Eversource Energy (ES) — Q1 2015 Earnings Call Transcript

Thank you, Christine. Good morning, and thank you for joining us. I'm Jeff Kotkin, Eversource Energy's Vice President for Investor Relations. Some of the statements made during this investor call may be forward-looking as defined within the meaning of the Safe Harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on management's current expectations and are subject to risk and uncertainty, which may cause the actual results to differ materially from forecasts and projections. Some of these factors are set forth in the news release 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. 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. Speaking today will be Jim Judge, our Executive Vice President and CFO; and Lee Olivier, our Executive Vice President for Enterprise, Energy Strategy and Business Development. Also joining us today are Phil Lembo, our Vice President and Treasurer; Jay Buth, our Vice President and Controller; and John Moreira, our new Vice President of Financial Planning and Analysis. Now I will turn over the call to Jim.

Thank you, Jeff, and thank you all for joining us this morning. Today, I will cover our first quarter financial results, which were strong and in line with our guidance range for the full year. Our strong operating performance results for the quarter I'll cover as well; an update on several regulatory dockets, which are either pending or recently concluded; and I'll close with an update on certain transmission projects. Before I begin, I want to thank our shareholders who, at our annual meeting yesterday, overwhelmingly approved our legal name change from Northeast Utilities to Eversource Energy. We began trading under the ticker symbol ES on February 19, but our legal name change required the approval of holders of two-thirds of our shares, which we did receive yesterday. Eversource Energy is not only the legal name of our parent company, it is also the brand we're using with customers in each of the three states where we provide service. It will not be the legal name of our six regulated utility companies, so their debt and preferred stock will continue to be issued and trade under the names Connecticut Light & Power, NSTAR Electric, and our other four subsidiaries. Now turning to our financial results. Excluding merger-related charges, we earned $257.3 million or $0.81 per share in the first quarter of 2015 compared with earnings of $241.8 million or $0.76 per share in the first quarter of 2014. Overall, these results represent a strong start to the year and reinforce our confidence in our full year earnings projection of $2.75 to $2.90 per share as well as our long-term earnings growth rate of 6% to 8%. Key items affecting earnings include the various impacts of the severe winter we had in New England this year as well as a number of regulatory developments, particularly in Massachusetts and Washington. It's important to note that the net earnings impact of these regulatory orders was right in line with our expectations, so were included in our guidance. I'll start with the weather impacts. Heating degree days in the Boston area were 22% above normal in the first quarter of 2015 and nearly 10% above last year. As a result, our first quarter firm natural gas sales rose 8% compared to 2014's elevated levels and provided a benefit of $0.02 per share for the quarter. On the electric side, the cold weather did not have a significant impact as weather variations are becoming less of an earnings driver due to decoupling in some jurisdictions. At CL&P, we benefited from higher distribution revenues resulting from new rates that became effective December 1, 2014. This was the primary factor for the higher electric distribution revenues, which increased earnings by $0.07 per share for the quarter. Our regulatory settlement in Massachusetts resolving several open dockets added another $0.04 per share to electric revenues. I'll discuss this item in more detail shortly. Weather also had an impact on our operations and maintenance expense. Because of the frigid weather and heavy snow, particularly in Eastern Massachusetts, we needed to defer some of our distribution construction activities until later this year. As a result, more of our employees' time was spent on maintenance and restoration and less on capital projects. This caused non-tracked O&M to rise and resulted in a $0.03 per share year-over-year reduction to earnings. This is really just a timing issue, and over the course of the year, we expect O&M to be more favorable as we catch up on our capital work. The impact of another regulatory order in Massachusetts related to energy supply bad debt recovery more than offset all of that increased O&M in the quarter and added $0.05 per share to our results. Thus, on a net basis, O&M was a pickup of $0.02 per share. Transmission earnings were $0.03 lower in the current quarter compared to last year as a result of a regulatory order from FERC that I'll discuss in more detail in a moment. Other factors that reduced earnings as we had projected were higher depreciation and property tax expenses and increased amortization associated with storm costs, which, together, lowered first quarter 2015 earnings by $0.06 per share compared with the first quarter of the year ago. The most significant year-over-year change was the commencement of Connecticut Light & Power's amortization of 2011 and 2012 storm costs, which will average approximately $50 million a year through 2020. Lastly, all other operating items reduced earnings by $0.01 per share. This concludes my reconciliation of our first quarter results. We have had an active regulatory calendar during the first four months of 2015, and some of those developments impacted our earnings in the first quarter. In early March, the Massachusetts DPU approved a settlement that resolved a number of outstanding issues related primarily to NSTAR Electric's reliability program spending as well as loss-based revenues associated with energy efficiency programs. Under the settlement, NSTAR Electric and NSTAR Gas will refund $44.8 million to customers, and as noted earlier, had a positive impact on earnings for the quarter versus last year. Also in the first quarter, the DPU approved our recovery of approximately $25 million of energy-related bad debt costs from the period 2007 through 2014 that we had previously expensed. That lowered our bad debt expense in the quarter, and as I mentioned earlier, benefited us by $0.05 per share versus last year. The other significant regulatory order that had an impact on the quarter's earnings was the FERC's order on rehearing related to the ROE complaints against the New England transmission owners. This latest order had a number of good aspects. Despite complaints from certain parties that the approved rate was high, FERC commissioners unanimously affirmed the methodology it used to establish our base ROE of 10.57% and affirmed the high end of the zone of reasonableness at 11.74%. FERC also agreed to an October 2014 effective date of that order rather than a date much earlier in the year. The disappointing element of the order, though, was that FERC capped the ROE incentives on transmission investments so that no single project could earn more than 11.74% even if the project had been previously granted higher incentives. Because that decision to cap incentives dates back to October of 2011, we recognized an after-tax charge of $12.4 million or $0.04 per share in the quarter. That charge was the primary reason our transmission earnings declined by $8.9 million in the quarter or $0.03 per share. I should note that although FERC issued a decision on rehearing in the first complaint last month, there are other complaints pending over New England transmission returns. Those two complaints, which were filed 19 months apart, in late 2012 and mid-2014, have been combined for processing before the administrative law judge. Hearings are scheduled for June, and an initial decision from the ALJ is due by the end of the year. We would expect an order from the FERC commissioners in the second half of 2016. Regarding our operations. Despite the harsh and long winter, our electricity and natural gas delivery systems performed very well in the first quarter. In fact, our restoration metric is tracking favorably through the first quarter compared to a best-ever performance last year. For example, the average time to restore service to customers following a power outage has declined to 95.8 minutes this year versus 96.8 minutes last year. In addition to the regulatory developments at the Massachusetts DPU and FERC that affected our first quarter financial results, there were several other developments on the regulatory front during the quarter. In March, we announced that we had agreed on a process to begin the divestiture of Public Service of New Hampshire's 1,200 megawatts of generation. The agreement, in principle, was reflected in the term sheet that I signed, along with the President of PSNH, two leading state senators, two senior staff members of the New Hampshire PUC, the head of the Governor's Energy Office, and the State Consumer Advocate. We are now formalizing a formal settlement agreement authorizing the sale of the generation assets that we expect will be filed with the New Hampshire PUC next month. We expect to conduct the sales process throughout 2016. Our generation rate base currently totals about $650 million. Per the deal terms, any shortfall between the purchase price of the units and our total investment in them would be securitized. Securitization would dramatically reduce the carrying costs on any regulatory assets and provide significant savings for customers. We would expect that the sale of securitization debt will occur once the sale process is complete in either late 2016 or early 2017. The securitization statute in New Hampshire needs to be amended to allow costs associated with the divestiture to be securitized. The New Hampshire Senate already approved the necessary changes in late March, and the House of Representatives held a hearing on the Senate Bill earlier this week. The settlement includes several items in addition to the generation divestiture. PSNH agrees to forego a general distribution rate case until mid-2017. PSNH would forego $25 million of the equity return not yet recognized on our Merrimack Scrubber since October 2011. PSNH would fund $5 million of clean energy initiatives for New Hampshire, and we would be allowed full recovery of our scrubber investment beginning with a return effective January 1, 2016, then via securitization as a stranded cost post-divestiture. There were also regulatory developments for Yankee Gas. Yesterday, Connecticut regulators approved a settlement of two over-earnings dockets. As a result of the settlement, Yankee Gas will freeze natural gas distribution rates for at least one year and will establish an earnings sharing mechanism that will split Yankee Gas earnings above 9.5% equally between customers and shareholders going forward. The settlement also provides firm customers with a rate credit totaling $1.5 million next winter. We have recognized that credit in our first quarter results. The settlement also meets the requirements of the Connecticut statute that requires distribution rates to be reviewed every four years. That means that our next Yankee Gas rate review will be required by 2019 as we focus our attention on improving service, reducing costs, and expanding the Yankee system to more customers. I should note that the rate freeze does not impact additional revenues we will receive by expanding service to new neighborhoods and implementing the state's comprehensive energy strategy. Yesterday, we received the final decision from PURA approving the settlement with no exceptions. In other positive news, last week, Standard & Poor's rating agency upgraded Eversource Energy and our subsidiaries' corporate credit rating to A. With this A rating and stable outlook, S&P now rates Eversource Energy at the very top of its list of utility holding companies that comprise the EEI Index. S&P also upgraded the commercial paper rating on Eversource to A1. Now I'll provide a brief update on some significant transmission projects. Our share of the Interstate Reliability Project, which we are building in Northeastern Connecticut, is about 90% complete as of March 31, and we expect it to enter service late this year. Also, over the past two months, we have filed the first two of what will be several siting applications for our $350 million suite of Greater Hartford projects. The first of those two projects was approved two weeks ago, and we expect to begin work on that project this summer. Further north, ISO New England selected a new overhead transmission project between Londonderry, New Hampshire, and Tewksbury, Massachusetts, as a means to reinforce the grid in the Greater Boston area that we will jointly build with National Grid. ISO New England selected our project rather than an alternative undersea project from Seabrook, New Hampshire, into Boston. Later this year, we will file for New Hampshire siting approval for this project that was assumed in our forecast. That concludes my formal remarks. Now I'll turn over the call to Lee.

Thank you, Jim. I will provide you with a brief update on our major capital initiatives and then turn the call back over to Jeff for Q&A. Let's start with what we saw in the New England power markets this winter. Even though spot market wholesale energy prices were lower this past winter than they were in the first quarter of 2014, retail energy prices increased 40% to 50%. This increase was driven by the volatility of last winter and market forces pushing wintertime supply risk onto residential and business consumers. Even with lower wholesale electricity prices this past winter, we don't expect that risk premium to go away. First, you have to look at the reasons behind this winter's decline, which start with lower worldwide oil prices; lower oil prices reduce the cost of buying fuel for the region's oil-fired generation; lower worldwide oil prices also caused liquefied natural gas to become cheaper and more plentiful in New England. But all of the structural problems remain in New England. Despite the higher LNG imports, reliance on our older coal and oil units increased over the course of this winter. During peak days in February, these older coal and oil units supplied more than 40% of New England's power needs. During the evening peak on February 15, oil alone accounted for 30% of New England's generation mix, while natural gas only accounted for 17%. Last summer, by contrast, natural gas had accounted for more than 50% of New England's generation mix. This factor caused New England wholesale electricity prices to average $126.70 per megawatt hour in February, the third highest cost on record behind only January and February of last year. And some of the oil and coal units on which we depended upon this winter will soon be retired. Approximately 1,800 megawatts of coal and oil generation at Brayton Point in Massachusetts and Bridgeport Harbor in Connecticut are scheduled to retire in about two years; this, in addition to the 1,400 megawatts of coal, oil, and nuclear generation that retired last year. That generation will likely be replaced by gas-fired generation, but we still don't have an approved plan to add significant new gas transmission infrastructure to the region. As demand for natural gas for heating continues to rise, less will be available for generators during the winter season. Come late spring and summer, most fixed energy rates will drop significantly since heating loads will disappear. But electricity prices will rise next winter as a result of our risk premium that is built into New England's wintertime electricity prices and the reliance on imported LNG. This seesawing of generation rates is frustrating for consumers since we are so close to abundant and low-cost natural gas in the Marcellus Shale region. But the problem is not supply of natural gas. It is not having sufficient pipeline capacity to transport that gas into New England during the winter months. Fortunately, we believe that the region's policymakers understand that New England needs more low-cost Marcellus gas to ensure reliability, wintertime price stability, and the region's competitiveness. The New England Governors and top energy policymakers met in Hartford last week to continue to plan a coordinated effort to resolve our infrastructure challenges and to lower costs for our customers. In Massachusetts, earlier this month, Governor Baker's Department of Energy Resources requested that the DPU open a docket on the means by which electric distribution companies can contract for pipeline capacity for the benefit of electric customers. The DPU subsequently opened a docket to address that issue. In Connecticut, the legislature Energy and Technology Committee considered and forwarded for action Senate Bill 1078. This bill contains the priorities of the Connecticut Department of Energy and Environmental Protection. It seeks to provide the agency with regulatory tools to procure affordable and reliable electricity for the expansion of natural gas capacity and procurement of additional renewable sources of energy on behalf of the state. A component of that legislation clarifies the ability of electric distribution companies to seek recovery of costs through an electric tariff that is related to purchasing new gas pipeline infrastructure. In New Hampshire, the Public Utility Commission wrote to FERC in March stating that New England continues to have a high winter electricity price problem that can be addressed economically only through the addition of new gas pipeline capacity. The New Hampshire PUC subsequently opened its own docket into approaches to ameliorate adverse effects of the wholesale electric market conditions. This docket will examine the gas resource constraints affecting New Hampshire electric distribution companies and electricity consumers. The New Hampshire PUC staff will provide a report to the commission by September 15 of this year. It is not only government energy agencies that are raising an alarm. On April 1, the Associated Industries of Massachusetts, the Connecticut Business and Industry Association, the Business and Industry Association of New Hampshire, and the Maine State Chamber of Commerce jointly wrote a letter to their four respective Governors urging them to take steps to reduce the cost of electricity and energy in the region. They wrote, and I quote, 'New England policymakers, led by its Governors, need to cooperate during this crisis and allow for the development of energy infrastructure projects as expeditiously as possible while working through local concerns.' All of these actions point to the need to construct additional pipeline capacity into New England that not only satisfies the increased use of natural gas as a heating source but also as a power generation fuel. As we have said previously, we believe that our $3 billion Access Northeast project we are developing jointly with Spectra and National Grid would be ideal to address our natural gas infrastructure challenges since it would involve upgrading Spectra's existing pipelines in New England. Our project is uniquely situated to deliver increased quantities of natural gas, the region's newest and cleanest fossil generators, since the Spectra pipelines and their alliance with Iroquois pipeline connect to more than 70% of the region's gas-fired units. To remind you, Spectra and Eversource would each own 40% of the project, and National Grid would own 20%. The open season for the project ends tomorrow. And once we see which parties bid for the project's capacity, we will move to signing binding contracts and then bring those contracts before state regulators. We expect to file our preliminary application with FERC later this year and our formal siting application with FERC in 2016. The schedule would allow for the pipeline to be approved in 2017 and constructed in time for the winter of 2018-2019, assuming the approvals are moved expeditiously. Turning to Northern Pass. The U.S. Department of Energy indicates it will release its draft Environmental Impact Statement in the June, July timeframe. Once that draft is released, the DOE will solicit both written and oral comments on its findings before the report is finalized. Assuming the draft is issued in the June or July timeframe, we expect to file our state application with the New Hampshire Site Evaluation Committee late this summer. The committee will have up to two months to determine that the application is complete and then up to 12 months to rule on it. We continue to engage various constituencies in New Hampshire, including the neighbors of the proposed 187-mile road, to understand their concerns and try to address them. These conversations have been constructive, and we continue to believe that our application to the Site Evaluation Committee will be viewed favorably by a range of stakeholders. We are encouraged to see that the business leaders in New Hampshire are calling for solutions to the region's significant energy challenges and believe there is a growing momentum around the Northern Pass project. In the New Hampshire legislature, there were two bills proposed that would have hurt the project, but neither one moved forward. One was retained in committee and won't be acted on this year. The other was soundly defeated outright. Moreover, we have expanded the benefits that Northern Pass will provide to New Hampshire. In March, we announced a new conservation partnership with the National Fish and Wildlife Foundation dedicated to restoring and sustaining healthy forests and rivers in New Hampshire. Northern Pass has committed $3 million over the next two years to this effort, and this amount will typically be doubled by working with the foundation to leverage additional federal and private funding. In the north country of New Hampshire, we have provided funding for a new broadband and cell service initiative and provided the initial seed money for a job-creation fund, which is part of our overall $7.5 million commitment in this particular area. We expect to receive both state and federal approvals in 2016, commence construction in the second half of 2016, and have the project substantially complete on both sides of the border by the end of 2018, with testing and entry into full commercial operation in the first half of 2019. We have moved the in-service date into 2019 because of the later date for receipt of the draft EIS and the need to perform final testing on the line during lower load months of the year. Because of high loads in both Québec and New England from December through early March, we anticipate all testing to be complete and full operation taking place in the April, May timeframe. From an earnings standpoint, though, I would emphasize that we will continue to earn AFUDC on our equity investment in Northern Pass during this period of the contractual ROE prior to the in-service date. We continue to estimate the cost of approximately $1.4 billion for Northern Pass. And that could change depending on conditions related to the regulatory approvals. This project continues to offer enormous benefits to the state of New Hampshire and to the region as a whole. New England continues to focus on its need for new clean energy sources and power to replace the older coal, oil, and nuclear generation units that continue to retire. In late February, the states of Massachusetts, Connecticut, and Rhode Island jointly unveiled a draft for a solicitation for clean power sources that would likely need new transmission to be connected to the grid. They include cost of RFPs for power purchase agreements as well as for the construction of transmission that would tap into clean energy. The schedule remains in draft, but we believe that the final RFP will be issued late in the second quarter, with responses due late in the third quarter. That would allow contracts to be signed by year-end and subject to regulatory reviews next year. We believe we will be well positioned in an RFP process to build transmission that connects significant clean energy sources to the region. We do have other potential projects besides Northern Pass that we may fit into the RFP as well, and we will make those public at an appropriate time. Now I'd like to turn the call back over to Jeff.

Thank you, Lee. And I'm going to return the call to Christine just to remind you how to answer questions. Christine?

Thank you, Christine. Our first question this morning is from Julien Dumoulin-Smith from UBS.

So perhaps a first quick question, and taking off on the last comment you all made there, if I can ask. Can you elaborate a little bit about other potential projects? I know you said specifically you would provide some more information later. But is the prospect of this being an alternative to Northern Pass? Or how do you think about that as a parallel or alternative to Northern Pass as you see this RFP process moving forward?

Julien, this is Lee Olivier. I don't see them being an alternative for Northern Pass, chiefly because the fact that Northern Pass is essentially hydropower, it's firm, it's fixed, it's large, it has a very high-capacity factor, HVAC lines usually operate in the high 90%. I don't see it as these other sources as an alternative to it because those other sources would be a combination of wind and, in some cases, wind with a mixture of run-of-the-river hydro. So they wouldn't have capacity factor. They wouldn't have kind of the certainty that you would have with Northern Pass. However, by their nature, the wind certainly is Class 1 renewables, highly desirable, and there is an opportunity to tap into wind resources in Northern New England and in New York as well, and potentially, over time, in the Maritime Provinces. So there's a lot of potential, but all of that -- or most of that wind would require additional transmission to interconnect into. But I don't see it as a substitute for Northern Pass.

Excellent. And so to that extent do you have any sense on, at least under the RFP terms, what the timeline would be and ultimately any sense of magnitude of potential spend on that front? I know, obviously, it's very early days, but perhaps I can continue to harp on that.

Yes. Right now, we would expect to have the draft out by the end of the second quarter of the RFP. And we could expect bids due sometime probably, I'm guessing, around the late August, September timeframe, and contracts awarded by the end of this year, early next year and approval sometime in 2016. And in terms of the total cost that the states are willing to spend on either power purchase agreements for clean or Class 1 energy or infrastructure, that's really not been determined yet. And I think what will happen there is that the states will put the RFP out. They will get bids in. They will evaluate the bids, and they'll evaluate them from a number of standpoints, obviously, cost, sitability, the amount of Class 1 energy that they can bring, the amount of firm fixed energy, the times of the day that would be there, and then they'll make a decision on how much money they want to spend at that period of time.

But do you ultimately see your involvement in bringing some of that Class 1 wind down into your respective service territories? Is that kind of a ballpark?

We do. We do. We see that, in fact, as a big part of our future. And even once you achieve the common goals of approximately 20% renewable portfolio in the region, as everyone knows that number goes down to — the carbon reductions go down to 80% reduction, and the renewables continue to go up over a period of time. So we see more Class 1 renewables, wind, and other interconnections to either Northern New England or Canada.

And sorry, the first question was kind of a focus on the last comment you made. Bigger picture question here. In terms of the open season, can you comment on the progress and the interest across a variety of parties you're talking to?

Yes, this is Access Northeast, Julien.

Yes, exactly.

Yes, yes. I would say the interest has been very, very high. And as you know with — between Eversource and National Grid, there is approximately 70% of the EDC customers in the region that have agreed to go forward with the project. And then there are a number of other EDCs that we are having conversations with now. EDCs, in some cases LDCs. We are having conversations with some generators with expressions of interest around the line to interconnect into the line. So I would say that the open season has gone very, very well for us.

Next question is from Dan Eggers from Crédit Suisse.

Lee, just on Julien's line of questioning on this — on the New England transmission and clean energy projects. Are they targeting a certain number of megawatts or anything about firm capacity, trying to set a boundary as to where they — for the threshold? Or is it an option where they're going to take all bids that could qualify and then decide some balance of size and cost as they deem prudent?

I really think it's more of the latter. I mean, each of these states has quantities for Class 1 renewable. And Connecticut can go up to about approximately 200, 250 megawatts of hydro. That's built into their statute. But I think more what they're likely to do is they want to get the bids in, and they go through a comprehensive analysis of really the value of the bids. In other words, can these projects get built? Is there a counterparty on the other end of the transmission line? What are the capacity factors? What is the total contribution to RPS portfolio? The total contribution to carbon reduction? Are these resources available during the most challenging periods of the year, which, in the case of New England, is the fall, winter months? And they're going to evaluate those against those and other criteria that's very similar, and then they're going to look at where do they want to put their money.

Okay, got it. And then I guess just on the kind of the FERC decision to allow generators to procure your subsidized fuel purchases in advance kind of in this interim period. Is there a limit in the region where you guys run into an environmental compliance or performance standards at the state or federal level as oil takes presumably more share?

Yes. There is limits on all of these old units that burn oil. They are limited to either so many tons or so many days of operation. Each state is a little bit different. Now obviously, if it ran up against whether you keep the lights on or off, I'm sure each of the operators, including ourselves, would seek relief on that. But there are limits to how much carbon that you can put. But it's different by state.

So is carbon the limitation? Or is it kind of like a NOx, SOx particulate issue?

Well, it's more NOx, SOx, but as you know, it directly leads to carbon as well. And the direction of the region is to move to clean energy sources. And as you've heard by my comments, during peak days in February, 40% of all of the energy we were producing was either from coal or oil. So clearly, the policymakers want to move in the opposite direction.

Okay. And then I guess I'm trying to balance out for the quarter how much weather helped versus normal you guys had. Obviously, continued decoupling of CL&P has reduced that amount of exposure. But is the total balance just going to be the $0.02 you guys saw in the gas utility side and then some savings in the O&M? Or where should we calibrate a proper weather-normalized number?

I think the incident is probably about $0.03. We did have sort of a significant increase in gas sales for the quarter, and 20% higher heating degree days really drove that. So approximately $0.03 versus normal.

Okay. So even adjusting for the O&M and kind of the rebalancing of more O&M this quarter because you couldn't do capital, the $0.03 is the good starting point?

It is.

Next question is from Greg Gordon from Evercore.

Most of my questions have been answered. Can you just go through the — though, what you think the base case is for the timing of getting fully through the Massachusetts — sorry, the New Hampshire process, when you'll have sort of the capital return to you from the sale of that asset when you get the securitization bonds and then what the use of proceeds would most likely be and over what time frame?

Sure. Greg, this is Jim. We will be filing the settlement, comprehensive settlement. We have an agreement in principle with those state parties that I mentioned. We'll be filing it in May, hopefully, by mid-May. We expect most of 2015 to be spent at the PUC up there reviewing the settlement. We do have a broad-based coalition in support of it. So we are optimistic the settlement will be approved. Also this year, the securitization legislation is progressing, and we expect that to be approved by the House and then signed by the Governor in the summer. So that puts us into 2016. I think 2016 will be the period where we will actually execute the divestiture and anticipate the awarding of the winning bids in late '16. We will then securitize whatever is not recovered in that transaction. And the use of those proceeds will be applied to future transmission projects to the extent that they appear, and we could use the cash to support that. Or it would be a return of capital, and we would also consider a potential, not only buy-down of debt but share buybacks as well if there wasn't a better use of those proceeds.

Great. So the earnings power of those assets really runs through, for all intents and purposes, the end of fiscal year '16? Should we think about that?

It does. In fact, there's an increase because January of 2016, the full scrubber will be in rates, whereas right now, only about two-thirds of the scrubber is in rates.

Great. And then you get that capital returned to you sort of on or around year-end '16, first quarter '17, and then redeploy that capital accordingly?

That's correct.

Our next question is from Travis Miller from Morningstar.

I was wondering now that oil prices we've had down low for quite a while, even to the extent that a lot of people are forecasting low forever, what has that done to your switching estimates in terms of customers switching from fuel oil to natural gas? Are those — have your revised any of those? Are you seeing any kind of change there in terms of willingness and economics to switch?

Well, there's no question that sort of the reduction in oil prices sort of reduces the benefit of the conversions. But what I can tell you is that the target that we had in 2013 was about 9,000 customers, and we got 10,000. I think we had a target last year of 10,000 that we got about 10,600. So we've been exceeding targets. And we're pleasantly surprised to see that our target for the first quarter of this year that we had budgeted about 1,800 conversions, and we actually finished the quarter at 2,050. No question, the economics were impacted. Previously, it was a four-year payback for a resident to recover the cost of the furnace conversion. And now maybe it's increased by a year or two in terms of the payback. But thus far, we've been pleasantly surprised at the volume of conversions we've been able to achieve.

Good. That's great. And then the political support continues to be behind the conversion as well?

That's correct. Not only political support, but there's new cost recovery mechanisms in place. In Connecticut and in Massachusetts, they're considering doing the same thing.

Next question is from Andrew Weisel from Macquarie.

First question on Access Northeast. After the conference of governors last week, do you have a sense of how quickly politicians and regulators might actually tweak the rules, specifically in Connecticut and Massachusetts? And then the second part of that question, is how likely is it that all six states will participate? And does that even matter if Connecticut and Massachusetts are able to approve the project?

Yes. Andrew, this Lee. Your first question was it the timing issue of how quickly will they move?

Yes.

Yes, I think they will move very quickly. As you know, there's dockets open in New Hampshire and Massachusetts. And Connecticut is pushing this bill through. So they're doing this, clearly, with the intent of trying to head off the problems that we see in the horizon with generation with Brayton Point, as an example, and Bridgeport Harbor returns. So there's a strong sense that we need to get a pipeline upgrade in service by the winter of 2018, '19. So I would see that there would be a very timely movement forward on this thing. I would say that we — the project by the middle of this year will have in front of the EDCs, and I would believe the EDCs will have Access Northeast in front of regulators by the middle of this year. And assuming legislation passes in Connecticut, we don't need other legislation in the region, and the PUCs would be set up to make a decision by the end of this year on the project. In regards to all of the states, clearly, Maine is already out with a solicitation for 200,000 dekatherms. I attended the Northeast Conference of Governors last week, and Governor LePage co-hosted the meeting, along with Governor Malloy. And he and his Energy Secretary, Patrick Woodcock, are very aggressive around getting this to action. And that's their statements. No more talk, we need action. And I would say it's equally with the Secretaries of Energy in Massachusetts and in Connecticut. And certainly, with the fact that New Hampshire has opened up its own docket investigating the wholesale supply issues in terms of pricing in New Hampshire, said that they are going to move very quickly. And Rhode Island is already there. So it's likely — it could be all six states, but it's more likely a five out of the six that will move forward in support of upgrades of gas infrastructure.

Great, very helpful. Then on Northern Pass, it looks like you filed an entry into the ISO's electric transmission upgrades queue for a 1,090-megawatt line. Can you talk about what that is, why you added it? And is that an alternative or a tweak to Northern Pass?

Yes. It's really — what it does, it provides us an option. Clearly, in the DOE EIS study, they're studying a number of ranges around the project, modifications to the projects, the different routes on the project, and potentially some additional undergrounding in the project. And basically, this option to go with the 1,090 would suggest using a different technology. And it's just an option. Our preferred route, our stated route is this 1,200-megawatt, 187-mile route as we've laid it out to the DOE. But we want to make sure that we have alternatives that could be approved through the ISO I39 process that would support the DOE outcome, whatever that may be.

Makes sense. Then lastly, appreciate the clarity on the next rate cases for a bunch of your subsidiaries. Just to clarify, after the NSTAR Gas case is done, when would be the next rate case that you'll file?

Obviously, Andrew, we'll decide that going forward. We're not obligated to file any rate cases after this NSTAR Gas one until 2017. I think in 2017, Connecticut Light & Power is expected to file another case and NSTAR Electric would likely as well. But until then, we're in control of our own destiny in terms of filing a case if we feel it's necessary and appropriate.

Next question is from Shar Pourreza from Guggenheim.

Most of my questions were answered. But just one, on the PSNH generation sale, can you just remind us sort of what you're under-earning on those assets and whether we could see that capital deployed at a relatively quicker pace upon the sale? So some accretive opportunities?

Sure. Shar, we've been earning approximately 8.5%. And the primary reason for that is that some of the scrubber costs have not been allowed into rates. The stipulated return on equity for generation is 9.81%. So we expect to be — see earning more beginning in January of '16 when the full scrubber is included in rates. And as I said, the proceeds of the transaction, late '16, late '17, in terms of the sale and the securitization of the balance, we will look at what our best investment opportunities are at the time. And we do come up with projects periodically that — transmission projects or what have you that could use that funding. Or as I said, we would certainly entertain as an alternative paying down capital, both in the form of debt capital as well as share buybacks. So we will assess the best use of those proceeds 1.5 years from now.

Got it. And then just on Access Northeast. Given Eversource and National Grid's, obviously, takeaway capacity as well as EDC and LDC interest, is there an opportunity given the stage that we're at now to look to upside that sort of a little bit over a B a day?

Yes. This is Lee Olivier. There is an opportunity. One of the — I think the aspects of our project is that it's, if you will, kind of like a just-in-time project. It's scalable. So we're talking about a Bcf today, and that's a combination of pipeline and LNG storage, which will be crucial for the region. But both our pipeline, the Spectra pipeline, the Algonquin, can be upgraded over time. So it can be scalable over time, along with LNG storage up to over 2 Bcf. But the beauty of this project is you build for what you need versus building a large pipeline that for eight months out of the year has a very low utilization. We'll have a very high utilization on this initiative.

Our next question is from Paul Patterson from Glenrock.

Just as sort of follow-up on Andrew's questions on this — I just want to make sure I understand. With the Massachusetts DPU — this is with the Access Northeast, with the Massachusetts DPU and the Connecticut legislature, what is the time frame they have to act, I guess, in these cases or legislation in the case of Connecticut vis-à-vis the FERC process, if you follow me? I mean, is there any sort of controlling factor here that we should be thinking about?

Yes. I think, realistically, we need a decision in the fourth quarter this year from, we'll say, the PUCs on the selection of Access Northeast if, indeed, we want to have the pipeline portion of the project in service by the winter of 2018, '19. And the pipeline piece is, it's about 0.5 Bcf. So we need decisions approximately by the end of this year. We will do a FERC pre-filing of the project either late in the third quarter, early in the fourth quarter, and then file the full filing in 2016, the middle of 2016. So the timing is that we'll work on getting the precedent agreements signed by the end of June. We will get those before the PUCs in the third quarter, and we need the decision in the fourth quarter because we really want to file our pre-filing with FERC, like I say, late in the third, early in the fourth quarter.

Okay. Great. And how much of this would you say is — of the open season is likely to go, just roughly speaking, to EDCs versus traditional — more traditional sort of gas customers?

I would think the majority of this will go to EDCs with the potential of — obviously, we will have some LDC load as well. And then there are some generators that we're in conversations with that we'd like to take gas from it. They don't know if they want to do a long-term contract or do they just want to build a lateral into it. So they build a lateral in. It's like a generator and a connection. They pay for that lateral. But then they have x amount of output, some of which could be very large that they would have available to their plants over the long term, but they would just buy off -- they would buy off the market through that lateral off of Access Northeast. That's probably more likely in that scenario.

Okay, great. And then with Northern Pass, the — I just wanted to sort of understand, I mean, you guys mentioned the testing and everything that might be happening. When do you think Northern Pass capacity would be available? Do you think it could be available for the Forward Capacity Auction #10? Just wanting to make sure that I sort of — when Northern Pass might actually be able to be actually entering into the capacity market in New England or...

Yes, I think it's probably more in the 2020 timeframe.

Okay, great. And then just finally, you mentioned LePage, and I have to -- he mentioned recently, and I know it's not your service territory, but has there been any -- he's recently mentioned about utilities actually owning renewable resources. And I was wondering if that's something that you're hearing among other states as well potentially? Or is that just him?

I have not heard that is a theme among any of the other states that we do business in.

Next question is from Michael Lapides from Goldman Sachs.

Jim, real quick question. Just the $12.4 million after-tax charge related to the FERC ROE decision, what line item does that impact? And you've left that, and you've done this previously in historicals in ongoing earnings. When should we start backing that out, like will that be a nonrecurring event beginning this quarter next year? Or will it start earlier than that sometime in the next couple of quarters?

It's in the revenue line, Michael. And it probably has about a $0.01 drag on earnings going forward on an annual basis. We had several items, as I talked about, in this quarter. The FERC ROE final decision. We had the bad debt remand in Massachusetts as well as the comprehensive settlement of 11 dockets in Massachusetts that were open. The net of all of those was basically a push. In other words, we had planned on all three taking place. Some came in higher than we expected. Some came in lower than we expected. But these are sort of — this is our core bread and butter, right. We're probably among the most purist T&D regulated utilities. So when we get a rate order like this any more than when we got the FERC order last year, we took it to recurring earnings. That's the case here. We don't think anything here should be sort of cut out as a one-time nonrecurring item. It's traditional rate making, which is the business that we're in.

Got it. But when I think about, let's say, the rest of this year, if you've already had a couple of quarters of taking some of the FERC ROE charges, that ramps down during the course of this year. I'm just trying to true things up to what a normalized would be after 2015.

Yes. The 10.57% is what we're assuming going forward is the rate. We still do have two dockets open to complaints, as you know. But we do anticipate that, that's going to be -- expected to be within the range of reasonableness, and that will be the rate set going forward. This limitation or clarification that the FERC has made on the ROE cap is about $0.01 hit from what we had anticipated previously.

Got it. And then last question. The discussion about potential legislation in Massachusetts, similar to the one in Connecticut for conversions, can you just need legislation for that? Can that be accomplished via regulation without having to get the state assembly involved? And if so, what's the timeline or kind of the process you think that takes?

We already have the legislation in Massachusetts. It would be up to the PUC, the Department of Public Utilities in Massachusetts, to pursue a similar program to what we are doing in Connecticut.

Got it. They have the legislation, they just need to enact enabling regulation to put it into place?

They do.

Next question is from Stephen Byrd from Morgan Stanley.

Just had one question, just on Access Northeast. There's a competitor project as well. When you look out at total demand and think about the prospects, do you see a potential really for there being enough demand for both projects to move forward? How do you think about kind of aggregate demand and how these projects would fit into that picture?

Yes. I guess the way I look at that — this is Lee Olivier, is that you've got a problem for like four months out of the year, and that problem will grow as these older oil and coal-fired power plants shut down over time. So that the winter problem will continue to grow. And so you will continue to need more supply in that four-month period of time. So essentially, the November through end of March period of time. The remainder of the year, there would potentially be the two major pipelines will be a glut of gas. You're probably not going to have very good utilization in these assets. And so our view is you need assets that are scaled and designed around what the problem is, which is why we think this is a very good solution for New England. And even with our line, clearly, the demand would be very, very high in the winter period of time. But there would be lots of gas at very low prices, very low differential prices from the Marcellus area in New England during the peak periods of the summer and also, of course, the shoulder periods of spring and fall. So we think it's — we just can't think of a rationale to build two very, very large projects at this point in time.

Understood. So if I'm following that, it's really the issue of major overcapacity during the non-peak demand periods that would cause utilization to kind of be an issue if you had both move forward?

Yes. And do you want to pay for that? Do you want to pay for a lot of capacity that sits idle or partially idle for eight months out of the year?

The next question is from Caroline Bone from Deutsche Bank.

I'd like to just follow up on an earlier question, that I think it was Paul had asked, on Access Northeast. Lee, I think you said that you'd only expect to have 0.5 B of capacity in service by 2018. Is that what you guys had originally contemplated? And would that 0.5 B of capacity cost $3 billion?

No, what we contemplated in this project is having 1 Bcf, approximately 1 Bcf, between 2018, 2019, with 2018 pipelines coming in service and the 2019 LNG coming in service. And what we would do is we would look at bridging contracts in between those with existing LNG facilities. But if you look at the $3 billion contract, not all of that was geared towards the EDCs. There's approximately $600 million to $700 million of that, that was geared towards interconnecting LDCs as well.

So that spending will take place just now in the pipeline at the same kind of time in parallel to the construction or the expansion of the pipeline?

It will actually happen in — all in a similar timeline.

Okay, great. And then just one follow-up on Northern Pass. Can you just help us better understand what the delay might mean for your capital plans, if anything really significant?

There isn't really any major shift. The spending will be largely incurred through 2018 absent the fact that the testing is going to have to delay until we get to the winter period. But we have — we provided CapEx guidance for our transmission projects, including Northern Pass. And when we look at the shifts, there were some other shifts going the other way. In particular, we have refined our estimates to the Greater Hartford project and the Greater Boston project as well, which actually advanced some spending from what we thought previously. So the CapEx that we provided at the start of the year is still sort of valid from our perspective.

Our next question is from Steve Fleishman from Wolfe.

I may just more bluntly ask the same question. Just in terms of your targeted 6% to 8% growth rate, the move in Northern Pass, the potential shift of stuff, that growth rate is still good? No, this doesn't affect that at all?

Doesn't affect it at all. We're still comfortable with the long-range growth rate of 6% to 8% through 2018.

Is there a year-to-year issue that comes up from that? Or is it — are you thinking more back-ended than before?

That's the — As I say, we've had some shifting in terms of Northern Pass cash flows, but there have been shifts forward of other projects as we refined our estimates. So we continue to be very comfortable. We're more confident than ever, I would say, on the two projects, Northern Pass and Access Northeast, based upon the groundswell of support that we're getting, not only from governors but energy policymakers throughout the region. When you have customers now seeing in Massachusetts energy service rates of $0.15 a kilowatt hour, there's a lot of public reaction. And I think people realize that even if we move quickly here, these projects are not going to be solved next winter or the winter after that or the winter after that. But if we move quickly enough, we can get resolution of these problems in the '18, '19 winter. So I think there's more momentum for these projects than we've ever had. And who knows, there may be additional projects down the line that would further support our 6% to 8% growth rate going forward.

Next question is from Greg Gordon from Evercore again.

Okay. All right. Well, it looks like we don't have any more folks in the queue. If there's any follow-up questions, please give us a call. Thank you very much for joining us this morning.