rates at all four of our electric distribution companies dropped significantly from as high as $0.15 per kilowatt hour to between $0.0825 and $0.10 a kilowatt hour. This reduction, which is a pass-through for us mostly impacts our residential customers, the vast majority of whom have not moved to a third-party supplier and continue to buy their energy from us. While our customers will benefit from this decline through December, rates are very likely to rise again significantly in January when New England’s acute shortage of natural gas pipeline capacity will again pressure electricity prices. This see-sawing of energy rates is not healthy for our region’s economy and Lee will discuss in a moment the long-term initiatives that we have underway to resolve this dilemma. In Washington, hearings at FERC concluded this month on the second and third complaints filed regarding the return on equity earned by New England transmission owners. Earlier this year, FERC reaffirmed a base ROE of 10.57%, down from its previously allowed 11.14%. We believe that the 10.57% base is a reasonable level and booked reserves in the second quarter of last year and first quarter of this year, to reflect FERC’s final order. We are due to receive a FERC ALJ initial decision late this year and expect the commission order in the third quarter of 2016. Turning from regulatory issues to financing, we are pleased with the outcome of our annual rating agency reviews. On our first quarter earnings call I mentioned that the S&P had raised its corporate rating on Eversource and its subsidiaries from A- to A with a stable outlook. S&P also upgraded Eversource’s commercial paper rating to A1. Subsequent to that upgrade, Fitch raised the outlook for CL&P, PSNH and WMECO to positive and Moody’s raised its outlook for PSNH and WMECO to positive. We believe these actions speak loudly about how well we are operating the business and how many important regulatory items have been successfully resolved. Now turning to Slide 8, I will provide a brief update on some significant transmission projects. Our share of the Interstate Reliability Project which we are building in Northeastern Connecticut has finished major construction and the project was about 97% complete as of June 30. Right of way restoration remains and we expect the entire project in Connecticut, Rhode Island and Massachusetts to be in service later this year. We have now made three filings with the Connecticut Siting Council for projects included in the $350 million Greater Hartford seven [ph] solutions and all have now been improved with one already under construction. We continue to estimate that all Greater Hartford projects will be completed by the end of 2018. On this slide, we also highlight some additional transmission projects in New Hampshire that have been in our forecast and guidance. On July 21, we and National Grid filed a joint application within New Hampshire Site Evaluation Committee to build the Merrimack Valley Reliability project. Our share of the project would cost approximately $37 million. Separately we are going through the pre-filing process of the Seacoast Reliability Project, which is part of the New Hampshire 10-year reliability initiative we have been discussing with you for a few years. We are reviewing our $70 million cost estimate for the Seacoast project as we incorporate input from the towns that will host the project. These projects underscore the continued economic growth we see in New Hampshire and Eastern Massachusetts. Altogether, our capital expenditures totaled $771 million in the first six months of the year, $324 million of which was spent on our electric transmission system. We continue to project total CapEx of $1.85 billion this year to $740 million of which will be invested in transmission. That concludes my formal remarks. Now I will turn the call over to Lee. Lee Olivier Thanks Jim. I will provide you with a brief update on our major capital initiatives and then turn the call back to Jeff for Q&A. Let’s start with Northern Pass profiled on Slide 10. U.S. Department of Energy released its draft environmental impact statement on July 21. We have begun our review of the document and do not believe it poses any unanticipated challenges to the construction of the project. We were pleased that the draft EIS included that there would be a very low to low visual impact on our Northern sections of our preferred group. As expected, the DOE reviewed a number of alternative routes of the project in addition to our preferred configuration. We will carefully evaluate these alternatives. The considerable breadth of these alternatives should ensure that the project configuration ultimately approved by New Hampshire regulators will have been analyzed by the DOE. While the draft EIS is now released the DOE has scheduled hearings on the report for early October and asked for written comments by the end of October. Now that the DOE has issued its draft review, we expect to file with New Hampshire Site Evaluation Committee for our state siting approval in the early to mid-fall. The new state process requires a series of public meetings on the project at least 30 days before the application. So you should expect those meetings to be scheduled soon. Once we file our application to site evaluation committee, we will have up to two months to determine that the submittal is complete and then up to 12 months to rule on it. Our state application will incorporate feedback from the DOE’s draft EIS, as well as from the ongoing outreach in New Hampshire to ensure it is viewed favorably by a wide range of stakeholders. As part of our engagement with New Hampshire stakeholders, we announced on June 16, a new and unique partnership that will create significant opportunities for New Hampshire workers and businesses to participate in our upcoming transmission projects in the state. This would include Northern Pass and about that $800 million we expect to invest in other New Hampshire projects over the next 5 years some of which Jim has referenced earlier. The Jobs program focuses on three key areas of employment. They include a commitment to hire New Hampshire workers first, their commitment to New Hampshire-based construction related companies, many of them family-run to have an opportunity to bid on our projects a first of a kind training program to allow New Hampshire apprentices to be paid while training for high demand work on electric transmission construction. This effort has been coordinated with IBEW and our major electrical contractors. We look forward to the many of these New Hampshire residents and companies working in Northern Pass. The project continues to offer enormous benefits to the State of New Hampshire and to the region as a whole. We continue to estimate the cost of approximately $1.4 billion for Northern Pass, but that could change depending on the conditions related to the regulatory approvals. Turning to Slide 11, you can see that we expect to receive both state and federal siting approvals of the project in late 2016, commence construction around the end of 2016 and have the project substantially complete on both sides of the border by the end of 2018, with testing and entering into full commercial operation in the first half 2019. This schedule is similar to what I discussed with you in May. Turning to Slide 12, New England continues to make progress towards addressing significant energy challenges facing the region. One of these challenges is the need for new clean sources of power especially as we witnessed the ongoing retirement of older coal, oil and nuclear units. Northern Pass will provide some of that clean power, but other additional sources would be needed to meet the renewable energy and carbon reduction mandates New England and other states have enacted into law. In late February, the state of Massachusetts, Connecticut and Rhode Island jointly unveiled a draft solicitation for clean energy sources that will require new electric transmission to be built. The draft RFP asked for proposals for power purchase agreements as well as for the construction and transmission that would tap into clean energy. In late June, the final proposed RFPs were submitted to Massachusetts and Rhode Island through regulators for approvals. Connecticut legislation does not require that step. We expect that regulatory sign-ups on their RFP will occur over the next couple of months and the RFPs will be released to potential bidders shortly thereafter with bids due late this year. In Massachusetts, Governor Baker filed legislation on July 9 that calls on the state to purchase up to 18.9 million megawatt hours annually of clean hydroelectric power and other renewable energy. That equates to about 2,400 megawatts of capacity. We expect the legislature to take up the Governor’s bill this fall. But earlier this week, Governor Baker’s Energy Secretary, Matthew Beaton, said that the Governor has made the bill one of his priorities since without hydropower, the state will fall short of emissions reductions targeted by the state’s landmark 2008 Global Warming Solutions Act. In addition to taking steps to address its clean energy goals, New England has also made significant progress towards improving the availability of natural gas to fuel power generation during the winter. As I discussed on our first quarter conference call, New England and federal policymakers are very concerned about the shortage of natural gas capacity into the region during cold weather months, New England is challenged by a lack of gas pipeline capacity into a region, a shortage of natural gas storage and a heavy and growing dependence on natural gas generation. These constraints caused New England to suffer the three highest price months ever in New England for wholesale electricity prices in January and February of 2014 and February of this year. Further, natural gas prices in New England this past winter were almost doubled the national average even though we are located so close to the Marcellus gas fields. Without action the fuel constraints that we are seeing are driving skyrocketing prices will only continue and intensify. ISO New England recently stated that it expects 10% of the region’s generation fleet to retire by 2018 and possibly another 5,000 megawatts by 2020. These units will be oil and coal fire. More natural gas generation will take your place pressuring gas supplies and customer rates even further. The region’s policymakers recognized the severity of this challenge and are taking action. Turning to Slide 13, let’s start with Connecticut legislation as Jim mentioned earlier, on June 22, Governor Malloy signed Public Act 15-107. This bill provides clear authority for state regulators to allow electric distribution companies to sign long-term supply agreements with interstate natural gas pipelines. We expect the Department of Energy and Environmental Protection to solicit proposals later this year. In Massachusetts, Department of Public Utilities opened the docket in April to examine whether we could – whether it should consider allowing electric distribution companies to contract for interstate pipeline capacity. We, along with National Grid and the government’s Department of Energy Resources, strongly believe the DPU’s authority to approve such contracts is clear under state law. Initial comments were filed in June and reply comments in early July. Although the DPU has not set a timeline for the remainder of the investigation, we anticipate the DPU will issue its findings later this summer or early fall. In New Hampshire, the Public Utilities Commission opened its own docket in April to investigate the means by which electric distribution companies could ameliorate adverse wholesale electric market conditions caused by natural gas constraints. Stakeholders filed comments in June. Further, the PUC staff released its preliminary conclusions earlier this month that electric distribution companies have the necessary authority to contract the natural gas capacity. The PUC staff will provide a report to the Commission by September 15 of this year. In Maine, the Public Utilities Commission conducted an RFP late last year as part of its mandate to bring up to 200 million cubic feet a day of incremental natural gas capacity into the state. Access Northeast bid into that RFP and in May Central Maine Power filed with the Maine PUC recommending that it be allowed to contract with Access Northeast to bring in additional gas capacity. The consultant hired by the PUC analyzed the proposals, issued its report earlier this month including that Maine going it alone would not be justified. We believe this reinforces the need for a multi-state effort. All of these actions point to the increased recognition by policymakers that New England requires additional interstate pipeline capacity to ensure electric grid reliability and stable pricing. As we have said previously, we believe that the $3 billion Access Northeast project we are developing with Spectra Energy and National Grid is ideally suited to address New England’s natural gas infrastructure challenges since it would include upgrading Spectra’s existing pipelines in New England. Our project is unique, uniquely situated to deliver increased quantities of natural gas to the region’s newest and cleanest generators to inspect those pipelines and our alliance with Iroquois Pipeline connect us to directly to more than 70% of the region’s gas fire units. To remind you, Spectra and Eversource would each own 40% of the project and National Grid would own 20% of the project. The project’s open season ended May 1 and it received a strong response from both electric and natural gas distribution companies. The Access Northeast has commenced the process of negotiating long-term contracts with those distribution companies. We expect that pipeline customers will file those contracts with state regulators later this year with the goal of securing state regulatory approvals in 2016. With respect to sitting and citing and permitting, we plan to commence our FERC pre-filing later this year. This will facilitate a formal certificate filing at FERC in 2016. We expect to bring the pipeline into service for the winter of 2018/19 assuming expeditious approvals by federal and state authorities, because of the longer construction timeline for LNG facilities, we anticipate the storage element of the project will commence service after the pipeline. On July 27, we announced LNG, the LNG element of Access Northeast of public meeting in Acushnet, Massachusetts. That element involves the construction of 6.8 Bcf of LNG storage in Acushnet where Eversource currently operates an LNG facility. This LNG facility has been operated safely and reliably for nearly 45 years. The combination of the enhanced Spectra pipeline system and the additional domestic natural gas will allow us to ensure up to 5,000 megawatts of natural gas generation will remain online even during the coldest winter months. Now, I would like to turn the call back over to Jeff for Q&A. Jeff Kotkin Thank you, Lee. And I will turn the call back to Christina just to remind you how to enter questions. Christina? Question-and-Answer Session Operator Thank you. We will now begin the question-and-answer session. [Operator Instructions] I will now turn the call back to Jeff. Jeff Kotkin Thanks, Christina. Our first question this morning is from Dan Eggers from Credit Suisse. Good morning, Dan. Dan Eggers Hey, good morning. Just on the process right now, I guess for Access Northeast, you guys will pre-file this year. FERC will give you a response what time in 2016 and then when would you expect an official formal approval and then start actually spending money on construction under the timeline you laid out today? Lee Olivier In regards to the pre-filing, we will do the pre-filing approximately in the fourth quarter of this year. And then we will do the certificate filing somewhere between the third quarter and fourth quarter of next year. And clearly, at the beginning of this project the capital expenditures, our investments are very low. And what we are doing now was we are putting together the capital flows and cash flows for next year. And we will have a better sense of those later in the year most likely at our conference in the fall in November at EI conference. Dan Eggers So, we will look for the capital update, but probably no real dollars going to work until what, ‘17/18, is that realistic? Lee Olivier I think that’s a reasonable conclusion. Dan Eggers And from confidence, obviously the open season is showing interest, do you guys need to see more state approvals in some of these process you have pending before everybody is going to be onboard for signing firm agreements at this point? Lee Olivier Well, in the case of Connecticut, they don’t need commission approval. What’s happening there is the Department of Energy Environmental Protection are putting together a RFP process. They are in the midst of doing that. They will go out with an RFP. Massachusetts, we expect by late this summer, early fall, will have signed off on the RFP and it will be issued then. And essentially, once the RFP is issued, this is on electrics, once the RFP is issued, there is about 75 days that will be required to get your bid in. So we could expect bids in the fall and to choose the winners, of late this year, early next year. And on gas, it really is going to be, it’s a little bit different. The only state that wants to using RFP process is Connecticut. The other states right now have not really made the determination whether they want to follow that or just used the standard kind of LDC process where we will file the EDCs will file the President agreements with the regulatory bodies and that will kick off an approval process that could take anywhere from three months to six months. Dan Eggers So we shouldn’t see the bulk of these contracts somewhere around year end I guess then the gas utilities could be a little bit later but within the next six months to nine months we will know how firm and who is presumably going to take the capacity? Lee Olivier Yes. I think that’s a good estimate of the time six months to nine months is a good estimate. Dan Eggers Okay, very good. Thank you, guys. Jeff Kotkin Thanks Dan. Next question is from Julien Dumoulin-Smith from UBS. Good morning Julien. Julien Dumoulin-Smith Good morning. So the first quick follow-up on the last question there if you can. In regards to the procurement, as you are thinking about what’s contemplated obviously to early days for Connecticut and Massachusetts, will this ultimately be sufficient to get your projects off the ground, what’s the quantity contemplated at least as you are seeing the frameworks proposed between just the two states today to get your project and plus other projects off the ground, what’s the total volume, if you will? Lee Olivier Julien, this is Lee. You are referring to the gas side? Julien Dumoulin-Smith Yes indeed. Lee Olivier Yes. In the gas side, we expect to get something very, very close to the 900,000 decatherms per day. Julien Dumoulin-Smith Okay, great. And then second question, somewhat related going towards to the other side of the house on the transmission, as you look at the Massachusetts legislation, how do you think about that tying into the present RFP that you just discussed, would that ultimately be an upsizing or how would that ultimately get feathered together? Lee Olivier And this is in regards to the three state electric RFP and Governor Baker’s proposed legislation. Julien Dumoulin-Smith Exactly, how do you see those two working together? Lee Olivier Currently, without that legislation the Massachusetts really would be interested in this deliverability commitment model whereby you buy essentially – you pay for transmission and you get a supplier on the other end that will deliver electricity on an agreed upon, essentially capacity factor or numbers of megawatt hours over the course of the year. So that would be their option there. If the Governor Baker’s legislation passes, then you really have the full range inside of the free state RFP. You would have the deliverability model. You can do transmission with PPAs or they could do PPAs as well. So just in the full range of what the options are in the current RFP. Julien Dumoulin-Smith Great. Thank you. Jeff Kotkin Thank you, Julien. Our next question is from Steven Berg from Morgan Stanley. Good morning Steven. Steven Berg Good morning. Thanks for your time. I wanted to follow-up on Dan’s question just on the approval process and Lee you laid out sort of a 6 month to 9 month timeframe. On the gas side, could you give us some indication in terms of just key regulatory items we should be trying to follow throughout the course of the fall and through the winter time just so that we can better understand sort of the sequence or the key things we should be looking for there? Lee Olivier Yes. Clearly, a key thing is the RFP process in Connecticut that will be run by R&D, which we expect to take place this fall. It will be the signing of the precedent agreements by the EDCs and LDCs, because it’s both and the filing of those precedent agreements that will take place essentially late third quarter, early fourth quarter, it will be the approval by the Massachusetts DPU of the RFP process. So, those are the kinds of things that you can expect to see, not the approval of the RFP process, but the approval of the docket that allows the EDCs to purchase gas infrastructure. So, those are some, again I said the pre-filing will be late this year and you will hear – we will continue to do the further rollout of our Acushnet facility, our LNG facility in Acushnet and you will hear more about that. Steven Berg Okay, that’s very helpful. And just shifting gears over to just follow-up on what you have mentioned in Massachusetts with the Governor’s legislation proposal. It’s great that it sounds like it’s a key priority for the Governor. Could you just speak to for the proposal broadly, any your sense for, are there key elements of or sort of features that have drawn our position or is this something that is generally that you think broadly you have supported politically, how do you kind of think about the politics of it? Lee Olivier Well, look, Jim you may want to catch up that one a little bit. Jim Judge I mean, Steven, this is Jim. I would characterize it as similar to what we saw in Connecticut. Governor Malloy’s Connecticut energy strategy recognized that there are low-cost clean sources available in terms of Canadian Hydro that can help the state achieve its carbon reduction goals. I think the same mentality exists in Massachusetts among the policymakers. So, obviously its draft legislation at this stage would need to be approved on Beacon Hill and then signed by the Governor, but we think there is recognition that clean resources are available and within reach and we need to sort of be on with it in terms of enabling the commitments to be made. Steven Berg Great, thank you very much. Jeff Kotkin Thanks, Steven. Next question is from Travis Miller from Morningstar. Good morning, Travis. Travis Miller Good morning. Thank you. On the O&M cost side, if you take out that business that you guys divested there, how are you thinking in terms of tracking your O&M savings targets for the year, behind ahead, on track, so far this year? Jim Judge Yes, the guidance that we gave, Travis, for the year was O&M reductions of 2% to 3%. And when we adjust out the sale of that electric contracting business, I would say we are probably closer to 4% year-to-date. So, we are out little ahead of it. I would caveat that by saying that we do know that there is some timing in those numbers that we have gas and electrical maintenance plans that are lagging behind slightly. So, we will probably catch up on some of that. So, while we are ahead of plan year-to-date, I think the guidance continues to be 2% to 3% for the year that we are comfortable in giving. And that nets out obviously excluded the business that we have sold here in the second quarter. Travis Miller Okay. And then what was the full earnings impact, the bottom line impact from that business, if you include that revenue? Jim Judge It was relatively small fractions of $0.01. We have $2 million a year that order of magnitude. Travis Miller Okay, great. Thanks so much. Jeff Kotkin Thanks, Travis. Next question is from Shar Pourreza from Guggenheim. Good morning, Shar. Shar Pourreza Good morning. Just one question on Northern Pass, the Jobs program that was announced as well as the property tax payments reductions, can we just get a little bit of a sense on what formed the basis of those terms with this from feedback you received from constituents within the state and sort of – is this sort of the foundation for settlements? Lee Olivier Yes, Shar, this is Lee Olivier. We are not looking at this as a foundation for settlement, because we really believe that the process that’s in place now in New Hampshire is best lift through kind of a litigated process. We think ultimately out the other end it will have more integrity if it’s through the litigated process. Clearly, New Hampshire wants to understand, being the host, they want to understand the values of that line to New Hampshire from the standpoint and what does it do to lower electric cost to the extent that they can have a power purchase agreement, to the extent that it creates jobs both during the construction in permanent jobs, to the extent that there is other financial value to the state. And so this is after a lot of conversations with elected leaders, municipal officials and other key stakeholders in the region, including obviously, labor, the environment. And so what we will have when we announced the project will be a comprehensive value proposition that we will present to New Hampshire that will provide significant benefit in terms of jobs, revenues, tax revenues and other support for the state over a long period of time. So, we believe, coupled with the draft, EIS, coupled with our own outreach around the existing route and changes that we could make reasonably that the combination of all of those will have wide acceptance in the state when we file our application at the SEC in the early fall timeframe. Shar Pourreza Okay, got it. So, just one clarification, so the Jobs program and the property tax payments that was from conversations you have had with constituents within New Hampshire? Lee Olivier Yes. Well, the property tax payments will just be the standard mill rate on any given area. In other words, how much infrastructure is in a town, what’s the particular towns’ mill rate, what’s that infrastructure worth, what do we have on the books and they will be paid accordingly, very standard is how we do all of our other transmission. And then the other services provide will have been, if you will, discussed with the key stakeholders and we will reach a joint decision on those. Shar Pourreza Okay, perfect. And then just on Access Northeast, once you get the firm contracts, sometime I guess next year, is there a point where we can get closer as far as upsizing the pipe through laterals and compressors? And then just lastly on the storage project, is there any kind of a quantification of what that spending outlook could be? Lee Olivier On the latter one, the storage, that’s approximately $800 million of investment out of the $3 billion of the project investments, that’s about $800 million. And those are, our first cut up the number is that’s doing some engineering, heavy engineering consulting and understanding where the market is right now will mind for LNG. So, we think right now $800 million is a good number for 6.8 Bcf. And if you look at the project, the LNG would provide about 400,000 decatherms a day. The pipelines would provide around 500,000 decatherms. So, our project right now is approximately 1 Bcf and that’s the project that we will proceed with at this time. Shar Pourreza Great, thank you so much. Lee Olivier You are welcome. Jeff Kotkin Thanks, sir. Next question is from Michael Lapides from Goldman Sachs. Good morning, Mike. Michael Lapides Good morning, guys. Congrats on a good quarter. Two separate questions. The first one, you have two big projects, I mean, two really big projects, Northern Pass and Access Northeast. There are other market participants who are proposing new transmission down into New England, some of which with more underground routing than overhead. There is also one or two other parties, or consortium trying to get new major pipeline built. Can you talk for each of those two projects, the competitive positioning, the difference between your project recommendations and some of the others that are out there in the market? Lee Olivier Yes, sure. Michael, this is Lee. I think looking at Northern Pass, clearly, the entity or utility that has the most hydropower available in North America is Hydro-Québec. And they are the closest geographically to New England, have tie lines into New England currently. And they are partners and they are only working on one interconnection between Québec and New England and that’s ours. Okay. So, they are not working on any other interconnection into New England. So, they are our partner here in New England. So where that would lead you is to if you look at other hydro sources, they would be in the [indiscernible] region, those are small in nature. They are under development, could show up in the next 15 years from now, but they don’t provide any meaningful supply into New England during that period of time. So, from that standpoint, our project, you know what 1,200 megawatts and you look at big part of what’s driving Governor Baker and others, it’s all about carbon reduction. If you want to get a picture, 50%, 80% carbon reduction by 2015, you need a lot of energy that doesn’t produce carbon that runs around the clock. And clearly, that transmission project is the best one to go do that. There will be other projects that will be wind projects. Some of them may have run-of-the-river, firmed up by their wind with run-of-the-river firm and the wind up, but those are smaller projects in nature, the 400 to 500 megawatts. And then you are probably looking at some big wind projects, we will say farther up in places like Maine. You have all the issues of building large transmission infrastructure to correct relatively speaking small amounts of energy. When you look at the wind capacity factor of 35%, the intermittency of that probably doesn’t have the huge carbon impact when you consider what you are paying for. So, that’s kind what the competition looks like there. On the gas side, it’s real clear. We are building a project that interconnects with 70% of the region’s generators. It is using existing right of ways, existing LNG facilities. It will pick up both EDCs, LDCs. It has future potential expansion capability. The competition is building a pipeline that is designed around serving LDCs and is in an area where it’s very difficult to interact with a whole lot of that 70% of the generation I just talked about. So, we think from that standpoint, we think that project is very well-positioned. And we had a very successfully rollout of our LNG in Acushnet, Massachusetts earlier this week. Michael Lapides Got it. One follow-up easier question, when you are thinking about whether there is a new normal for gas utility, demand growth, especially at the residential and small commercial. How do you think about that and how different is that across your systems? Jim Judge Well, this is Jim. Long-term gas growth rate that we are assuming in our 5-year plan and the guidance that we have provided is 4%. Now, you may not get those growth numbers in other regions of the country, where gas penetration is more significant. We have a huge opportunity in Connecticut, as well as in Massachusetts in terms of converting customers to gas heat at their homes. In fact, we have got attractive mechanisms in Connecticut in terms of cost recovery for that. So, we are targeting about 11,000 conversions this year. In spite of the decline in oil prices, we are actually ahead of plan. I think we have signed up 4,800 in the first half of the year. So, we have got 2% plus growth just on new customers. And then obviously, the volume is likely to grow as well. So, we feel pretty confident about our 4% growth rate long-term. Again, I don’t know that I would apply that to other utilities or other regions of the country. Michael Lapides Got it. Thanks guys. Much appreciate it. Jeff Kotkin Thanks, Michael. Our next question is from Andrew Weisel from Macquarie. Good morning Andrew. Andrew Weisel Good morning. Two questions on Northern Pass. Jeff Kotkin Andrew could you just speak up a little bit? Andrew Weisel Sure. Sorry, two questions on Northern Pass, first with the RFPs that you described, given that this is an economic base project, do those really matter if the project succeeds in bidding those RFPs and if so would that affect your economics, Hydro- Québec’s or the rate payers? Lee Olivier I think – this is Lee, Andrew. I think the way we would answer that is there is this existing RFP process that’s been made available to all entrants. So obviously, we in HQ would enter this project into – to that process because to go forward independent of that would provide the others that would bid in and we are chosen to have the competitive advantage over Northern Pass. So I think it’s appropriate that this project, takes part in that RFP process. So and in that case as you know, in the three states there would be some load share spreading of that cost over those three states. And each state obviously will be different based upon the specific part of there – either RPS portfolio and our carbon reduction mandates that they have. So that would have to be determined by the three states as part of the RFP process. Andrew Weisel Okay. Thank you. The next question from me DOE’s draft EIS, the cost estimates of undergrounding look quite a bit lower than what you guys have talked about. The most expensive option they have is 4B at $2.1 billion to underground it, is there some disagreement in how they make that estimate, do you still think that it would be prohibitively expensive to underground it or in light of the DOE’s estimate, is that something that you might consider? Jim Judge The numbers that DOE used in their estimates was a direct cost. They didn’t use the fully loaded cost with AFUDC and financing. So they just used the direct cost that’s why their costs were different than our costs. Andrew Weisel So do you still consider – I am sorry continue. Jim Judge The cost that we use are costs that are current industry market costs either for underground that we do or have done and/or updates from our contractors. So we think our costs are pretty accurate. And I think the main difference with the DOE is they just used direct cost. Andrew Weisel Do you still see fully undergrounding as prohibitively expensive? Jim Judge Yes. We see underground – full undergrounding is a necessary, prohibitively expensive and a project – some project modifications could be done with some additional undergrounding that rates, essentially the issue raised inside of the DOE EIS. If you look at the DOE EIS and analyzes essentially three areas; the Northern area, the central area and the Southern are like the White Mountains National Forest. And all of the areas, if you look of the scenic impacts are all rated on the scale from zero to five. They are already either very low or low in terms of the scenic impact. Nevertheless, as a result of that outreach we have done, there is some additional undergrounding that can be done, that will make those numbers even lower without having to underground the entire project. Andrew Weisel Thank you very much. Jeff Kotkin Thank you, Andrew. Our next question is from Caroline Bone from Deutsche Bank. Good morning Caroline. Caroline Bone Good morning, just a minor question really because most of my questions have been asked, but is there anything that could cause you to book a reserve related to the pending second and third ROE complaints, would the ALJ decision be potential catalyst? Lee Olivier There is a potential that the ALJ decision comes on by year end, I think they are targeting in fact at the late December number. And obviously we will assess the merits of that recommendation, whether or not it warrants a reserve or not. So the timing is such that we do expect that ALJ decision at the end of this year. However, the final FERC ruling on it would be the third quarter of 2016. So we will have to look at the facts and circumstances of that order before we could tell you whether it is going to be reserved or not. Caroline Bone Alright. Thanks guys. Jeff Kotkin Alright. Thank you, Caroline. We have no more questions in the queue. So we just want to thank everybody for joining us. We know you have additional calls later this morning but if you have follow-up questions, please give us a call. Thank you very much. Jim Judge Thank you.